SEC.UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended
MARCH 31,June 30, 2006or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
¨ 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: 1-12202
NORTHERN BORDERONEOK PARTNERS, L.P.
(Exact(Exact name of registrant as specified in its charter)
DELAWAREDelaware 93-1120873 (State(State or other jurisdiction of
(I.R.S. Employerincorporation or organization)
(IRS Employer
Identification
Number)No.)
13710 FNB PARKWAY OMAHA, NEBRASKA 68154-5200 (Address of principal executive offices) (Zip code)(402) 492-7300 (Registrant's100 West Fifth Street
Tulsa, Oklahoma
(Address of principal executive offices)
74103-4298
(Zip Code)
(918) 588-7000
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes
[X]x No[ ]¨Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of
"accelerated“accelerated filer and large acceleratedfiler"filer” in Rule 12b-2 of the ExchangeAct).Act. (Check one):Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ]
Large accelerated filerx
Accelerated filer¨ Non-accelerated filer¨ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
[ ]¨ No[X]xIndicate the number of shares outstanding of each of the
issuer'sissuer’s classes of common stock, as of the latest practicable date.
CLASS OUTSTANDING AT MAYClass
Outstanding at August 1, 2006
- ------------- --------------------------Common units 46,397,214 units Class B units 36,494,126 units NORTHERN BORDERONEOK PARTNERS,
L.P. AND SUBSIDIARIES QUARTERLY REPORT ON FORML.PQuarterly Report on Form 10-Q
TABLE OF CONTENTS
The statements in this
quarterly reportQuarterly Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-lookingstatements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.statements. Forward-looking statements may include words such as"anticipate," "estimate," "expect," "project," "intend," "plan," "believe," "should"“anticipate,” “estimate,” “plan,” “expect,” “project,” “intend,” “plan,” “believe,” “should” and other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that our goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements are describedin this quarterly reportunder Part II, Item 1A,"Risk“Risk Factors,"” in our Quarterly Reports and under Part I, Item 1A,"Risk“Risk Factors,"” in ourannual reportAnnual Report on Form 10-K for the year ended December 31, 2005.2GLOSSARYGlossary
The abbreviations, acronyms, and industry terminology used in this
quarterly reportQuarterly Report are defined as follows:
Bbl...........................Bbl
Barrels, equivalent to 42 United States gallons
Bbl/
d.........................dBarrels per day
BBtu/d
Billion British thermal units per day
Bcf/d
Billion cubic feet per day
Bear Paw
Energy...............EnergyBear Paw Energy, LLC
Bighorn Gas
Gathering.........GatheringBighorn Gas Gathering, L.L.C.
Black
Mesa....................MesaBlack Mesa Pipeline, Inc.
Btu
British thermal units
Crestone
Energy...............EnergyCrestone Energy Ventures, L.L.C.
EITF
Emerging Issues Task Force
Exchange
Act..................ActSecurities Exchange Act of 1934, as amended
FASB..........................FASB
Financial Accounting Standards Board
FERC..........................FERC
Federal Energy Regulatory Commission
Fort Union Gas
Gathering......GatheringFort Union Gas Gathering, L.L.C.
GAAP.......................... GenerallyGAAP
United States generally accepted accounting principles
Guardian
Pipeline.............PipelineGuardian Pipeline, L.L.C.
LIBOR
London Interbank Offered Rate
Lost Creek
Gathering..........GatheringLost Creek Gathering Company, L.L.C.
MBbl/d
Thousand barrels per day
Midwestern Gas
Transmission...TransmissionMidwestern Gas Transmission Company
MMBtu.........................MMBtu
Million British thermal units
MMBtu/d
Million British thermal units per day
MMcf
Million cubic feet
MMcf/
d........................dMillion cubic feet per day
NBP
Services..................ServicesNBP Services, LLC, a ONEOK subsidiary
NGL
Natural gas liquids
Northern Border
Pipeline......PipelineNorthern Border Pipeline Company
Northern Plains...............NYMEX
New York Mercantile Exchange
NYSE
New York Stock Exchange
ONEOK
ONEOK, Inc.
ONEOK NB
ONEOK NB Company, formerly known as Northwest Border Pipeline Company, a ONEOK subsidiary
ONEOK Partners GP
ONEOK Partners GP, L.L.C., formerly known as Northern Plains Natural Gas Company, LLC, a ONEOK subsidiary
Northwest Border.............. Northwest BorderOverland Pass Pipeline Company
a ONEOK subsidiary NYMEX......................... New York Mercantile Exchange NYSE.......................... New York Stock Exchange ONEOK......................... ONEOK, Inc. Partnership................... Northern Border Partners, L.P., Northern Border Intermediate Limited Partnership and its subsidiaries SEC...........................Overland Pass Pipeline Company LLC
SEC
Securities and Exchange Commission
SFAS..........................SFAS
Statement of Financial Accounting Standards
TC
PipeLines..................PipeLinesTC PipeLines Intermediate Limited Partnership, a subsidiary of TC PipeLines, LP
TransCanada...................TransCanada
TransCanada Corporation
Trunk gathering
system........systemLarge diameter pipeline running through a production area to which smaller individual gathering systems are connected
U.S........................... United StatesViking Gas
Transmission.......TransmissionViking Gas Transmission Company
3PART I
-– FINANCIAL INFORMATIONITEM 1. FINANCIAL STATEMENTS
NORTHERN BORDER PARTNERS,ONEOK Partners, L.P.
AND SUBSIDIARIESand SubsidiariesCONSOLIDATED
STATEMENTSTATEMENTS OF INCOME(UNAUDITED)
THREE MONTHS ENDED MARCH 31, ------------------- 2006 2005 -------- -------- (In thousands except per unit amounts)Operating revenue $170,799 $160,379 -------- -------- Operating expenses: Product purchases 44,021 32,465 Operations and maintenance 31,643 33,172 Depreciation and amortization 21,294 21,392 Taxes other than income 10,178 9,812 -------- -------- Operating expenses 107,136 96,841 -------- -------- Operating income 63,663 63,538 -------- -------- Interest expense 22,704 21,166 -------- -------- Other income (expense): Equity earnings in unconsolidated affiliates 6,163 4,477 Other income 950 741 Other expense (162) (223) -------- -------- Other income, net 6,951 4,995 -------- -------- Minority interest in net income 11,206 12,189 -------- -------- Income from continuing operations before income taxes 36,704 35,178 Income taxes 2,027 899 -------- -------- Income from continuing operations 34,677 34,279 Discontinued operations, net of tax 9 390 -------- -------- Net income to partners $ 34,686 $ 34,669 ======== ======== Calculation of limited partners' interest in net income: Net income to partners $ 34,686 $ 34,669 Less: General partners' interest in net income 3,822 2,683 -------- -------- Limited partners' interest in net income $ 30,864 $ 31,986 ======== ======== Limited partners' per unit net income: Income from continuing operations $ 0.67 $ 0.68 Discontinued operations, net of tax -- 0.01 -------- -------- Net income $ 0.67 $ 0.69 ======== ======== Number of units used in computation 46,397 46,397 ======== ========The
Three Months Ended
June 30,Six Months Ended
June 30,(Unaudited)
2006 2005 2006 2005 (Thousands of dollars, except per unit amounts) Operating revenue
$ 1,159,350 $ 149,417 $ 2,329,179 $ 309,796 Cost of sales and fuel
944,150 35,466 1,909,038 67,931 Net margin
215,200 113,951 420,141 241,865 Operating expenses:
Operations and maintenance
69,063 30,042 140,889 63,214 Depreciation and amortization (Note 7)
39,282 21,456 66,752 42,848 Taxes other than income
8,136 8,989 14,913 18,801 Total operating expenses
116,481 60,487 222,554 124,863 Gain on sale of assets
113,877 — 114,865 — Operating income
212,596 53,464 312,452 117,002 Interest expense, net
30,787 21,372 67,221 42,538 Other income (expense):
Equity earnings from investments
18,004 4,418 49,817 8,895 Other income
3,614 1,082 5,421 1,823 Other expense
(5,425 ) (234 ) (6,150 ) (457 ) Total other income, net
16,193 5,266 49,088 10,261 Minority interest in net income
519 8,629 2,138 20,818 Income from continuing operations before income taxes
197,483 28,729 292,181 63,907 Income taxes
1,284 997 25,478 1,896 Income from continuing operations
196,199 27,732 266,703 62,011 Discontinued operations, net of tax
— 358 — 748 Net income to partners
$ 196,199 $ 28,090 $ 266,703 $ 62,759 Limited partners’ interest in net income:
Net income to partners
$ 196,199 $ 28,090 $ 266,703 $ 62,759 General partners’ interest in net income
12,105 2,552 51,745 5,235 Limited partners’ interest in net income
$ 184,094 $ 25,538 $ 214,958 $ 57,524 Limited partners’ per unit net income:
Income from continuing operations
$ 2.22 $ 0.54 $ 3.33 $ 1.22 Discontinued operations, net of tax
— 0.01 — 0.02 Net income per unit
$ 2.22 $ 0.55 $ 3.33 $ 1.24 Number of units used in computation
82,891 46,397 64,644 46,397 See accompanying
notes are an integral part of these consolidated financial statements 4NORTHERN BORDER PARTNERS,Notes to Consolidated Financial Statements.ONEOK Partners, L.P.
AND SUBSIDIARIES CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (UNAUDITED)
THREE MONTHS ENDED MARCH 31, ----------------- 2006 2005 ------- ------- (In thousands)Net income to partners $34,686 $34,669 Other comprehensive income: Changes associated with current period hedging transactions 5,000 (2,725) Changes associated with current period foreign currency translation (4) (21) ------- ------- Total comprehensive income $39,682 $31,923 ======= =======The accompanying notes are an integral part of these consolidated financial statements. 5NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIESand SubsidiariesCONSOLIDATED BALANCE
SHEET (UNAUDITED)
MARCH 31, DECEMBER 31, 2006 2005 ---------- ------------ (In thousands)ASSETS Current assets: Cash and cash equivalents $ 18,730 $ 43,090 Accounts receivable, net of allowance for doubtful accounts of $18 at March 31, 2006, and December 31, 2005 64,832 82,848 Materials and supplies, at cost 7,543 7,273 Prepaid expenses and other 5,168 5,211 Derivative financial instruments 2,073 -- ---------- ---------- Total current assets 98,346 138,422 ---------- ---------- Property, plant and equipment: Interstate natural gas pipeline 2,677,529 2,668,645 Natural gas gathering and processing 289,188 284,199 Other 51,878 47,876 ---------- ---------- Total property, plant and equipment 3,018,595 3,000,720 Less: Accumulated provision for depreciation and amortization 1,102,751 1,082,210 ---------- ---------- Property, plant and equipment, net 1,915,844 1,918,510 ---------- ---------- Investments and other assets: Investment in unconsolidated affiliates 288,402 290,756 Goodwill 152,782 152,782 Regulatory assets 18,621 14,153 Other 14,363 13,143 ---------- ---------- Total investments and other assets 474,168 470,834 ---------- ---------- Total assets $2,488,358 $2,527,766 ========== ========== LIABILITIES AND PARTNERS' EQUITY Current liabilities: Current maturities of long-term debt $ 238,000 $ 233,194 Derivative financial instruments 1,264 4,571 Accounts payable 34,326 53,706 Accrued taxes other than income 31,819 33,081 Accrued interest 21,925 17,446 ---------- ---------- Total current liabilities 327,334 341,998 ---------- ---------- Long-term debt, net of current maturities 1,090,905 1,121,777 ---------- ---------- Minority interests in partners' equity 275,196 274,510 ---------- ---------- Reserves and deferred credits: Deferred income taxes 12,502 10,311 Derivative financial instruments 5,058 2,362 Regulatory liabilities 2,681 2,591 Other 9,317 8,628 ---------- ---------- Total reserves and deferred credits 29,558 23,892 ---------- ---------- Commitments and contingencies (Note 7) Partners' equity: General partners 18,375 17,341 Common units: 46,397,214 units issued and outstanding at March 31, 2006, and December 31, 2005 743,947 750,201 Accumulated other comprehensive income (loss) 3,043 (1,953) ---------- ---------- Total partners' equity 765,365 765,589 ---------- ---------- Total liabilities and partners' equity $2,488,358 $2,527,766 ========== ==========TheSHEETS
(Unaudited)
June 30,
2006December 31,
2005(Thousands of dollars) Assets
Current assets:
Cash and cash equivalents
$ 24,869 $ 43,090 Accounts receivable, net
416,076 82,848 Gas and natural gas liquids in storage and imbalances
247,920 — Commodity exchanges
203,187 — Materials and supplies
16,284 7,273 Derivative financial instruments
3,998 — Prepaid expenses and other
8,391 5,211 Total current assets
920,725 138,422 Property, plant and equipment:
Property, plant and equipment
3,299,795 3,000,720 Accumulated depreciation and amortization
621,568 1,082,210 Property, plant and equipment, net
2,678,227 1,918,510 Investments and other assets:
Investment in unconsolidated affiliates
756,053 290,756 Goodwill and intangibles
665,648 152,782 Other
19,838 27,296 Total investments and other assets
1,441,539 470,834 Total assets
$ 5,040,491 $ 2,527,766 Liabilities and Partners’ Equity
Current liabilities:
Current maturities of long-term debt
$ 11,931 $ 2,194 Notes payable
1,364,000 231,000 Derivative financial instruments
9,937 4,571 Accounts payable
390,713 46,673 Commodity exchanges
337,532 — Accrued taxes other than income
14,779 33,081 Accrued interest
10,237 17,446 Other
37,358 7,033 Total current liabilities
2,176,487 341,998 Long-term debt, net of current maturities
626,359 1,121,777 Minority interests in partners’ equity
5,548 274,510 Deferred credits and other liabilities:
Deferred income taxes
14,085 10,311 Derivative financial instruments
6,874 2,362 Other liabilities
28,252 11,219 Total deferred credits and other liabilities
49,211 23,892 Commitments and contingencies (Note 11)
Partners’ equity:
General partners
51,904 17,341 Common units: 46,397,214 units issued and outstanding at June 30, 2006, and December 31, 2005
802,559 750,201 Class B units: 36,494,126 units issued and outstanding at June 30, 2006
1,331,659 — Accumulated other comprehensive income (loss)
(3,236 ) (1,953 ) Total partners’ equity
2,182,886 765,589 Total liabilities and partners’ equity
$ 5,040,491 $ 2,527,766 See accompanying
notes are an integral part of these consolidated financial statements. 6NORTHERN BORDER PARTNERS,Notes to Consolidated Financial Statements.ONEOK Partners, L.P.
AND SUBSIDIARIESand SubsidiariesCONSOLIDATED
STATEMENTSTATEMENTS OF CASH FLOWS(Unaudited)
THREE MONTHS ENDED MARCH 31, -------------------- 2006 2005 --------- -------- (In thousands)CASH FLOW FROM OPERATING ACTIVITIES Net income to partners $ 34,686 $ 34,669 --------- -------- Adjustments to reconcile net income to partners to net cash provided by operating activities: Depreciation and amortization 21,386 21,482 Minority interests in net income 11,206 12,189 Reserves and deferred credits 689 (340) Equity earnings in unconsolidated affiliates (6,163) (4,477) Distributions received from unconsolidated affiliates 9,203 1,187 Changes in components of working capital 1,626 3,726 Non-cash losses (gains) from derivative financial instruments (21) 40 Other (2,398) (1,406) --------- -------- Total adjustments 35,528 32,401 --------- -------- Net cash provided by operating activities 70,214 67,070 --------- -------- CASH FLOW FROM INVESTING ACTIVITIES Investment in unconsolidated affiliates (605) (1,454) Capital expenditures for property, plant and equipment (17,806) (9,846) --------- -------- Net cash used in investing activities (18,411) (11,300) --------- -------- CASH FLOW FROM FINANCING ACTIVITIES Cash distributions: General and limited partners (39,906) (39,906) Minority interests (13,502) (16,229) Equity contributions from minority interests 3,099 -- Issuance of long-term debt 258,000 13,000 Debt reacquisition costs (3,628) -- Long-term debt financing costs (179) -- Retirement of long-term debt (280,047) (9,302) --------- -------- Net cash used in financing activities (76,163) (52,437) --------- -------- Net change in cash and cash equivalents (24,360) 3,333 Cash and cash equivalents at beginning of period 43,090 33,980 --------- -------- Cash and cash equivalents at end of period $ 18,730 $ 37,313 ========= ======== Supplemental disclosures of cash flow information: Cash paid for interest, net of amount capitalized $ 19,475 $ 16,294 ========= ======== Cash paid for income taxes $ 143 $ 151 ========= ======== Changes in components of working capital: Accounts receivable $ 18,016 $ 3,663 Materials and supplies, prepaid expenses and other (228) 877 Accounts payable (19,379) (6,492) Accrued taxes other than income (1,262) (401) Accrued interest 4,479 6,079 --------- -------- Total $ 1,626 $ 3,726 ========= ========The
Six Months Ended
June 30,
(Unaudited)
2006 2005 (Thousands of Dollars) Operating Activities
Net income to partners
$ 266,703 $ 62,759 Depreciation and amortization
66,752 43,023 Minority interests in net income
2,138 20,818 Equity earnings from investments
(49,817 ) (8,895 ) Distributions received from investments
69,819 2,653 Gain on sale of assets
(115,349 ) — Non-cash gains on derivative financial instruments
(3,842 ) (58 ) Changes in components of working capital (net of acquisition effects):
Accounts receivable
75,224 8,149 Commodity exchange receivable
(70,028 ) — Inventories, prepaid expenses and other
(16,250 ) (214 ) Accounts payable and other current liabilities
12,363 (9,182 ) Commodity exchange payable
103,043 — Accrued taxes other than income
(6,872 ) (4,850 ) Accrued interest
4,315 236 Other
4,365 (3,132 ) Cash provided by operating activities
342,564 111,307 Investing Activities
Investments in unconsolidated affiliates
(8,212 ) (1,454 ) Acquisitions
(1,438,485 ) — Proceeds from sale of assets
297,236 — Capital expenditures for property, plant and equipment
(53,575 ) (23,161 ) Increase in cash and cash equivalents for previously unconsolidated subsidiaries
7,496 — Decrease in cash and cash equivalents for previously consolidated subsidiaries
(22,039 ) — Cash used in investing activities
(1,217,579 ) (24,615 ) Financing Activities
Cash distributions:
General and limited partners
(84,761 ) (79,812 ) Minority interests
(147 ) (31,943 ) Cash flow retained by ONEOK (Note 1)
(176,978 ) — Debt reacquisition costs
(3,628 ) — Long-term debt financing costs
(179 ) (1,327 ) Retirement of long-term debt
(35,013 ) (2,653 ) Short-term note payable, net
1,157,500 7,000 Payments upon termination of derivatives
— (2,654 ) Cash provided by (used in) financing activities
856,794 (111,389 ) Change in cash and cash equivalents
(18,221 ) (24,697 ) Cash and cash equivalents at beginning of period
43,090 33,980 Cash and cash equivalents at end of period
$ 24,869 $ 9,283 Supplemental cash flow information:
Cash paid for interest, net of amount capitalized
$ 37,785 $ 44,341 See accompanying
notes are an integral part of these consolidated financial statements. 7NORTHERN BORDER PARTNERS,Notes to Consolidated Financial Statements.ONEOK Partners, L.P.
AND SUBSIDIARIESand SubsidiariesCONSOLIDATED
STATEMENTSTATEMENTS OF CHANGES INPARTNERS'PARTNERS’ EQUITY(UNAUDITED)
ACCUMULATED OTHER TOTAL GENERAL COMMON COMPREHENSIVE PARTNERS' PARTNERS UNITS INCOME (LOSS) EQUITY -------- -------- ------------- --------- (In thousands)Partners' equity at December 31, 2005 $17,341 $750,201 $(1,953) $765,589 Net income to partners 3,822 30,864 -- 34,686 Changes associated with current period hedging transactions -- -- 5,000 5,000 Changes associated with current period foreign currency translation -- -- (4) (4) Distribution to partners (2,788) (37,118) -- (39,906) ------- -------- ------- -------- Partners' equity at March 31, 2006 $18,375 $743,947 $ 3,043 $765,365 ======= ======== ======= ========TheAND COMPREHENSIVE INCOME
(Unaudited)
General
PartnersCommon
UnitsClass B
UnitsOther
Comprehensive
Income (Loss)Total
Partners’
Equity(Thousands of Dollars) Balance at December 31, 2005
$ 17,341 $ 750,201 $ — $ (1,953 ) $ 765,589 Net income to partners
51,745 130,306 84,652 — 266,703 Other comprehensive income (loss)
(1,283 ) (1,283 ) Total comprehensive income
265,420 Net income retained by ONEOK (Note 1)
(35,818 ) — — — (35,818 ) Issuance of 36,494,126 Class B units and contribution from general partners
25,449 — 1,247,007 — 1,272,456 Distributions paid
(6,813 ) (77,948 ) — — (84,761 ) Balance at June 30, 2006
$ 51,904 $ 802,559 $ 1,331,659 $ (3,236 ) $ 2,182,886 See accompanying
notes are an integral part of these consolidated financial statements. 8NORTHERN BORDER PARTNERS,Notes to Consolidated Financial Statements.ONEOK Partners, L.P.
AND SUBSIDIARIESand SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
BASIS OF PRESENTATIONORGANIZATION AND MANAGEMENTIn this report, references to
"we," "us," "our"“we,” “us,” “our” or the"Partnership" collectively“Partnership” refer to ONEOK Partners, L.P. and its subsidiary, ONEOK Partners Intermediate Limited Partnership and subsidiaries, formerly known as Northern Border Partners, L.P. andour subsidiary,Northern Border Intermediate Limited Partnership, respectively.ONEOK Partners, L.P. is a publicly traded Delaware limited partnership that was formed in 1993. Our common units are listed on the NYSE under the trading symbol “OKS.”
ONEOK Partners, L.P. Amended and Restated Partnership Agreement – In May 2006, our sole general partner, ONEOK Partners GP, entered into a Second Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P. (MLP Partnership Agreement) to amend and restate our previously existing partnership agreement, the principal differences of which are as follows. The MLP Partnership Agreement:
changes the name of Northern Border Partners, L.P. to ONEOK Partners, L.P.;provides that we are managed by our sole general partner, ONEOK Partners GP;replaces our previously existing Partnership Policy Committee and Audit Committee with the Board of Directors, Audit Committee and Conflicts Committee of ONEOK Partners GP;separates the functions of the Audit Committee, which will be a standing committee of the Board of Directors of ONEOK Partners GP, and the Conflicts Committee, which will not be a standing committee of the Board of Directors of ONEOK Partners GP;expands our “purpose” clause to encompass midstream business activities as well as other activities permitted by applicable law;incorporates Amendment No. 1 to our previously existing partnership agreement, the provisions of which are described in our Current Report on Form 8-K filed on April 12, 2006;removes obsolete provisions of the previously existing partnership agreement; andmodifies the form of common unit certificate to reflect the new name of the partnership and related matters.ONEOK Partners Intermediate Limited Partnership Amended and Restated Partnership Agreement– In May 2006, the sole general partner of ONEOK Partners Intermediate Limited Partnership (ILP), ONEOK Partners GP, and we, the sole limited partner of ILP, entered into a Second Amended and Restated Agreement of Limited Partnership of ONEOK Partners Intermediate Limited Partnership (ILP Partnership Agreement) to amend and restate the previously existing partnership agreement, the principal differences of which are as follows. The ILP Partnership Agreement:
changes the name of Northern Border Intermediate Limited Partnership to ONEOK Partners Intermediate Limited Partnership;provides that ILP will be managed by its sole general partner, ONEOK Partners GP;replaces its previously existing Partnership Policy Committee and Audit Committee with the Board of Directors and Audit Committee of ONEOK Partners GP; andremoves obsolete provisions of the previously existing partnership agreement.ONEOK Partners GP, the sole general partner of us and the sole general partner of the ILP, is a wholly owned subsidiary of ONEOK. ONEOK Partners GP and its
subsidiaries.affiliates own an approximate 45.7 percent interest in us.2. ACQUISITIONS AND DIVESTITURES
The ONEOK Transactions– In April 2006, we completed the acquisition of certain companies comprising ONEOK’s former Gathering and Processing, Natural Gas Liquids and Pipelines and Storage segments, collectively referred to as the “ONEOK Energy Assets,” and several related transactions, which are collectively referred to as the “ONEOK Transactions.” As part of the ONEOK Transactions, ONEOK acquired ONEOK NB, formerly known as Northwest Border Pipeline Company, an affiliate of TransCanada that held a 0.35 percent general partner interest in us, under a Purchase and Sale Agreement between an affiliate of ONEOK and an affiliate of TransCanada. As a result, ONEOK owns our entire two percent general partner interest.
We acquired the ONEOK Energy Assets for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. ONEOK now owns approximately 37.0 million of our limited partner units, which when combined with its general partner interest, increases its total interest in us to 45.7 percent. We used $1.05 billion drawn under a $1.1 billion, 364-day credit agreement (Bridge Facility), coupled with the proceeds from the sale of a 20 percent partnership interest in Northern Border Pipeline, to finance the transaction.
In June 2005, the FASB ratified the consensus reached in EITF Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights” (EITF 04-5). EITF 04-5 presumes that a general partner controls a limited partnership and therefore should consolidate the partnership in the financial statements of the general partner. Our Partnership Agreement provides for the right to replace the general partner by a vote of greater than a simple majority of the limited partner interests not held by the general partner and, accordingly, under the guidance in EITF 04-5, ONEOK is deemed to have control for accounting purposes. ONEOK elected to use the prospective method and began to consolidate our operations in their consolidated financial statements as of January 1, 2006. As ONEOK is deemed to control us under the requirements of EITF 04-5, the ONEOK Transactions are accounted for as a transaction between entities under common control and the transaction is excluded from the accounting indicated by SFAS No. 141, “Business Combinations.” Accordingly, ONEOK’s historical cost basis in the ONEOK Energy Assets is transferred to us in a manner similar to a pooling of interests. The difference between the historical cost basis of the net assets acquired of $2.7 billion and the cash paid has been assigned to the value of the Class B limited partner units issued to ONEOK and their general partner interest in us. These assets and their related operations are included in our consolidated financial statements as of January 1, 2006. The following table shows the impact to our consolidated balance sheet for the ONEOK Energy Assets as of December 31, 2005:
ONEOK Energy Assets
December 31, 2005 (Thousands of dollars) Assets
Current assets
$ 769,808 Property, plant and equipment, net
1,997,397 Goodwill and intangibles
513,904 Investments and other
71,983 Total assets
$ 3,353,092 Liabilities
Accounts payable
$ 353,997 Other current liabilities
278,092 Other deferred credits
21,095 Total liabilities
$ 653,184 Net assets acquired
$ 2,699,908 Since the ONEOK Transactions were not completed until April 2006, the income and cash flow from the ONEOK Energy Assets for the first quarter of 2006 were retained by ONEOK. In our consolidated statements of cash flows, we reported cash flow retained by ONEOK of $177.0 million, which represents the cash flows generated from these companies while they were owned by ONEOK. The following table shows the impact to our consolidated statements of income for the ONEOK Energy Assets prior to our acquisition:
ONEOK Energy Assets
Three Months Ended
March 31, 2006(Thousands of dollars) Operating revenue
$ 1,162,571 Cost of sales and fuel
1,013,851 Net margin
148,720 Operating expenses:
Operations and maintenance
47,530 Depreciation and amortization
19,277 Taxes other than income
4,407 Total operating expenses
71,214 Operating income
77,506 Interest expense
21,281 Other income, net
1,760 Income from continuing operations before income taxes
57,985 Income taxes
22,167 Net income to partners
$ 35,818 Limited partners’ interest in net income:
Net income to partners
$ 35,818 General partner interest in net income
(35,818 ) Limited partners’ interest in net income
$ — Prior to the acquisition, the ONEOK Energy Assets were included in the consolidated state and federal income tax returns of ONEOK and, accordingly, current taxes payable were allocated to the ONEOK Energy Assets based on ONEOK’s effective rate. Income tax liabilities and provisions for income tax expense for the ONEOK Energy Assets, as presented herein, were calculated on a stand-alone basis. Our consolidated statement of income for the six months ended June 30, 2006, includes income tax expense recorded by ONEOK Energy Assets of $22.2 million for the first quarter of 2006. In conjunction with the ONEOK Transactions, all income tax liabilities of ONEOK Energy Assets were retained by ONEOK.
Income from the ONEOK Energy Assets for the first quarter of 2006 also reflects interest expense of $21.3 million which represents interest charged on long-term debt owed to ONEOK. The interest rate on the debt was calculated periodically based upon ONEOK’s weighted average cost of debt. This debt was retained by ONEOK as part of the ONEOK Transactions.
In June 2006, we recorded a $63.2 million purchase price adjustment related to a working capital settlement under the terms of the ONEOK Transactions. The working capital settlement is reflected as an increase to the value of the Class B units and a receivable from ONEOK in our consolidated balance sheet. The working capital settlement has not been finalized; however, we do not expect material adjustments.
The unaudited pro forma information in the table below presents a summary of our results of operations as if the acquisition of the ONEOK Energy Assets had occurred at the beginning of the periods presented. The results do not necessarily reflect the results that would have been obtained if the acquisition of the ONEOK Energy Assets had actually occurred on the dates indicated or results that may be expected in the future.
Pro Forma
Three Months Ended
June 30, 2005Pro Forma
Six Months Ended
June 30, 2005(Thousands of dollars) Revenue
$ 669,128 $ 1,349,209 Income from continuing operations
$ 64,129 $ 132,172 Net income per unit
$ 0.72 $ 1.49 The units issued to ONEOK are a newly created Class B limited partner unit with the same distribution rights as the outstanding common units, but have limited voting rights and are subordinated related to cash distributions to the common units. Distributions on the Class B units will be prorated from the date of issuance. We will hold a special election for holders of common units as soon as practical but within 12 months, subject to extension, of issuing the Class B units, to approve the conversion of the Class B units into common units and to approve certain amendments to our partnership agreement. The proposed amendments would grant voting rights for common units held by the general partner if a vote is held to remove the general partner and require fair market value compensation for the general partner interest. If the common unit holders do not approve the conversion and amendments, the Class B unit distribution rights will increase to 115 percent of the distributions paid on the common units. If the conversion and the amendments are approved by the common unitholders, the Class B units will be eligible to convert into common units on a one-for-one basis. If the common unit holders vote to remove ONEOK or its affiliates as our general partner at any time prior to the approval of the conversion and certain amendments to our partnership agreement, the Class B units distribution rights would continue to be subordinated in the manner described above unless and until the conversion described above has been approved, at which time the amount payable on such Class B units would increase to 125 percent of the distributions payable with respect to the common units.
Disposition of 20 Percent Partnership Interest in Northern Border Pipeline –In April 2006, we completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million. We recorded a gain on the sale of approximately $113.9 million in the second quarter of 2006. We and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline, and an affiliate of TransCanada will become the operator of the pipeline effective April 1, 2007. Under SFAS No. 94, “Consolidation of All Majority Owned Subsidiaries,” a majority-owned subsidiary shall not be consolidated if control is likely to be temporary or if it does not rest with the majority owner. Neither we nor TC PipeLines will have control of Northern Border Pipeline, as control will be shared equally through Northern Border Pipeline’s Management Committee. We are no longer consolidating Northern Border Pipeline as of January 1, 2006, the effective date of the sale. The amounts we previously reported as assets, liabilities and equity associated with Northern Border Pipeline were reclassified as an investment under the equity method.
The following table shows the reconciliation of our investment in Northern Border Pipeline at December 31, 2005:
Northern Border Pipeline
December 31, 2005 (Thousands of dollars) Assets
Current assets
$ 67,691 Property, plant and equipment, net
1,516,075 Investments and other
20,932 Total assets reclassified
$ 1,604,698 Liabilities and Equity
Accounts payable
$ 14,104 Other current liabilities
68,917 Other deferred credits
4,775 Long-term debt
601,916 Total liabilities
689,712 Minority interests in partners’ equity
274,496 Accumulated other comprehensive income
1,584 Total liabilities and equity reclassified
$ 965,792 Total investment
$ 638,906 Acquisition of Guardian Pipeline Interests –In April 2006, we acquired a 66 2/3 percent interest in Guardian Pipeline for approximately $77 million increasing our ownership to 100 percent. We used borrowings from our credit facility to fund the acquisition of the additional interest in Guardian Pipeline. Following the completion of the transaction, we consolidated Guardian Pipeline in our financial statements. This change was retroactive to January 1, 2006. Prior to the transaction, our 33 1/3 percent interest in Guardian Pipeline was accounted for as an investment under the equity method.
Overland Pass Natural Gas Liquids Pipeline Joint Venture –In May 2006, we entered into an agreement with a subsidiary of The Williams Companies, Inc. (Williams) to form a joint venture called Overland Pass Pipeline Company. Overland Pass Pipeline Company will build a 750-mile natural gas liquids pipeline from Opal, Wyoming to the Midcontinent natural gas liquids market center in Conway, Kansas. The pipeline will be designed to transport approximately 110,000 Bbl/d of natural gas liquids, which can be increased to approximately 150,000 Bbl/d with additional pump facilities. As the 99 percent owner of the joint venture, we will manage the construction project, advance all costs associated with construction and operate the pipeline. Williams will have the option to increase its ownership up to 50 percent by reimbursing us for our proportionate share of all construction costs and, upon full exercise of that option, would become operator within two years of the pipeline becoming operational. Construction of the pipeline is expected to begin in the summer of 2007, with start up scheduled for early 2008. As part of a long-term agreement, Williams dedicated its natural gas liquids production from two of its gas processing plants in Wyoming to the joint-venture company. We will provide downstream fractionation, storage and transportation services to Williams. The pipeline project is estimated to cost approximately $433 million. At the project’s inception, we paid $11.4 million to Williams for initial capital expenditures incurred. In addition, we plan to invest approximately $173 million to expand our existing fractionation capabilities and the capacity of our natural gas liquids distribution pipelines. Financing for both projects may include a combination of short- or long-term debt or equity. The project requires the approval of various state and regulatory authorities.
3. SUMMARY OF ACCOUNTING POLICIES
We prepared the consolidated financial statements included
hereinin this Quarterly Report on Form 10-Q without audit pursuant to the rules and regulations of theSecurities and Exchange Commission.SEC. The consolidated financial statements reflect all normal and recurring adjustments that are, in the opinion of management, necessary for a fair presentation of the financial results for the interim periods presented. Certain information and notes normally included in financial statements prepared in accordance withU.S. generally accepted accounting principles (U.S. GAAP)GAAP are condensed or omitted pursuant to such rules and regulations. However, we believe that the disclosures are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with the consolidated audited financial statements and the notes thereto included in ourannual reportAnnual Report on Form 10-K for the year ended December 31, 2005.The preparation of financial statements in conformity with
U.S.GAAP requires management to make assumptions and use estimates that affect the reported amount of the assets, liabilities, revenue and expenses as well as the disclosure of contingent assets and liabilities during the reporting period. Actual results could differ from these estimates if the underlying assumptions are incorrect.At MarchExcept as described below, our accounting polices are consistent with those disclosed in Note 2 of the consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31,
2006, we owned a 70% general partner interest in Northern Border Pipeline Company (see Note 9-Subsequent Events). Our significant wholly owned subsidiaries are: Crestone Energy Ventures, L.L.C.; Bear Paw Energy, LLC; Midwestern Gas Transmission Company; Viking Gas Transmission Company; and Black Mesa Pipeline, Inc. We also own a 49% common membership interest in Bighorn Gas Gathering, L.L.C.; a 37% interest in Fort Union Gas Gathering, L.L.C.; a 35% interest in Lost Creek Gathering Company, L.L.C.; and a 33-1/3% interest in Guardian Pipeline, L.L.C. (see Note 9-Subsequent Events).2005.Reclassifications–Certain reclassifications
werehave been made to the 2005 financial statements to conform to the current year presentation.2.Such reclassifications did not have an impact on previously reported net income or partners’ equity.Inventories –Inventories are valued at the lower of cost or market. The values of current natural gas and natural gas liquids in storage are determined using the weighted average cost method. Noncurrent natural gas in storage is classified as property and valued at cost. Materials and supplies are valued at average cost.
Derivatives and Risk Management Activities –We use financial instruments in the management of our interest rate and commodity price exposure. A control environment has been established which includes policies and procedures for risk assessment and the approval, reporting and monitoring of financial instrument activities. We do not use these instruments for trading purposes. SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), as amended by SFAS No. 137 and SFAS No. 138, requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. Many of the purchase and sale agreements that otherwise would have been required to follow derivative accounting qualify as normal purchases and normal sales under SFAS No. 133 and are therefore exempt from fair value accounting treatment.
We determine the fair value of a derivative instrument by the present value of its future cash flows based on market prices from third party sources. We record changes in the derivative’s fair value in the current period earnings unless we elect hedge accounting at inception and specific hedge accounting criteria are met. Accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the income statement, and requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Commodity price volatility may have a significant impact on the gain or loss in any given period.
To minimize the risk of price fluctuations, we periodically enter into futures transactions, collars and swaps in order to hedge anticipated purchases and sales of natural gas, condensate and natural gas liquids. Under certain conditions, we designate these derivative instruments as a hedge of exposure to changes in cash flow. For hedges of exposure to changes in cash flow, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive income and subsequently reclassified into earnings when the forecasted transaction affects earnings. Any ineffectiveness of designated hedges is reported in earnings in the period the ineffectiveness occurs.
Property –The following table sets forth our property, by segment, for the periods presented.
June 30,
2006
December 31,
2005
(Thousands of dollars) Gathering and Processing
$ 1,073,583 $ 284,199 Natural Gas Liquids
505,812 — Pipelines and Storage
1,176,325 — Interstate Natural Gas Pipelines
491,883 2,668,645 Other
52,192 47,876 Property, plant and equipment
3,299,795 3,000,720 Accumulated depreciation and amortization
621,568 1,082,210 Net property, plant and equipment
$ 2,678,227 $ 1,918,510 Environmental Expenditures –We accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remediation feasibility study. Such accruals are adjusted as further information becomes available or circumstances change. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.
Revenue Recognition –We recognize revenue when services are rendered or product is delivered. The Gathering and Processing segment records operating revenue when gas is processed in or transported through company facilities. Operating revenue of the Gathering and Processing segment is derived from percent-of-proceeds, keep-whole and fee-based contracts. Operating revenue for our Interstate Natural Gas Pipelines segment is recognized based upon contracted capacity and actual volumes transported under transportation service agreements.
Regulation –Our intrastate natural gas transmission pipelines are subject to the rate regulation and accounting requirements of the Oklahoma Corporation Commission, Kansas Corporation Commission and Texas Railroad Commission. Our interstate natural gas pipelines and natural gas liquids pipelines are subject to regulation by the FERC. Our Interstate Natural Gas Pipelines segment and portions of our Pipelines and Storage segment follow the accounting and reporting guidance contained in SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). During the rate-making process, regulatory authorities may require us to defer recognition of certain costs to be recovered through rates over time as opposed to expensing such costs as incurred. This allows us to stabilize rates over time rather than passing such costs on to the customer for immediate recovery. Accordingly, actions by regulatory authorities could have an effect on the amount recovered from rate payers. Any difference in the amount recoverable and the amount deferred is recorded as income or expense at the time of the regulatory action. If all or a portion of the regulated operations are no longer subject to the provisions of SFAS No. 71, a write-off of regulatory assets and stranded costs may be required.
At June 30, 2006, we had regulatory assets in the amount of $8.3 million included in other assets on our consolidated balance sheet. Regulatory assets are being recovered as a result of approved rate proceedings over various time periods.
Income Taxes–We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of our net assets for financial and income tax purposes cannot be readily determined as we do not have access to all information about each partner’s tax attributes related to us.
Our corporate subsidiaries are required to pay federal and state income taxes. Income taxes are accounted for under the asset and liability method. Deferred income tax assets and liabilities are recognized by these entities for the future tax consequences attributable to differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases and operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Except for the companies whose accounting policies conform to SFAS No. 71, the effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. For the companies whose accounting policies conform to SFAS No. 71, the effect on deferred tax assets and liabilities of a change in tax rates is recorded as regulatory assets and regulatory liabilities in the period that includes the enactment date.
4. CREDIT FACILITIES
AND LONG-TERM DEBTIn March 2006, we entered into a five-year $750 million amended and restated revolving credit agreement (2006 Partnership Credit Agreement) with certain financial institutions and terminated our $500 million revolving credit agreement.
TheAt June 30, 2006, we had borrowings of $311 million and a $15 million letter of credit outstanding under the 2006 Partnership Credit Agreement at a weighted average interest rateon amounts outstanding under these agreements during the first quarterof2006 was 5.40%. On March 31, 2006, Viking Gas Transmission redeemed its four series of senior notes outstanding. In connection with the redemption, Viking Gas Transmission paid a premium of $3.6 million. The net loss from the redemption, including unamortized debt costs associated with the debt, will be amortized to interest expense over the remaining life of the Viking Gas Transmission senior notes. At March 31, 2006, the unamortized loss on reacquired debt was $3.8 million and is included in regulatory assets on the consolidated balance sheet. 3. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES We utilize financial instruments to reduce our market risk exposure to interest rate and commodity price fluctuations and achieve a more predictable cash flow. We follow established policies and procedures to assess risk and approve, monitor and report our financial instrument activities. We do not use these instruments for trading purposes. We record in accumulated other comprehensive income amounts related to terminated interest rate swap agreements for cash flow hedges and amortize these amounts to interest expense over the term of the hedged debt. During the three months ended March 31, 2006, we amortized approximately $0.4 million related to the terminated interest rate 9swap agreements as a reduction to interest expense from accumulated other comprehensive income. We expect to amortize approximately $0.2 million in each of the remaining quarters of 2006. Our outstanding interest rate swap agreements, with notional amounts totaling $150 million, expire in March 2011. Under these agreements, we make payments to counterparties at variable rates based on the London Interbank Offered Rate and receive payments based on a 7.10% fixed rate. As of March 31, 2006, the average effective interest rate on our interest rate swap agreements was 7.62%. Our interest rate swap agreements are designated as fair value hedges as they hedge the fluctuations in the market value of the senior notes issued by us in 2001. As of March 31, 2006, the accompanying consolidated balance sheet reflects long-term derivative financial liabilities of $5.1 million with a decrease in long-term debt related to our fair value hedges. We record in long-term debt amounts received or paid related to terminated or amended interest rate swap agreements for fair value hedges and amortize these amounts to interest expense over the remaining life of the interest rate swap agreement. During the three months ended March 31, 2006, we amortized approximately $1.3 million as a reduction to interest expense and expect to amortize approximately $0.8 million in each of the remaining quarters of 2006. Bear Paw Energy periodically enters into commodity derivative contracts and fixed-price physical contracts. Bear Paw Energy primarily utilizes price swaps, which are designated as cash flow hedges, to hedge its exposure to natural gas and natural gas liquids price volatility. During the three months ended March 31, 2006, Bear Paw Energy recognized gains of $0.8 million from the settlement of derivative contracts. As of March 31, 2006, the consolidated balance sheet reflected an unrealized loss of approximately $1.3 million in current derivative financial instrument liabilities and an unrealized gain of approximately $2.1 million in current derivative financial instrument assets. If prices remain at current levels, Bear Paw Energy expects to reclassify approximately $0.3 million, $0.2 million and $0.3 million from accumulated other comprehensive income as an increase to operating revenue in the second, third and fourth quarters of 2006, respectively. However, this increase would be offset with decreased operating revenue due to the lower prices assumed. 4. BUSINESS SEGMENT INFORMATION Our business is divided into two reportable segments, defined as components of the enterprise about which financial information is available and evaluated regularly by our management and the Partnership Policy Committee. Our reportable segments are strategic business units that offer different services. Each segment is managed separately because each business requires a different marketing strategy. These segments are as follows: the Interstate Natural Gas Pipeline segment, which provides interstate natural gas transportation services, and the Natural Gas Gathering and Processing segment, which provides services for the gathering, treating, processing and compression of natural gas and the fractionation of natural gas liquids. 10BUSINESS SEGMENT DATA
INTERSTATE NATURAL GAS THREE MONTHS ENDED NATURAL GAS GATHERING AND MARCH 31, 2006 PIPELINE PROCESSING OTHER (a) TOTAL - ------------------ ----------- ------------- --------- -------- (In thousands)Revenue from external customers $95,642 $73,513 $ 1,644 $170,799 Operating income (loss) 55,325 13,991 (5,653) 63,663 EBITDA 73,193 23,876 (5,303) 91,766
THREE MONTHS ENDED MARCH 31, 2005 - ------------------Revenue from external customers $96,645 $57,573 $ 6,161 $160,379 Operating income (loss) 55,638 9,502 (1,602) 63,538 EBITDA 72,823 17,706 143 90,672(a) Includes other items not allocable to segments. In 2005, our coal slurry operation was shown as a separate reportable segment. Our coal slurry transportation contract was terminated at December 31, 2005, therefore our coal slurry business is included in Other. TOTAL ASSETS BY SEGMENT
MARCH 31, DECEMBER 31, 2006 2005 ---------- ------------ (In thousands)Interstate natural gas pipeline $1,873,387 $1,888,980 Natural gas gathering and processing 589,143 594,379 Other (a) 25,828 44,407 ---------- ---------- Total assets $2,488,358 $2,527,766 ========== ==========(a) Includes other items not allocable to segments. We evaluate performance based on EBITDA (earnings before interest, taxes, depreciation and amortization and allowance for equity funds used during construction (AFUDC)). Management uses EBITDA to compare the financial performance of our segments and to internally manage those business segments. Management believes that EBITDA provides useful information to investors as a measure of comparability to peer companies. EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with U.S. GAAP. EBITDA calculations may vary from company to company; therefore our computation of EBITDA may not be comparable to a similarly titled measure of another company. 11RECONCILIATION OF NET INCOME (LOSS) TO EBITDA
INTERSTATE NATURAL GAS THREE MONTHS ENDED NATURAL GAS GATHERING AND MARCH 31, 2006 PIPELINE PROCESSING OTHER (a) TOTAL - ------------------ ----------- ------------- --------- ------- (In thousands)Net income (loss) $31,920 $19,565 $(16,799) $34,686 Minority interest 11,206 -- -- 11,206 Interest expense, net 11,249 (2) 11,457 22,704 Depreciation and amortization 16,908 4,306 172 21,386 Income tax 2,157 7 (133) 2,031 AFUDC (247) -- -- (247) ------- ------- -------- ------- EBITDA $73,193 $23,876 $ (5,303) $91,766 ======= ======= ======== =======
THREE MONTHS ENDED MARCH 31, 2005 - ------------------Net income (loss) $32,149 $13,690 $(11,170) $34,669 Minority interest 12,189 -- -- 12,189 Interest expense, net 11,204 54 9,908 21,166 Depreciation and amortization 16,569 3,958 955 21,482 Income tax 730 4 450 1,184 AFUDC (18) -- -- (18) ------- ------- -------- ------- EBITDA $72,823 $17,706 $ 143 $90,672 ======= ======= ======== =======(a) Includes other items not allocable to segments. 5. NET INCOME PER UNIT Net income per unit is computed by dividing net income, after deduction of the general partners' allocation, by the weighted average number of outstanding common units. The general partners' allocation is equal to an amount based upon their collective 2% general partner interest, adjusted for incentive distributions. The incentive distribution allocated to the general partners totaled $3.1 million for the first quarter of 2006, which will be paid to the general partners during the second quarter. The amount of distribution to partners shown on the accompanying consolidated statement of changes in partners' equity included incentive distributions paid to the general partners in the first quarter of 2006 of approximately $2.0 million. On April 18, 2006, we declared a cash distribution of $0.88 per unit ($3.52 per unit on an annualized basis) for the first quarter ended March 31, 2006. The distribution is payable on May 15, 2006, to unitholders of record on April 28, 2006. 6. RATES AND REGULATORY ISSUES As required by the provisions of the settlement of Northern Border Pipeline's last rate case, on November 1, 2005, we filed a rate case with the Federal Energy Regulatory Commission (FERC). In December 2005, the FERC issued an order that identified issues that were raised in the proceeding, accepted the proposed rates but suspended their effectiveness until May 1, 2006, at which time the new rates will be collected subject to refund until final resolution of the rate case. Information about our regulatory proceedings is included in Note 6 of the Financial Statements in our annual report on Form 10-K for the year ended December 31, 2005. 127. COMMITMENTS AND CONTINGENCIES BLACK MESA On December 31, 2005, we shut down our coal slurry pipeline operation. The Mohave Generating Station co-owners, Navajo Nation, Hopi Tribe, Peabody Western Coal Company and other interested parties continue to negotiate water source and coal supply issues and Black Mesa is working to resolve coal slurry transportation issues so that operations may resume in the future. If there are successful resolutions of these issues and the project receives a favorable Environmental Impact Statement, Black Mesa will reconstruct the coal slurry pipeline in late 2008 and 2009 for an anticipated in service date during 2010. If the pipeline is reconstructed, we anticipate Black Mesa's capital expenditures for the project will be in the range of $175 million to $200 million, supported by revenue from a new transportation contract. If the Mohave Generating Station is permanently closed, we expect to incur pipeline removal and remediation costs of approximately $1 million to $2 million, net of salvage, and a non-cash impairment charge of approximately $10 million related to the remaining undepreciated cost of the pipeline assets and goodwill. We expect to incur approximately $2 million to $4 million of operations and maintenance expense in 2006 primarily related to employee standby costs. Negotiations continue with various parties that may result in recovery of some of these standby costs. We may be required to take an impairment charge in accordance with Statement of Financial Accounting Standards (SFAS) No. 142 and SFAS No. 144 prior to final resolution of the issues concerning the Mohave Generating Station even though the project may ultimately proceed. LEGAL PROCEEDINGS Various legal actions that have arisen in the ordinary course of business are pending. We believe that the resolution of these issues will not have a material adverse impact on our results of operations or financial position. ENVIRONMENTAL LIABILITIES We are subject to federal, state and local environmental laws and regulations. Also, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies could result in substantial costs and liabilities to us. 8. ACCOUNTING PRONOUNCEMENTS In December 2004, the Financial Accounting Standards Board issued SFAS No. 123R, "Share-Based Payment," which requires companies to expense the fair value of share-based payments and includes changes related to the expense calculation for share-based payments. Northern Plains and NBP Services adopted SFAS No. 123R as of January 1, 2006, and will charge us for our proportionate share of the expense recorded by Northern Plains and NBP Services. The impact of adopting SFAS No. 123R does not have a material impact on our results of operations or financial position. 9. SUBSEQUENT EVENTS ONEOK TRANSACTIONS5.75 percent.In April
2006, under the Contribution Agreement, we acquired all of ONEOK's gathering and processing and pipelines and storage assets for approximately 36.5 million Class B units. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. The assets will be recorded at historical cost rather than at fair value since these transactions were between affiliates under common control. ONEOK now owns approximately 37.0 million of our limited partner units, which when combined with its general partner interest, increases its total interest in us to 45.7%. Under the ONEOK Purchase and Sale Agreement, we purchased all of ONEOK's natural gas liquids assets for $1.35 billion in cash. We used $1.05 billion drawn under the Bridge Facility, coupled with the proceeds from the sale of the 20% partnership interest in Northern Border Pipeline Company, to finance the transaction. 13DISPOSITION OF 20% INTEREST IN NORTHERN BORDER PIPELINE In April 2006, under the Partnership Interest Purchase and Sale Agreement dated as of December 31, 2005, we completed the sale of a 20% partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million. We and TC PipeLines each now own a 50% interest in Northern Border Pipeline, with an affiliate of TransCanada becoming operator of the pipeline effective April 1, 2007. Beginning in the second quarter, we will no longer consolidate Northern Border Pipeline, effective as of January 1, 2006. Instead, our ownership of Northern Border Pipeline will be reported as investment in unconsolidated affiliates on our balance sheet. Our share of Northern Border Pipeline's operating results will be reported as equity earnings in unconsolidated affiliates on our statement of income. BRIDGE FACILITY On April 6,2006, we entered into a $1.1 billion 364-day credit agreement (Bridge Facility) with a syndicate of banks and borrowed $1.05 billion tocompletefinance a portion of the acquisition of the ONEOKTransactions. Until May 6, 2006, we can make one additional borrowingEnergy Assets. Amounts outstanding under the Bridge Facilityof up to $50 million for purposes of making payments related to the ONEOK Transactions. Additionally, wemust be repaid on or before April 5, 2007. We must make mandatory prepayments on any outstanding balance under this credit facility with the net cash proceeds of any asset disposition in excess of $10 million or from the net cash proceeds received from any issuance of equity orofdebt having a term greater than one year.Amounts outstanding under the Bridge Facility must be repaid on or before April 5, 2007.The interest rate applied to amounts outstanding under the Bridge Facility may, at our option, be thelender'slender’s base rate or an adjustedLondon Interbank Offered RateLIBOR plus a spread that is baseduponon our long-term unsecured debt ratings. At June 30, 2006, the weighted average interest rate for borrowings under the Bridge Facility was 5.67 percent.Under the 2006 Partnership Credit Agreement and the Bridge Facility, we are required to comply with certain financial, operational and legal covenants. Among other things, we are required to maintain a ratio of EBITDA (net income plus minority interests in net income, interest expense, income taxes and depreciation and amortization) to interest expense of greater than 3 to 1. We are also required to maintain a ratio of indebtedness to adjusted EBITDA (EBITDA adjusted for pro forma operating results of acquisitions made during the year) of no more than 4.75 to 1. If we consummate one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will be
temporarilyincreased to 5.25 to 1 for two calendar quarters following the acquisition. Upon any breach of these covenants, amounts outstanding under the 2006 Partnership Credit Agreement and the Bridge Facility may become immediately due and payable. At June 30, 2006, we were in compliance with these covenants.The acquisition of an additional 66 2/3 percent interest in Guardian Pipeline resulted in the inclusion of outstanding amounts under Guardian Pipeline’s revolving note agreement in our consolidated balance sheet. The revolving note agreement permits Guardian Pipeline to choose rates based on the prime commercial lending rate or LIBOR as the interest rate on its outstanding borrowings, specify the portion of the borrowings to be covered by specific interest rate options and specify the interest rate period. At June 30, 2006, Guardian Pipeline had $3.0 million outstanding under its $10 million revolving note agreement at an interest rate of 6.60 percent, due November 8, 2007.
5. LONG-TERM DEBT
In March 2006, we borrowed $33 million under our amended and restated revolving credit agreement to redeem all of the outstanding Viking Gas Transmission Series A, B, C and D senior notes and paid a premium of $3.6 million. The net loss from the redemption, including unamortized debt costs associated with the debt, has been capitalized as a regulatory asset and will be amortized to interest expense over the remaining life of the Viking Gas Transmission senior notes. At June 30, 2006, the unamortized loss on reacquired debt included in other assets on the consolidated balance sheet was $3.7 million.
The acquisition of an additional 66 2/3 percent interest in Guardian Pipeline resulted in the inclusion of $152 million of long-term debt in our consolidated balance sheet. The senior notes comprising such debt were issued under a master shelf agreement with certain financial institutions. Principal payments are due annually through 2022. Interest rates on the notes range from 7.61 percent to 8.27 percent with an average rate of 7.85 percent.
Guardian Pipeline’s master shelf and revolving note agreement contain financial covenants (1) restricting the incurrence of other indebtedness by Guardian Pipeline and (2) requiring the maintenance of a minimum interest coverage ratio and a maximum debt ratio. The agreements require the maintenance of a ratio of (1) EBITDA (net income plus interest expense, income taxes and depreciation and amortization) to interest expense of not less than 1.5 to 1 and (2) total indebtedness to EBITDA of not greater than 6.75 to 1. Upon any breach of these covenants, amounts outstanding under the
Bridge Facilitynote agreement may becomeimmediatelydue andpayable. ACQUISITION OF GUARDIAN PIPELINE INTERESTSpayable immediately. At June 30, 2006, Guardian Pipeline was in compliance with its financial covenants.As a result of no longer consolidating Northern Border Pipeline, we are not reporting its long-term debt subsequent to December 31, 2005.
The following table sets forth our long-term debt for the periods indicated.
Due June 30,
2006December 31,
2005(Thousands of dollars) ONEOK Partners
Senior notes – 8.875%
2010 $ 250,000 $ 250,000 Senior notes – 7.10%
2011 225,000 225,000 Northern Border Pipeline
Senior notes – 7.75%
2009 — 200,000 Senior notes – 7.50%
2021 — 250,000 Senior notes – 6.25%
2007 — 150,000 Viking Gas Transmission
Series A senior notes – 6.65%
2008 — 6,045 Series B senior notes – 7.10%
2011 — 2,520 Series C senior notes – 7.31%
2012 — 7,311 Series D senior notes – 8.04%
2014 — 13,111 Guardian Pipeline
Senior notes – various
2022 151,537 — Bear Paw Energy
Capital leases
— 61 Total long-term notes payable
626,537 1,104,048 Change in fair value of hedged debt
(6,874 ) (2,362 ) Unamortized premium
18,627 22,285 Current maturities
(11,931 ) (2,194 ) Total long-term debt
$ 626,359 $ 1,121,777 Aggregate repayments of long-term debt required for the next five years are as follows: $6.0 million for the remainder of 2006, $11.9 million in 2007, $11.9 million in 2008, $11.9 million in 2009 and $261.9 million in 2010.
6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
We utilize financial instruments to reduce our market risk exposure to interest rate and commodity price fluctuations and achieve more predictable cash flows. We follow established policies and procedures to assess risk and approve, monitor and report our financial instrument activities. We do not use these instruments for trading purposes.
Cash Flow Hedges –Our Gathering and Processing segment periodically enters into commodity derivative contracts and fixed-price physical contracts. Our Gathering and Processing segment primarily utilizes NYMEX-based futures, collars and over-the-counter swaps, which are designated as cash flow hedges, to hedge its exposure to gross processing spread and natural gas, natural gas liquids and condensate price volatility. During the three and six months ended June 30, 2006, this segment recognized losses of $0.5 million and gains of $1.4 million, respectively, from the settlement of derivative contracts. At June 30, 2006, the accompanying consolidated balance sheet reflected an unrealized loss of $4.8 million in accumulated other comprehensive loss with a corresponding offset in derivative financial instrument liabilities. If prices remain at current levels, the Gathering and Processing segment expects to reclassify approximately $4.8 million from accumulated other comprehensive loss as a decrease to operating revenue in the remainder of 2006. Ineffectiveness related to these cash flow hedges resulted in a gain of approximately $1.7 million and $3.8 million for the three and six months ended June 30, 2006, respectively. There were no losses during the six months ended June 30, 2006, and 2005, due to the discontinuance of cash flow hedge treatment.
We record in accumulated other comprehensive income amounts related to terminated interest rate swap agreements for cash flow hedges and amortize these amounts to interest expense over the term of the hedged debt. During the three and six months ended June 30, 2006, we amortized approximately $0.2 million and $0.3 million, respectively, related to the terminated interest rate swap agreements as a reduction to interest expense from accumulated other comprehensive income. We expect to amortize approximately $0.2 million in each of the remaining quarters of 2006.
Fair Value Hedges –Our outstanding interest rate swap agreements, with notional amounts totaling $150 million, expire in March 2011. Under these agreements, we make payments to counterparties at variable rates based on LIBOR and receive payments based on a 7.10 percent fixed rate. At June 30, 2006, the average effective interest rate on our interest rate swap agreements was 7.62 percent. Our interest rate swap agreements are designated as fair value hedges as they hedge the fluctuations in the market value of the senior notes issued by us in 2001. As of June 30, 2006, our consolidated balance sheet reflects long-term derivative financial liabilities of $6.9 million, with a decrease in long-term debt related to our fair value hedges.
We record in long-term debt amounts received or paid related to terminated or amended interest rate swap agreements for fair value hedges and amortize these amounts to interest expense over the remaining life of the interest rate swap agreement. During the three and six months ended June 30, 2006, we amortized approximately $0.8 million and $1.6 million, respectively, as a reduction to interest expense and expect to amortize approximately $0.8 million in each of the remaining quarters of 2006.
7. GOODWILL AND INTANGIBLES
The acquisition of the ONEOK Energy Assets resulted in $214.8 million of additional goodwill in our consolidated balance sheet. The annual test of goodwill for these assets was performed as of January 1, 2006, and impairment was not indicated at that time.
Black Mesa, which was part of our former Coal Slurry Pipeline segment, consisted of a pipeline that was designed to transport crushed coal suspended in water along 273 miles of pipeline that originates at a coal mine in Kayenta, Arizona and terminates at Mohave Generating Station (Mohave) in Laughlin, Nevada. The coal slurry pipeline was the sole source of fuel for Mohave and was fully contracted to Peabody Western Coal until December 31, 2005. The water used by the coal slurry pipeline was supplied from an aquifer in the Navajo Nation and Hopi Tribe joint use area until December 31, 2005.
Under a consent decree, Mohave agreed to install pollution control equipment by December 2005. However, due to the uncertainty surrounding the ongoing source of water supply and coal supply negotiations, Southern California Edison Company (SCE), a 56 percent owner of Mohave, filed a petition before the California Public Utility Commission (CPUC) requesting that they either recognize the end of Mohave’s coal-fired operations on December 31, 2005, or authorize expenditures for pollution control activities required for future operation. In December 2004, the CPUC authorized SCE to make the necessary expenditures for critical path investments and directed interested parties to continue working toward resolution of essential water and coal supply issues.
On December 31, 2005, Black Mesa’s transportation contract with the coal supplier of Mohave expired and our coal slurry pipeline operations were shut down as expected. Pending resolution of the issues confronting Mohave, its owners requested that Black Mesa remain prepared to resume coal slurry operations. Pursuant to an agreement reached with SCE, Black Mesa was reimbursed for certain of its standby costs. In June 2006, SCE completed a comprehensive study of the water source, coal supply and transportation issues and announced that it would no longer pursue the resumption of plant operations. As a result, Black Mesa is no longer receiving reimbursement for its standby costs. SCE and the other Mohave co-owners are jointly exploring options for Mohave, including the possibility of selling the plant. SCE is also conducting discussions with all involved parties regarding Mohave’s future.
In preparation of our financial statements for the three months ended June 30, 2006, we reassessed our coal slurry pipeline operation as a result of the developments described above. We concluded that the likelihood of Black Mesa resuming operations was significantly reduced and a goodwill and asset impairment of $8.4 million and $3.4 million, respectively, would need to be recorded as depreciation and amortization in the second quarter of 2006. The reduction to net income after income taxes was $10.5 million.
We also assessed our Interstate Natural Gas Pipelines segment as a result of the sale of a 20 percent partnership interest in Northern Border Pipeline in April 2006
we executedand the acquisition of aPurchase and Sale Agreement and acquired 66-2/3%66 2/3 percent interest in Guardian Pipelinenot owned by us for approximately $77 million. We used borrowings from our credit facility to fund ourin April 2006 and concluded that there was no impairment indicated. Our acquisition of theadditional66 2/3 percent interest in GuardianPipeline. We will begin consolidating GuardianPipeline resulted in thesecond quarter, effective January 1,recognition of $5.7 million of additional goodwill and reclassification of $1.7 million to goodwill, which had been previously included in our investment in unconsolidated affiliates. The remaining increase in goodwill for the Interstate Natural Gas Pipelines segment is related to OkTex Pipeline Company, L.L.C., which was a ONEOK Energy Asset.The following table reflects the changes in the carrying amount of goodwill for the periods indicated.
Balance
December 31, 2005Goodwill
AdditionsGoodwill
AdjustmentsBalance
June 30, 2006(Thousands of dollars) Gathering and Processing
$ 75,532 $ 14,505 $ — $ 90,037 Natural Gas Liquids
— 175,566 — 175,566 Pipelines and Storage
— 24,141 — 24,141 Interstate Natural Gas Pipelines
68,872 8,048 — 76,920 Other
8,378 — (8,378 ) — Goodwill
$ 152,782 $ 222,260 $ (8,378 ) $ 366,664 In accordance with Accounting Principal Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock,” any premium paid by an investor, which is comparable to goodwill, must be identified. For the investments we account for under the equity method of accounting, this premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill. At June 30, 2006,
instead$185.6 million ofbeing reflected asequity method goodwill was included in our investment in unconsolidated affiliates on our consolidated balancesheetsheet.Intangible assets primarily relate to contracts acquired through the acquisition of the natural gas liquids businesses from ONEOK and
equity earningsare being amortized over an aggregate weighted-average period of 40 years. The aggregate amortization expense for each of the next five years is estimated to be approximately $7.7 million. The following tables reflect the gross carrying amount and accumulated amortization of intangibles at June 30, 2006.
Intangibles,
GrossAccumulated
AmortizationIntangibles,
Net(Thousands of dollars) Natural Gas Liquids
$ 292,000 $ (7,299 ) $ 284,701 Pipelines and Storage
14,650 (367 ) 14,283 Intangibles
$ 306,650 $ (7,666 ) $ 298,984 Balance
January 1, 2006Amortization Balance
June 30, 2006(Thousands of dollars) Natural Gas Liquids
$ (3,649 ) $ (3,650 ) $ (7,299 ) Pipelines and Storage
(184 ) (183 ) (367 ) Accumulated amortization
$ (3,833 ) $ (3,833 ) $ (7,666 ) 8. BUSINESS SEGMENT INFORMATION
The acquisition of the ONEOK Energy Assets in April 2006 is accounted for in these consolidated financial statements effective January 1, 2006. In connection with these transactions, we formed two new operating segments called Natural Gas Liquids and Pipelines and Storage.
Our business is divided into four reportable segments, defined as components of the enterprise about which financial information is available and evaluated regularly by our management and the Board of Directors of our general partner. Our reportable segments are strategic business units that offer different services. Each segment is managed separately based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment. These segments are as follows: (1) the Gathering and Processing segment, which primarily gathers and processes raw natural gas; (2) the Natural Gas Liquids segment, which primarily treats and fractionates raw natural gas liquids and stores and markets purity natural gas liquids products; (3) the Pipelines and Storage segment, which primarily operates intrastate natural gas transmission pipelines, natural gas storage facilities and regulated natural gas liquids gathering and distribution pipelines; and (4) the Interstate Natural Gas Pipelines segment, which primarily operates our interstate natural gas transmission pipelines that are regulated by the FERC. Certain assets of the Pipelines and Storage segment are regulated by the FERC as well as the Oklahoma Corporation Commission, Kansas Corporation Commission and Texas Railroad Commission.
The accounting policies of the segments are described in Note 3. Intersegment gross sales are recorded on the same basis as sales to unaffiliated customers. Corporate overhead costs relating to a reportable segment are allocated for the purpose of calculating operating income.
The following tables set forth certain operating segment financial data for the periods indicated.
Three Months Ended June 30, 2006
Gathering
and
ProcessingNatural Gas
LiquidsPipelines
andStorage
Interstate
Natural Gas
PipelinesOther and
EliminationsTotal (Thousands of dollars) Sales to unaffiliated customers
$ 94,216 $ 874,234 $ 17,260 $ 23,230 $ (128 ) $ 1,008,812 Sales to affiliated customers
127,083 (1,663 ) 25,118 — — 150,538 Intersegment sales
126,575 8,954 16,893 — (152,422 ) — Total revenue
$ 347,874 $ 881,525 $ 59,271 $ 23,230 $ (152,550 ) $ 1,159,350 Operating income
$ 46,279 $ 29,232 $ 25,000 $ 125,110 $ (13,025 ) $ 212,596 Equity earnings from investments
$ 5,276 $ — $ 25 $ 12,703 $ — $ 18,004 EBITDA
$ 64,407 $ 35,085 $ 32,452 $ 141,439 $ (5,482 ) $ 267,901 Capital expenditures
$ 14,581 $ 5,023 $ 11,914 $ 3,783 $ 498 $ 35,799 Three Months Ended June 30, 2005
Gathering
and
ProcessingNatural Gas
LiquidsPipelines
and
StorageInterstate
Natural Gas
PipelinesOther and
EliminationsTotal (Thousands of dollars) Sales to unaffiliated customers
$ 61,039 $ — $ — $ 81,267 $ 5,837 $ 148,143 Sales to affiliated customers
— — — 1,274 — 1,274 Intersegment sales
— — — — — — Total revenue
$ 61,039 $ — $ — $ 82,541 $ 5,837 $ 149,417 Operating income
$ 10,841 $ — $ — $ 43,915 $ (1,292 ) $ 53,464 Equity earnings from investments
$ 4,251 $ — $ — $ 167 $ — $ 4,418 EBITDA
$ 19,133 $ — $ — $ 61,234 $ 118 $ 80,485 Capital expenditures
$ 4,180 $ — $ — $ 7,656 $ 1,479 $ 13,315
Six Months Ended June 30, 2006
Gathering
and
ProcessingNatural Gas
LiquidsPipelines
and StorageInterstate
Natural Gas
PipelinesOther and
EliminationsTotal (Thousands of dollars) Sales to unaffiliated customers
$ 178,009 $ 1,685,920 $ 34,743 $ 48,783 $ 1,498 $ 1,948,953 Sales to affiliated customers
327,401 (1,663 ) 54,488 — — 380,226 Intersegment sales
243,204 16,691 32,952 — (292,847 ) — Total revenue
$ 748,614 $ 1,700,948 $ 122,183 $ 48,783 $ (291,349 ) $ 2,329,179 Operating income
$ 92,825 $ 46,351 $ 53,736 $ 138,176 $ (18,636 ) $ 312,452 Equity earnings from investments
$ 10,698 $ — $ 269 $ 38,850 $ — $ 49,817 EBITDA
$ 127,523 $ 57,472 $ 69,341 $ 184,449 $ (10,791 ) $ 427,994 Total assets
$ 1,389,161 $ 1,681,839 $ 1,055,536 $ 979,580 $ (65,625 ) $ 5,040,491 Capital expenditures
$ 22,398 $ 7,977 $ 15,490 $ 6,905 $ 805 $ 53,575 Six Months Ended June 30, 2005
Gathering
and
ProcessingNatural Gas
LiquidsPipelines
and StorageInterstate
Natural Gas
PipelinesOther and
EliminationsTotal (Thousands of dollars) Sales to unaffiliated customers
$ 118,612 $ — $ — $ 175,625 $ 11,998 $ 306,235 Sales to affiliated customers
— — — 3,561 — 3,561 Intersegment sales
— — — — — — Total revenue
$ 118,612 $ — $ — $ 179,186 $ 11,998 $ 309,796 Operating income
$ 20,343 $ — $ — $ 99,553 $ (2,894 ) $ 117,002 Equity earnings from investments
$ 8,255 $ — $ — $ 640 $ — $ 8,895 EBITDA
$ 36,839 $ — $ — $ 134,057 $ 261 $ 171,157 Total assets
$ 576,160 $ — $ — $ 1,852,747 $ 36,854 $ 2,465,761 Capital expenditures
$ 8,127 $ — $ — $ 13,066 $ 1,968 $ 23,161 We evaluate our performance based on EBITDA. Management uses EBITDA to compare the financial performance of our segments and to internally manage those business segments. Management believes that EBITDA provides useful information to investors as a measure of comparability to peer companies. EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. EBITDA calculations may vary from company to company; therefore, our computation of EBITDA may not be comparable to a similarly titled measure of another company.
The following tables set forth the reconciliation of net income to EBITDA by operating segment for the periods indicated.
Three Months Ended June 30, 2006
Gathering
and
ProcessingNatural Gas
LiquidsPipelines
and
Storage
Interstate
Natural Gas
PipelinesOther and
EliminationsTotal (Thousands of dollars) Net income
$ 53,899 $ 29,552 $ 23,345 $ 132,856 $ (43,453 ) $ 196,199 Minority interest
— — 134 385 — 519 Interest expense, net
— — 108 3,199 27,480 30,787 Depreciation and amortization
10,501 5,368 7,558 3,613 12,242 39,282 Income taxes
7 165 1,307 1,556 (1,751 ) 1,284 AFUDC
— — — (170 ) — (170 ) EBITDA
$ 64,407 $ 35,085 $ 32,452 $ 141,439 $ (5,482 ) $ 267,901 Three Months Ended June 30, 2005
Gathering
and
ProcessingNatural Gas
LiquidsPipelines
and
StorageInterstate
Natural Gas
PipelinesOther and
EliminationsTotal (Thousands of dollars) Net income
$ 15,110 $ — $ — $ 24,048 $ (11,068 ) $ 28,090 Minority interest
— — — 8,629 — 8,629 Interest expense, net
40 — — 11,228 10,104 21,372 Depreciation and amortization
3,978 — — 16,598 965 21,541 Income taxes
5 — — 849 117 971 AFUDC
— — — (118 ) — (118 ) EBITDA
$ 19,133 $ — $ — $ 61,234 $ 118 $ 80,485
Six Months Ended June 30, 2006
Gathering
and
ProcessingNatural Gas
LiquidsPipelines
and
Storage
Interstate
Natural Gas
PipelinesOther and
EliminationsTotal (Thousands of dollars) Net income
$ 91,065 $ 34,587 $ 36,474 $ 164,830 $ (60,253 ) $ 266,703 Minority interest
— — 272 1,866 — 2,138 Interest expense, net
4,590 8,866 7,887 6,942 38,936 67,221 Depreciation and amortization
21,068 10,767 15,141 7,362 12,414 66,752 Income taxes
10,800 3,252 9,567 3,747 (1,888 ) 25,478 AFUDC
— — — (298 ) — (298 ) EBITDA
$ 127,523 $ 57,472 $ 69,341 $ 184,449 $ (10,791 ) $ 427,994 Six Months Ended June 30, 2005
Gathering
and
ProcessingNatural Gas
LiquidsPipelines
and
StorageInterstate
Natural Gas
PipelinesOther and
EliminationsTotal (Thousands of dollars) Net income
$ 28,800 $ — $ — $ 56,197 $ (22,238 ) $ 62,759 Minority interest
— — — 20,818 — 20,818 Interest expense, net
94 — — 22,432 20,012 42,538 Depreciation and amortization
7,936 — — 33,167 1,920 43,023 Income taxes
9 — — 1,579 567 2,155 AFUDC
— — — (136 ) — (136 ) EBITDA
$ 36,839 $ — $ — $ 134,057 $ 261 $ 171,157 9. UNCONSOLIDATED AFFILIATES
Our investments in unconsolidated affiliates are as follows:
Net
Ownership
InterestJune 30,
2006December 31,
2005(Thousands of dollars) Northern Border Pipeline (a)
50 % $ 446,839 $ — Bighorn Gas Gathering
49 % 97,761 96,485 Fort Union Gas Gathering
37 % 80,680 79,319 Lost Creek Gathering (c)
35 % 73,572 78,482 Venice Energy Services Co., LLC
10.2 % 39,359 — Other
Various 17,842 — Guardian Pipeline
33 1/3 % — 36,470 Total
$ 756,053 (b) $ 290,756
(a) As of January 1, 2006, we began accounting for our ownership interest in Northern Border Pipeline as an investment under the equity method (Note 2). For the first three months of 2006, we included 70 percent of Northern Border Pipeline’s income in equity earnings from investments. After the sale of a 20 percent interest in Northern Border Pipeline in April 2006, we include 50 percent of Northern Border Pipeline’s income in equity earnings from investments.
(b) The unamortized excess of our investments in unconsolidated affiliates over the underlying book value of the net assets accounted for under the equity method was $185.6 million and $185.8 million at June 30, 2006 and December 31, 2005, respectively.
(c) Crestone Energy is also entitled to receive an incentive allocation of earnings from third-party gathering service revenue recognized by Lost Creek Gathering. As a result of the incentive, Crestone Energy’s share of Lost Creek Gathering income exceeds its 35 percent ownership interest. Our equity earnings from investments are as follows:
Six Months Ended
June 30,2006 2005 (Thousands of dollars) Northern Border Pipeline
$ 38,850 $ — Bighorn Gas Gathering
3,821 1,512 Fort Union Gas Gathering
4,278 2,892 Lost Creek Gathering
2,599 3,851 Other
269 — Guardian Pipeline
— 640 Total
$ 49,817 $ 8,895 Summarized combined financial information of our unconsolidated affiliates is presented below:
June 30,
2006
(Thousands of dollars) Balance Sheet
Current assets
$ 71,594 Property, plant and equipment, net
$ 1,705,988 Other noncurrent assets
$ 23,551 Current liabilities
$ 245,660 Long-term debt
$ 498,298 Other noncurrent liabilities
$ 5,311 Accumulated other comprehensive income
$ 166 Owners’ equity
$ 1,051,698 Six Months Ended
June 30, 2006
(Thousands of dollars) Income Statement
Operating revenue
$ 188,499 Operating expenses
$ 77,028 Net income
$ 88,906 Distributions paid to us
$ 69,819 10. NET INCOME PER UNIT
Net income per unit is computed by dividing net income after deducting the general partner’s allocation by the weighted average number of outstanding common units. The general partner owns a two percent interest in us and also owns incentive distribution rights which provide for an increasing proportion of cash distributions from the partnership as the distributions made to limited partners increase above specified levels. For purposes of our calculation of net income per unit, net income is generally allocated to the general partner as follows: 1) an amount based upon the two percent general partner interest in net income; and 2) the amount of the general partner’s incentive distribution right based on the total cash distributions declared during the period. The amount of incentive distribution allocated to our general partner totaled $8.2 million and $11.3 million for the three and six month ended June 30, 2006, respectively, based on distributions declared to date. The amount of distribution to partners shown on the accompanying consolidated statement of changes in partners’ equity and comprehensive income included incentive distributions paid to the general partners in the first and second quarters of 2006 of approximately $5.1 million. Gains resulting from interim capital transactions, as defined in our partnership agreement, are generally not subject to distribution; however, the partnership agreement provides that if such distributions were made, the incentive distribution right would not apply. Accordingly, the gain on sale of assets for the three and six month ended June 30, 2006, had no impact on the incentive distribution rights.
As discussed in Note 1, the Partnership completed the ONEOK Transactions during the second quarter of 2006; however, for accounting purposes, the transactions were accounted for retroactive to January 1, 2006. Net income from the ONEOK Energy Assets prior to the April 2006 acquisition was $35.8 million and has been reflected in our year-to-date earnings for 2006. For purposes of our calculation of income per unit for the six month period ended June 30, 2006, these pre-acquisition earnings were allocated to the general partner as they retained the related cash flow for that period.
On July 19, 2006, we declared a cash distribution of $0.95 per unit ($3.80 per unit on an annualized basis) for the second quarter of 2006. The distribution is payable on August 14, 2006, to unitholders of record on July 31, 2006.
11. RATES AND REGULATORY ISSUES
In November 2005, Northern Border Pipeline filed a rate case with the FERC as required by the provisions of the settlement of its last rate case. In December 2005, the FERC issued an order that identified issues that were raised in the proceeding and accepted the proposed rates, but suspended their effectiveness until May 1, 2006. Since that time, the new rates have been collected subject to refund until final resolution of the rate case. The FERC also issued a procedural schedule which set a hearing commencement date of October 4, 2006, with an initial decision scheduled for February 2007. On May 31, 2006, the FERC staff and certain interveners in the case filed their testimony. Settlement discussions are ongoing. Additional information about our regulatory proceedings is included in Note 6 of the consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2005.
12. COMMITMENTS AND CONTINGENCIES
Operating Leases and Agreements –Future minimum payments under non-cancelable operating leases and agreements as of June 30, 2006, were $8.0 million for the remainder of 2006, $14.5 million in 2007, $13.7 million in 2008, $12.3 million in 2009, $12.2 million in 2010 and $20.4 million thereafter.
Legal Proceedings –Various legal actions that have arisen in the ordinary course of business are pending. We believe that the resolution of these issues will not have a material adverse impact on our
statementresults ofincome. ROCKY MOUNTAIN NATURAL GAS LIQUIDS PIPELINE JOINT VENTUREoperations or financial position.Environmental Liabilities –We are subject to multiple environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid wastes and hazardous material and substance management. These laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to the results of operations. If an accidental leak or spill of hazardous materials occurs from our lines or facilities, in the process of transporting natural gas or natural gas liquids, or at any facility that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including investigation and clean up costs, which could materially affect our results of operations and cash flows. In
Mayaddition, emission controls required under the Federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our business, financial condition and results of operations.Our expenditures for environmental evaluation and remediation to date have not been significant in relation to our results of operations and there were no material effects upon earnings during the three and six months ended June 30, 2006 related to compliance with environmental regulations.
13. RELATED PARTY TRANSACTIONS
The Gathering and Processing segment sells natural gas to ONEOK and its subsidiaries. A significant portion of the Pipelines and Storage segment’s sales are to ONEOK and its subsidiaries which utilize both transportation and storage services.
As part of the ONEOK Transactions, we acquired contractual rights to process natural gas at the Bushton, Kansas processing plant (Bushton Plant) that is leased by a subsidiary of ONEOK, ONEOK Bushton Processing, Inc. (OBPI). Our Processing and Services Agreement with ONEOK and OBPI sets out the terms by which OBPI will provide processing and related services at the Bushton Plant through 2012. In exchange for such services, we will pay OBPI for all direct costs and expenses of operating the Bushton Plant, including reimbursement of a portion of OBPI’s obligations under equipment leases covering the Bushton Plant.
In April 2006, we entered into
an agreementa Services Agreement witha subsidiaryONEOK, ONEOK Partners GP and NBP Services that replaced the Administrative Services Agreement between us and NBP Services so that our operations and the operations ofWilliamsONEOK and its affiliates can combine or share certain common services toform a joint venture called Overland Pass Pipeline Company, LLC. The joint-venture companyoperate more efficiently and cost effectively. Under the Services Agreement, ONEOK willbuild a 750-mileprovide to us at least the type and amount of services that it provides to its affiliates, including those services required to be provided pursuant to our partnership agreement. ONEOK Partners GP will continue to operate our interstate natural gasliquidspipelinethat will transport upassets according to110,000 barrels per dayeach pipeline’s operating agreement. However, ONEOK Partners GP may purchase services from ONEOK and its affiliates pursuant to the terms ofunprocessed natural gas liquids from Opal, Wyomingthe Services Agreement.ONEOK and its affiliates provide a variety of services to
Conway, Kansas,us, including cash management and financing services, employee benefits provided through ONEOK’s benefit plans, administrative services, insurance and office space leased in ONEOK’s headquarters building and other field locations. Where costs are specifically incurred on behalf of one of our affiliates, thenation's primary natural gas liquids supply and storage hubs. Additional pump facilities would increasecosts are billed directly to us by ONEOK. In other situations, thecapacitycosts may be allocated to150,000 barrels per day. Initially, we will own 99%us through a variety of methods, depending upon the nature of thejoint ventureexpense andWilliams will ownactivities. For example, a service which applies equally to all employees is allocated based upon theremaining 1%. Williams will havenumber of employees. On theoption to increase its ownership to 50% and become operator within two years ofother hand, an expense benefiting thepipeline becoming operational. As part ofconsolidated company but having no direct basis for allocation is allocated by the modified Distrigas method, along-term agreement, Williams will dedicate its natural gas liquids production from two of its gas processing plants in Wyoming to the joint-venture company. We will provide downstream fractionation and transportation services. The natural gas liquids pipeline project is estimated to cost approximately $450 million. We plan to invest approximately $160 million to expand our existing fractionation capabilities and capacity of our natural gas liquids distribution pipelines. Financing for both projects may includemethod using a combination ofshort-ratios that include gross plant and investment, operating income and wages. All costs directly charged or allocated to us are included in the consolidated statements of income.Prior to our April 2006 acquisition, the ONEOK Energy Assets balance sheet included long-term debt
or equity. Pending all necessary approvals,owed to ONEOK. The interest rate on thetarget in-service datedebt was calculated periodically based upon ONEOK’s weighted average cost of debt. This debt was eliminated in conjunction with our acquisition of the ONEOK Energy Assets.An affiliate of ONEOK enters into some of the commodity derivative contracts on behalf of our Gathering and Processing segment. See Note 6 for a discussion of our derivative instruments and hedging activities.
The following table sets forth the transactions with related parties for the
natural gas liquids pipelineperiods shown.
Three Months Ended
June 30, 2006Six Months Ended
June 30, 2006(Thousands of Dollars) Revenue
$ 150,538 $ 380,226 Expense
Administrative and general expenses
$ 26,476 $ 45,911 Interest expense
— 21,281 Total expense
$ 26,476 $ 67,192 14. ACCOUNTING PRONOUNCEMENTS
In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment” (SFAS No. 123R), which requires companies to expense the fair value of share-based payments and includes changes related to the expense calculation for share-based payments. ONEOK Partners GP and NBP Services adopted SFAS No. 123R as of January 1, 2006, and charge us for our proportionate share of the recorded expense. The impact of adopting SFAS No. 123R did not have a material impact on our results of operations or financial position.
In September 2005, the FASB ratified the consensus reached in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (EITF 04-13). EITF 04-13 defines when a purchase and a sale of inventory with the same party that operates in the same line of business should be considered a single nonmonetary transaction. EITF 04-13 is
early 2008. 14ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSeffective for new arrangements that a company enters into in periods beginning after March 15, 2006. We completed our review of the applicability of EITF 04-13 to our operations and determined that it did not have a material impact on our results of operations or financial position.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and notes to consolidated financial statements included under Item 1.
In this report, references to
"we," "us," "our"“we,” “us,” “our” or the"Partnership" collectively“Partnership” refer toNorthern BorderONEOK Partners, L.P., our subsidiary, ONEOK Partners Intermediate Limited Partnership, and its subsidiaries, formerly known as Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership,and its subsidiaries.respectively.EXECUTIVE SUMMARY
OVERVIEW Northern BorderOverview –ONEOK Partners, L.P. is a publicly traded Delaware limited partnership that was formed in 1993. Our common units are listed on the NYSE under the trading symbol
"NBP." For“OKS.” In April 2006, we acquired certain companies comprising ONEOK’s former Gathering and Processing, Natural Gas Liquids and Pipelines and Storage segments collectively referred to as thefirst quarter ended March 31,“ONEOK Energy Assets” from ONEOK, the parent company of our general partner, in a series of transactions collectively referred to as the “ONEOK Transactions,” which are described under “Recent Developments” in this section. The ONEOK Energy Assets are consolidated with our legacy assets and reported in our consolidated financial statements as of January 1, 2006.As of June 30, 2006, our operations
were conducted throughare divided into four strategic business units based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment, which include thefollowing two business segments: -following:the Gathering and Processing segment, which primarily gathers and processes raw natural gas;the Natural Gas Liquids segment, which primarily treats and fractionates raw natural gas liquids, and stores and markets purity natural gas liquids products;the Pipelines and Storage segment, which primarily operates intrastate natural gas transmission pipelines, natural gas storage facilities and regulated natural gas liquids gathering and distribution pipelines; andthe Interstate Natural GasPipeline,Pipelines segment, whichprovidesprimarily operates our interstate natural gastransportation services; and - Natural Gastransmission pipelines.Our Gathering and Processing,
which gathers, processesNatural Gas Liquids, Pipelines andcompressesStorage, and Interstate Natural Gas Pipelines segments accounted for approximately 43 percent, 21 percent, 25 percent and 11 percent of operating income, respectively, for the six months ended June 30, 2006.Our primary business objectives are to generate stable cash flow sufficient to pay quarterly cash distributions to our unitholders and to increase our quarterly cash distributions over time. Our ability to maintain and grow our distributions to unitholders depends on acquisitions and growth of our existing businesses.
The acquisition of the ONEOK Energy Assets utilizes our core competencies related to energy transportation services in the United States and diversifies our portfolio of assets. The ONEOK Energy Assets enable us to enter into the well-established Midcontinent market and key natural gas liquids markets in Kansas and
fractionates natural gas liquids. RECENT DEVELOPMENTSTexas. In addition, our expanded portfolio better positions us for future organic growth projects, which we believe offer the most attractive growth opportunities for us at this time.Recent Developments –The following is a summary of our significant developments since
DecemberMarch 31,2005: Guardian Pipeline Revenue and Cost Study -2006:ONEOK Transactions – In
February 2006, the FERC issued an order accepting Guardian Pipeline's revenue and cost study that requested approval of a settlement agreement to re-establish the rates initially approved by the FERC and to reduce the depreciation rate from 3.33% to 2.0%, effective January 1, 2005. Guardian Pipeline II Project - In February 2006, Guardian Pipeline announced that it signed precedent agreements with two major Wisconsin utility companies to expand its existing natural gas pipeline system in eastern Wisconsin. The proposed project will expand and extend the existing pipeline approximately 106 miles from its current terminus near Ixonia, Wisconsin to the Green Bay area, adding approximately 537 MMcf/d of capacity. Guardian Pipeline's capital costs for the project are estimated to range between $220 million and $240 million. Pending all necessary approvals, the target in-service date is November 2008. Midwestern Gas Transmission Eastern Extension Project - In March 2006, Midwestern Gas Transmission accepted the certificate of public convenience and necessity issued by the FERC for its Eastern Extension Project. The Eastern Extension Project will add 31 miles of natural gas pipeline with approximately 120 MMcf/d of transportation capacity. It is estimated that the project will cost approximately $28 million. Due to the delay in obtaining the FERC certificate, the Eastern Extension Project's proposed in-service date of November 2006 will likely also be delayed. Amended and Restated Credit Agreement - In MarchApril 2006, weentered into a $750 million amended and restated revolving credit agreement and terminated our existing $500 million revolving credit agreement.completed the acquisition of the ONEOK Energy Assets through the ONEOK Transactions, described as follows:Acquisition of ONEOK Energy Assets
- In April 2006, under the Contribution Agreement, we– We acquiredall of ONEOK's gatheringcertain assets comprising ONEOK’s former Gathering andprocessingProcessing, Natural Gas Liquids andpipelinesPipelines andstorage assetsStorage segments for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. ONEOK now owns approximately 37.0 million of our limited partner units which, when combined with its general partner interest, increases its total interest in us to45.7%. Under the ONEOK Purchase and Sale Agreement, we purchased all of ONEOK's natural gas liquids assets for $1.35 billion in cash.45.7 percent. We used $1.05 billion drawn under our $1.1 billion, 364-day credit agreement coupled with the proceeds from the sale ofthe 20%our 20 percent partnership interest in Northern Border PipelineCompanyto finance the transaction.15OurThe assets were recorded at historical cost rather than at fair value since these transactions were between affiliates under common control. These assets and their related operations are included in our consolidated financial statements as of January 1, 2006.The Audit Committee of Northern Border Partners, L.P., which
consistsconsisted solely of independent members, determined that the ONEOKtransactionsTransactions were fair and reasonable to us and in the interests of our public unitholders. The Audit Committee engaged independent legal counsel and an independent financial adviser to assist in itsdetermination.determination that the ONEOK Transactions were fair and reasonable to us and in the interests of our public unitholders.Equity Issuance– We amended our partnership agreement to provide for the issuance of Class B limited partner units and issued approximately 36.5 million Class B limited partner units to ONEOK in connection with the ONEOK Transactions. The new class of equity securities is entitled to the same distribution rights as our outstanding common units, but has limited voting rights and is subordinated to the common units with respect to the minimum quarterly distribution. The number of Class B units issued was determined by using the average closing price of our common units for the 20 trading days prior to the signing of a Contribution Agreement between ONEOK and us on February 14, 2006. The Class B limited partner units were issued on April 6, 2006.
We will hold a special election for holders of common units as soon as practical but within 12 months, subject to extension, of issuing the Class B units, to approve the conversion of the Class B units into common units and certain amendments to our partnership agreement. The proposed amendments would grant voting rights for common units held by our general partner if a vote is held to remove our general partner and require fair market value compensation for the general partner interest if the general partner is removed.
If the common unitholders do not approve the conversion and the amendments, the Class B unit distribution rights will increase to 115 percent of the cash distributions paid on the common units. If the conversion and the amendments are approved by the common unitholders, the Class B units will be eligible to convert into common units on a one-for-one basis. If the common unit holders vote to remove ONEOK or its affiliates as our general partner at any time prior to the approval of the conversion and certain amendments to our partnership agreement, the Class B unit distribution rights will continue to be subordinated in the manner described above unless and until the conversion described above has been approved, at which time the amount payable on such Class B units would increase to 125 percent of the cash distributions payable with respect to the common units.
Purchase and Sale of General Partner Interest – ONEOK acquired ONEOK NB, formerly known as Northwest Border Pipeline Company, an affiliate of TransCanada that held a 0.35 percent general partner interest in us. As a result, ONEOK owns the entire two percent general partner interest in us and therefore controls the partnership.
Disposition of
20%20 Percent Partnership Interest in Northern Border Pipeline- In April 2006, we completed the sale of– We sold a20%20 percent partnership interest in Northern Border Pipeline to TC PipeLinesunder the Partnership Interest Purchase and Sale Agreement dated as of December 31, 2005,for approximately $297million.million to help finance the acquisition of the ONEOK Energy Assets. We recorded a gain on the sale of approximately $113.9 million in the second quarter of 2006. We and TC PipeLines each now own a50%50 percent interest in Northern Border Pipeline. As a result of thesale,transaction, Northern Border Pipelinewillis no longerbeconsolidated in our financial statements. Instead, our interest in Northern Border Pipelinewill be reflectedis accounted for as an investmentin unconsolidated affiliates on our balance sheet andunder the equityearnings in unconsolidated affiliates on our statement of income, effective January 1, 2006. As a result of the transaction,method.In addition, the General Partnership Agreement for Northern Border Pipeline was amended and restated, effective April 6, 2006. The major provisions adopted or changed
includedinclude the following:- Thethe Management Committee of Northern Border Pipelinewill consistconsists of four members. Each partnerwill designatedesignates two members and TC PipeLineswill designatedesignates one of its members aschairman. - Thechairman;the Management Committeewill designatedesignates the members of the Audit Committee, whichwill consistconsists of three members. One memberwill beis selected by thepartnerpartner’s designated members of the Management Committee whose affiliate is the operator and two memberswill beare selected by the otherpartner. -partner’s designated members of the Management Committee; andONEOK Partners GP, formerly known as Northern Plains Natural Gas Company, LLC, will operate Northern Border Pipeline until April 1, 2007. Effective April 1, 2007, an affiliate of TransCanada will become the operator.OurThe Audit Committee of Northern Border Partners, L.P. determined that the disposition of the
20%20 percent interest in Northern Border Pipeline was fair and reasonable to us and in the interests of our public unitholders. The Audit Committee engaged independent legal counsel and an independent financial adviser to assist in itsdetermination. Purchasedetermination that the disposition of the 20 percent interest in Northern Border Pipeline was fair andSalereasonable to us and in the interests ofGeneral Partner Interest - In April 2006, underour public unitholders.Services Agreement– We entered into a Services Agreement with ONEOK, ONEOK Partners GP and NBP Services that replaced the
Purchase and SaleAdministrative Services Agreement between us and NBP Services so that our operations and the operations of ONEOK andan affiliateits affiliates can combine or share certain common services to operate more efficiently and cost effectively. Under the Services Agreement, ONEOK will provide to us at least the type and amount ofTransCanada,services that it provides to its affiliates, including those services required to be provided pursuant to our partnership agreement. ONEOKacquired Northwest Border, an affiliatePartners GP will continue to operate our interstate natural gas pipeline assets according to each pipeline’s operating agreement. However, ONEOK Partners GP may purchase services from ONEOK and its affiliates pursuant to the terms ofTransCanada that held a 0.35% general partner interest in us. As a result, ONEOK owns our entire 2% general partner interest. Change of Directors and Officers - In April 2006, concurrent withthecompletion of ONEOK's purchase of Northwest Border, Paul E. Miller resigned as a member of our Partnership Policy Committee and John W. Gibson was appointed by Northwest Border to replace him. In addition, several appointments of our principal officers were announced, effective April 7, 2006, which included: - David Kyle, chairman and chief executive officer of ONEOK, was appointed our chairman and chief executive officer; - John W. Gibson, formerly president of ONEOK Energy Companies, was appointed our president and chief operating officer; - James C. Kneale, executive vice president, Finance and Administration and chief financial officer of ONEOK, was appointed our chief financial officer; - Jerry L. Peters, formerly our chief financial officer, was appointed our senior vice president, chief accounting officer and treasurer; - John R. Barker, senior vice president and general counsel of ONEOK, was appointed our executive vice president, general counsel and secretary; - William R. Cordes, formerly our chief executive officer, was appointed president of Northern Border Pipeline; and - Janet K. Place, was appointed our vice president, associate general counsel and assistant secretary, and general counsel of Northern Border Pipeline.Services Agreement.Bridge Facility
- In April 2006, we– We entered into a $1.1 billion 364-day credit agreement with several financial institutions tocompletefinance a portion of the ONEOK Transactions. Amounts outstanding under the agreement must be repaid on or before April 5, 2007.16Additional information about this agreement is included under, “Liquidity and Capital Resources.” Increased Cash Distribution
-–In April 2006, we increased our cash distribution by $0.08 per unit to $0.88 per unit for the first quarter of 2006,payablewhich was paid on May 15, 2006, to unitholders of record as of April 28, 2006. In July 2006, we increased our cash distribution by $0.07 per unit to $0.95 per unit for the second quarter of 2006, payable on August 14, 2006, to unitholders of record as of July 31, 2006.Northern Border Pipeline Chicago III Expansion Project
-– In April 2006, the Chicago III Expansion Project went into service as planned, adding approximately 130 MMcf/d of transportation capacity on the eastern portion ofthe pipelineNorthern Border Pipeline into the Chicago area.Acquisition of Guardian Pipeline Interests
-–In April 2006, weexecutedacquired aPurchase and Sale Agreement and acquired 66-2/3%66 2/3 percent interest in Guardian Pipelinenot owned by usfor approximately $77million. As a result of the acquisition,million, increasing our ownership to 100 percent. Guardian Pipelinewill beis consolidated in our financial statements and reported in our Interstate Natural GasPipeline segment instead ofPipelines segment. Previously, it was reflected as an investment under the equity method.ONEOK Partners, L.P. Amended and Restated Partnership Agreement – In May 2006, our sole general partner, ONEOK Partners GP, entered into a Second Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P. (MLP Partnership Agreement) to amend and restate our previously existing partnership agreement, the principal differences of which are as follows. The MLP Partnership Agreement:
changes the name of Northern Border Partners, L.P. to ONEOK Partners, L.P.;provides that we are managed by our sole general partner, ONEOK Partners GP;replaces our previously existing Partnership Policy Committee and Audit Committee with the Board of Directors, Audit Committee and Conflicts Committee of ONEOK Partners GP;separates the functions of the Audit Committee, which will be a standing committee of the Board of Directors of ONEOK Partners GP, and the Conflicts Committee, which will not be a standing committee of the Board of Directors of ONEOK Partners GP;expands our “purpose” clause to encompass midstream business activities as well as other activities permitted by applicable law;incorporates Amendment No. 1 to our previously existing partnership agreement, the provisions of which are described inunconsolidatedour Current Report on Form 8-K filed on April 12, 2006;removes obsolete provisions of the previously existing partnership agreement; andmodifies the form of common unit certificate to reflect the new name of the partnership and related matters.ONEOK Partners Intermediate Limited Partnership Amended and Restated Partnership Agreement– In May 2006, the sole general partner of ONEOK Partners Intermediate Limited Partnership (ILP), ONEOK Partners GP, and we, the sole limited partner of ILP, entered into a Second Amended and Restated Agreement of Limited Partnership of ONEOK Partners Intermediate Limited Partnership (ILP Partnership Agreement) to amend and restate the previously existing partnership agreement, the principal differences of which are as follows. The ILP Partnership Agreement:
changes the name of Northern Border Intermediate Limited Partnership to ONEOK Partners Intermediate Limited Partnership;provides that ILP will be managed by its sole general partner, ONEOK Partners GP;replaces its previously existing Partnership Policy Committee and Audit Committee with the Board of Directors and Audit Committee of ONEOK Partners GP; andremoves obsolete provisions of the previously existing partnership agreement.ONEOK Partners GP, the sole general partner of us and the sole general partner of ILP, is a wholly owned subsidiary of ONEOK. ONEOK Partners GP and its affiliates own an approximate 45.7 percent interest in us.
Name, Address and Website Changes – In May 2006, we filed a Certificate of Amendment to Certificate of Limited Partnership of Northern Border Partners, L.P. to change our name to ONEOK Partners, L.P. Northern Border Intermediate Limited Partnership also filed a Certificate of Amendment to Certificate of Limited Partnership of Northern Border Intermediate Limited Partnership to change its name to ONEOK Partners Intermediate Limited Partnership. The amendments also reflect the new name and address of our and ILP’s sole general partner, ONEOK Partners GP, formerly known as Northern Plains Natural Gas Company, LLC.
The new address of our principal executive offices and the address of our sole general partner is 100 West Fifth Street, Tulsa, Oklahoma 74103-4298. Our new website is www.oneokpartners.com, where our Governance Guidelines, Code of Conduct, Accounting and Financial Reporting Code of Ethics, MLP Partnership Agreement and written charter of the Audit Committee are available. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports are available free of charge through our
balance sheetwebsite as soon as reasonably practicable after we electronically file them with, or furnish them to, the SEC.Change of Directors and
equity earningsOfficers – In May 2006, we amended and restated our MLP Partnership Agreement to replace our Partnership Policy Committee and Audit Committee with the Board of Directors and Audit Committee of our sole general partner, ONEOK Partners GP. As a result, all of our officers and members of the Partnership Policy Committee resigned and ONEOK Partners GP elected a six-member Board of Directors, three of whom are independent and will also serve on the Audit Committee of the Board of Directors of ONEOK Partners GP. The ONEOK Partners GP Board of Directors includes the following members:David L. Kyle, the chairman and chief executive officer of our general partner, who is also chairman of the board, president and chief executive officer of ONEOK;John W. Gibson, the president and chief operating officer of our general partner;James C. Kneale, the executive vice president–finance and administration and chief financial officer of our general partner, who is also the executive vice president–finance and administration and chief financial officer of ONEOK;Gerald B. Smith, chairman and chief executive officer of Smith, Graham and Company Investment Advisors, L.P.;Gary N. Petersen, president of Endres Processing LLC; andGil J. Van Lunsen, a retired managing partner of the Tulsa, Oklahoma office of KPMG LLP.Concurrently, the Board of Directors of ONEOK Partners GP elected officers of ONEOK Partners GP, including the following:
David L. Kyle, chairman and chief executive officer;John W. Gibson, president and chief operating officer;James C. Kneale, executive vice president–finance and administration and chief financial officer;John R. Barker, executive vice president, general counsel and secretary; andJerry L. Peters, senior vice president, chief accounting officer and treasurer.Biographical information for Mr. Kyle, Mr. Peters, Mr. Smith, Mr. Petersen and Mr. Van Lunsen is included under Item 10, “Directors and Executive Officers of the Registrant,” in
unconsolidated affiliatesour Annual Report on Form 10-K for the year ended December 31, 2005. Biographical information for Mr. Gibson, Mr. Kneale and Mr. Barker is included in ourstatement of income. Rocky MountainCurrent Report on Form 8-K filed on May 23, 2006.Overland Pass Natural Gas Liquids Pipeline Joint Venture
-–In May 2006, we entered into an agreement with a subsidiary of The Williams Companies, Inc. (Williams) to form a joint venture called Overland Pass Pipeline Company. Overland Pass Pipeline CompanyLLC. The joint-venture companywill build a 750-mile natural gas liquids pipelinethat will transport up to 110,000 barrels per day of unprocessed natural gas liquidsfrom Opal, Wyoming toConway, Kansas, one ofthenation's primaryMidcontinent natural gas liquidssupply and storage hubs. Additionalmarket center in Conway, Kansas. The pipeline will be designed to transport approximately 110,000 Bbl/d of natural gas liquids, which can be increased to approximately 150,000 Bbl/d with additional pump facilitieswould increaseif customers contract for that capacity. As thecapacity to 150,000 barrels per day. Initially, we will own 99%99 percent owner of the joint venture, we will manage the construction project, advance all costs associated with construction andWilliams will ownoperate theremaining 1%.pipeline. Williams will have the option to increase its ownership up to50%50 percent by reimbursing us for our proportionate share of all construction costs and, upon full exercise of that option, would become operator within two years of the pipeline becoming operational. Construction of the pipeline is expected to begin in the summer of 2007, with start up scheduled for early 2008. As part of a long-term agreement, Williamswill dedicatededicated its natural gas liquids production from two of its gas processing plants in Wyoming to the joint-venture company. We will provide downstream fractionation, storage and transportationservices.services to Williams. Thenatural gas liquidspipeline project is estimated to cost approximately$450$433 million.WeAt the project’s inception, we paid $11.4 million to Williams for initial capital expenditures incurred. In addition, we plan to invest approximately$160$173 million to expand our existing fractionation capabilities and the capacity of our natural gas liquids distribution pipelines. Financing for both projects may include a combination of short- or long-term debt or equity.Pending all necessary approvals,The project requires thetarget in-service date for theapproval of various state and regulatory authorities.Midcontinent Pipeline Proposal –In June 2006, we signed a letter of intent to form a joint venture with Boardwalk Pipeline Partners, LP and Energy Transfer Partners, LP to construct a new interstate natural gas
liquidspipeline originating in North Texas, crossing Oklahoma and Arkansas and terminating in Dyer County, Tennessee at a new interconnect with Texas Gas Transmission, LLC. The proposed interstate pipeline would create new pipeline capacity for constrained wellhead production in North Texas and Central Oklahoma and would have initial capacity of up to 1.0 Bcf/d. Formation of the joint venture isearly 2008.subject to negotiation and execution of definitive agreements by the participants.The preparation of financial statements in accordance with
U.S.GAAP requires us to make estimates and assumptions with respect to values or conditions which cannot be known with certainty that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements.SuchThese estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates are reasonable, actual results could differ from our estimates.There has beenImpairment of Goodwill and Long-Lived Assets –We assess goodwill for possible impairment annually and when events or changes in circumstances indicate the carrying value of the goodwill might exceed its current fair value for each of our business segments in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets.” Fair values are based on the discounted cash flow method for each of our business segments. This type of analysis requires us to make assumptions and estimates regarding industry economic factors and the profitability of future business strategies. Our assumptions and estimates are based on our current business strategy taking into consideration present industry and economic conditions, as well as our analysis of future expectations. If the fair value of the business is less than the book value including the goodwill, goodwill is deemed to be impaired and we are required to perform a second test to measure the amount of the impairment. In the second test, we calculate the fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the operations from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculated fair value of the goodwill, we will record a goodwill impairment charge.
We assess our long-lived assets for possible impairment when events or changes in circumstances indicate that their carrying amount may exceed their fair value in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Management reviews our assets at the end of each reporting period to determine if any events that would trigger asset impairment have occurred. This type of analysis requires us to make assumptions and estimates regarding industry economic factors and the profitability of future business strategies. Our assumptions and estimates are based on our current business strategy, taking into consideration present industry and economic conditions as well as our analysis of future expectations. Fair values are based on the sum of the undiscounted future cash flow expected to result from the use and eventual disposition of the assets. If the undiscounted future cash flow is less than the carrying value of the asset, we calculate an impairment loss. The impairment loss calculation compares the carrying value of the asset to the asset’s estimated fair value, which is based on future discounted cash flow. If we recognize an impairment loss, the adjusted carrying amount of the asset will be its new cost basis. For a depreciable long-lived asset, the new cost basis will be depreciated over the remaining useful life of that asset.
In preparation of our financial statements for the three months ended June 30, 2006, we reassessed our Black Mesa coal slurry pipeline operation as a result of Southern California Edison Company’s announcement that it would no
changelonger pursue the resumption of operations of the Mohave Generating Station. We concluded that the likelihood of Black Mesa resuming operations was significantly reduced and a goodwill and asset impairment of $8.4 million and $3.4 million, respectively, would need to be recorded as depreciation and amortization in the second quarter of 2006. The reduction to net income after taxes was $10.5 million. Additional information about Black Mesa is included under “Results of Operations–Other.”We also assessed our
critical accounting estimates duringInterstate Natural Gas Pipelines segment as a result of thefirst quarter ended March 31, 2006. Informationsale of a 20 percent interest in Northern Border Pipeline in April 2006 and the acquisition of a 66 2/3 percent interest in Guardian Pipeline in April 2006 and concluded that there was no impairment indicated. The acquisition of the 66 2/3 percent interest in Guardian Pipeline resulted in the recognition of $5.7 million of additional goodwill.Additional information about our critical accounting estimates is included under Item 7,
"Management's“Management’s Discussion and Analysis of Financial Condition and Results ofOperations-CriticalOperations–Critical Accounting Estimates,"” in ourannual reportAnnual Report on Form 10-K for the year ended December 31, 2005.17RESULTS OF OPERATIONS
SELECTED FINANCIAL AND OPERATING RESULTS BY SEGMENT The following table summarizes financialConsolidated Operating Results –Consolidated net income was $196.2 million and
operating results by segment$266.7 million for the three and six months endedMarch 31,June 30, 2006, respectively, compared with $28.1 million and $62.8 million for the same periods last year. Net income increased primarily due to:the April 2006 acquisition of the ONEOK Energy Assets, which are consolidated effective as of January 1, 2006, for financial reporting purposes and accounts for $89.5 million and $125.3 million of consolidated net income for the three and six months ended June 30, 2006, respectively;favorable commodity prices realized by our gathering and processing business; andthe gain on sale of assets reported in the second quarter of 2006 as a result of the sale of a 20 percent interest in Northern Border Pipeline; partially offset bythe impact of the goodwill and asset impairment related to Black Mesa.Consolidated net margin was $215.2 million and $420.1 million for the three and six months ended June 30, 2006, respectively, compared with $114.0 million and $241.9 million, respectively, for the same periods last year. Net margin increased primarily due to the acquisition of the ONEOK Energy Assets, which accounts for $165.4 million and $314.1 million of consolidated net margin for the three and six months ended June 30, 2006, respectively, and to a lesser extent, the effect of the Guardian Pipeline consolidation partially offset by the effect of the Northern Border Pipeline deconsolidation.
We recognized a $113.9 million gain on sale of assets in the second quarter of 2006 as a result of the sale of a 20 percent interest in Northern Border Pipeline.
Consolidated interest expense increased for the three and six months ended June 30, 2006, due to the additional borrowings associated with the ONEOK Transactions, partially offset by the Northern Border Pipeline deconsolidation.
Equity earnings from investments for the three and six months ended June 30, 2006, primarily include earnings from our interest in Northern Border Pipeline and our gathering and processing joint venture interests in the Powder River and Wind River Basins. Equity earnings from investments for the three and six months ended June 30, 2005, include earnings from our 33 1/3 percent interest in Guardian Pipeline, which is reflected on a consolidated basis beginning January 1, 2006, and
2005:
THREE MONTHS ENDED MARCH 31, ------------------- 2006 2005 -------- -------- (In thousands, except operating data)Operating revenue: Interstate natural gas pipeline $ 95,642 $ 96,645 Natural gasour gathering and processing73,513 57,573 Other 1,644 6,161 -------- -------- Total operating revenue 170,799 160,379 -------- -------- Operating income (loss): Interstate natural gas pipeline 55,325 55,638 Natural gas gathering and processing 13,991 9,502 Other (5,653) (1,602) -------- -------- Total operating income 63,663 63,538 -------- -------- Income (loss) from continuing operations: Interstate natural gas pipeline 31,920 32,149 Natural gas gathering and processing 19,565 13,690 Other (16,808) (11,560) -------- -------- Total income from continuing operations 34,677 34,279 -------- -------- Discontinued operations, net of tax 9 390 -------- -------- Net income $ 34,686 $ 34,669 ======== ======== Operating data by segment (1): Interstate natural gas pipeline: MMcf delivered 305,280 306,692 MMcf/d average throughput 3,468 3,501 Natural gas gathering and processing: MMcf/d gathered 1,095 1,049 MMcf/d processed 65 60(1) Operating data includes 100% of the volumes forjoint ventureinvestments as well asinterests in the Powder River and Wind River Basins.Minority interest in net income for
whollythe three and six months ended June 30, 2006, includes earnings from the 66 2/3 percent interest in Guardian Pipeline that we did not own until we acquired that interest in April 2006. Minority interest in net income for the three and six months ended June 30, 2005, includes earnings from the 30 percent interest in Northern Border Pipeline ownedsubsidiaries. CONSOLIDATED OPERATING RESULTS Operating revenue increased $10.4by TC PipeLines when Northern Border Pipeline’s results were consolidated.Income taxes for the six months ended June 30, 2006, include income tax expense recorded for the ONEOK Energy Assets of $22.2 million
or 6%,calculated on a stand-alone basis for the first quarter of2006 compared2006. Prior to the acquisition, the ONEOK Energy Assets were included in the consolidated state and federal income tax returns of ONEOK and, accordingly, income tax expense was allocated to the ONEOK Energy Assets based on ONEOK’s effective rate. In conjunction with thesame quarterONEOK Transactions, any outstanding income tax liabilities of2005 due to higher Natural Gasthe ONEOK Energy Assets were retained by ONEOK.Gathering and Processing
segment revenue which offset the slightly lower Interstate Natural Gas Pipeline segment revenue and the loss of coal slurry pipeline revenue resulting from the shut down of Black Mesa on December 31, 2005. The coal slurry pipeline results are not reported as a discontinued operation because we believe that the coal slurry pipeline operation is likely to resume in the future. Additional information about our coal slurry pipeline operation is included in this section under "Other" and Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations-Executive Summary," in our annual report on Form 10-K for the year ended December 31, 2005. Operating income was flat for the first quarter of 2006 compared with the same quarter last year. The increased contributionSegmentOverview –As part of the
Natural Gas Gathering and Processing segment was offset by due diligence, legal and other expenses related to theONEOKand TransCanada transactionsTransactions described in this section under"Recent Developments." 18Income from continuing operations was also flat for the first quarter“Recent Developments,” we acquired all of2006 compared with the same quarter last year. Increased interest and income tax expense were offset by higher equity earnings in unconsolidated affiliates. INTERSTATE NATURAL GAS PIPELINE SEGMENT OVERVIEW The Interstate Natural Gas Pipeline segment transportsONEOK’s natural gasprimarily from the Western Canada Sedimentary Basin to the Midwestern U.S. At March 31, 2006, the Interstate Natural Gas Pipeline segment consisted of the following: - 70% general partnership interest in Northern Border Pipeline; - Midwestern Gas Transmission; - Viking Gas Transmission;gathering and- 33-1/3% interest in Guardian Pipeline. In April 2006, we completed the sale of a 20% partnership interest in Northern Border Pipeline to TC PipeLines. Weprocessing assets andTC PipeLines each now own a 50% interest in Northern Border Pipeline. In addition, wecombined these newly acquired66-2/3% interest in Guardian Pipeline not owned by us. Additional information about these transactions is included in this section under "Recent Developments." KNOWN TRENDS AND UNCERTAINTIES We continue to expect that Canadian natural gas export volumes in 2006 will remain near 2005 levels despite increased production in Canada as a result of the greater number of Canadian drilling rigs in operation. We also continue to expect U.S. demand for natural gas in 2006 to be similar to 2005 levels. Residential demand for natural gas fell below normal levels during the 2005-2006 heating season as a result of warm temperatures in January and relatively normal temperatures in February. However, the Energy Information Administration projects that increased industrial demand in 2006 will offset the reduced demand of residential users. We continue to expect that Northern Border Pipeline revenue in 2006 will be comparableassets with2005 revenue, although market conditions have changed. In April and May of 2005, we did not sell all ofourfirm transportation capacity on Northern Border Pipeline due to decreased demand for Canadian natural gas as a result of greater supply competition in the Midwestern U.S. and increased natural gas storage injections. When storage levels approached full capacity and summer temperatures were higher than normal during the third quarter of 2005, demand for the pipeline's transportation capacity increased. Natural gas storage levels in Western Canada were higher during the first quarter of 2006 compared with the first quarter of 2005 and the five-year average for the same period as a result of relatively warm winter temperatures. Increased natural gas throughput on the TransCanada pipeline system to Eastern markets, due in part to greater demand for Canadian natural gas supply as a result of lingering supply disruptions related to Hurricanes Katrina and Rita, is expected to slow storage injection activity in Western Canada during the second quarter of 2006. In addition, Western U.S. demand for Canadian natural gas is expected to modestly decline in 2006 compared with 2005 due to the return of normal snowpack in the region that will cause gas-fired electric generation to be displaced with hydroelectric generation. OPERATING RESULTS The Interstate Natural Gas Pipeline segment reported income from continuing operations of $31.9 million for the first quarter ended March 31, 2006, which was relatively flat compared with $32.1 million for the same quarter of 2005. A modest decline in Northern Border Pipeline revenue was offset by increased Midwestern Gas Transmission revenue. Operating revenue decreased slightly for the first quarter ended March 31, 2006, compared with the same quarter of 2005. Northern Border Pipeline operating revenue decreased $3.0 million for the first quarter of 2006 compared with the same quarter last year primarily as a result of discounted transportation rates, transportation capacity that was sold for shorter transportation paths and some unsold firm transportation capacity in March 2006. Midwestern Gas Transmission partially offset this decrease primarily with additional revenue generated from the Southbound Expansion, which went into service in November 2005. 19Operations and maintenance expense decreased $1.6 million for the first quarter ended March 31, 2006, compared with the same quarter of 2005. Viking Gas Transmission recorded an unfavorable gas imbalance adjustment of $1.4 million during the first quarter of 2005. Equity earnings of unconsolidated affiliates represent earnings from our one-third interest in Guardian Pipeline. Minority interests in net income represent the 30% minority interest in Northern Border Pipeline. NATURAL GAS GATHERING AND PROCESSING SEGMENT OVERVIEW The Natural Gaslegacy Gathering and Processing segmentgathersassets.The gathering and processing assets we acquired from ONEOK gather natural gas in the Midcontinent region, which includes the Anadarko Basin of Oklahoma and the Hugoton Basin and Central Kansas Uplift of Kansas. Raw natural gas is compressed and transported through pipelines to processing facilities where volumes are aggregated, treated and processed to remove water vapor, solids and other contaminants and natural gas liquids are extracted. In some cases, the natural gas liquids are separated into marketable components, including ethane, propane, isobutane, normal butane and natural gasoline, utilizing a distillation process known as fractionation and the components are sold to refineries or local markets. The remaining residue gas, which consists primarily of methane, is compressed and delivered to natural gas pipelines.
Our legacy Gathering and Processing segment assets gather natural gas from
producers'producers’ wells and central delivery points in three producingbasins:basins in the Rocky Mountain region: the Williston Basin, which spans portions of Montana, North Dakota and the Canadian province of Saskatchewan, and the Powder River and Wind River Basins of Wyoming.Our Williston Basin facilities compress and transport raw natural gas, primarily associated with oil production, through pipelines to our processing facilities where water and other contaminants are removed and valuable natural gas liquids are extracted. We separate
• Williston Basin – Our Williston Basin facilities compress and transport raw natural gas, primarily associated with oil production, through pipelines to our processing facilities where water and other contaminants are removed and natural gas liquids are extracted. We fractionate the natural gas liquids into marketable components and sell the components to refineries or local markets. We compress the remaining residue gas, consisting primarily of methane, and deliver it to interstate natural gas pipelines.
• Powder River Basin –Our Powder River Basin facilities gather and compress coalbed methane gas primarily to the Bighorn Gas Gathering and Fort Union Gas Gathering trunk gathering systems for gathering and delivery to interstate natural gas pipelines. These assets provide different levels of services at different gathering rates.
• Wind River Basin –Our Wind River Basin facilities consist of an interest in the Lost Creek Gathering trunk gathering system that receives natural gas from pipeline interconnections with producer-owned gathering systems and processing plants. The natural gas is processed as necessary and delivered to interstate natural gas pipelines. Together, the
natural gas liquids into marketable components utilizing a distillation process known as fractionation and sell the components to refineries or local markets. We compress the remaining residue gas, consisting primarily of methane, and deliver it to interstate natural gas pipelines. Our Powder River Basin facilities compress and transport coalbed methane gas primarily to the Bighorn Gas Gathering and Fort Union Gas Gathering trunk gathering systems for transport and delivery to interstate natural gas pipelines. Our Wind River Basin facilities consist of an interest in a trunk gathering system that receives natural gas from pipeline interconnections with producer-owned gathering systems and processing plants. The natural gas is processed as necessary and delivered to interstate natural gas pipelines. At March 31, 2006, the Natural Gascombined Gathering and Processing segmentconsistedassets consist of thefollowing subsidiaries: - Bear Paw Energy,following:approximately 10,100 miles and approximately 4,400 miles of gathering pipelines withoperationscapacity owned, leased or contracted for in theWillistonMidcontinent andPowder River Basins; and - Crestone Energy, which owns: - 49% interest in Bighorn Gas Gathering,Rocky Mountain regions, respectively;11 active processing plants, withoperationsapproximately 1.7 Bcf/d of owned, leased or contracted processing capacity in thePowder River Basin; - 37% interest in Fort Union Gas Gathering,Midcontinent region and four active processing plants, withoperationsapproximately 94 MMcf/d of processing capacity in thePowder River Basin;Rocky Mountain region; and- 35% interest in Lost Creek Gathering, with operationsapproximately 89 MBbl/d and 11 MBbl/d of owned, leased or contracted natural gas liquids fractionation capacity in theWind River Basin. KNOWN TRENDS AND UNCERTAINTIESMidcontinent and Rocky Mountain regions, respectively.Our natural gas processing operations utilize straddle and field gas processing plants to extract natural gas liquids and remove water vapor and other contaminants from the raw natural gas stream. A straddle gas processing plant is situated on a pipeline system and relies on the pipeline’s natural gas throughput volume, which subjects the plant to increased supply risk as it is dependent upon the throughput of a single pipeline rather than several supply sources. Field gas processing plants gather raw natural gas from multiple producing wells.
Operating revenue for these assets is derived primarily from the following three types of contracts with natural gas producers:
• Keep-whole –Under keep-whole contracts, raw natural gas is processed and merchantable natural gas that contains the same amount of Btus as the raw natural gas contained is returned to the producer, keeping the producer whole on a Btu basis. Natural gas liquids extracted from raw natural gas are retained as the processing fee.
• Percent-of-proceeds – Under percent-of-proceeds contracts, a percentage of the natural gas and natural gas liquids gathered and processed is retained as payment for gathering and processing services. The producer may elect either to take its share of the natural gas and natural gas liquids in kind or receive its share of the proceeds from the sale of the commodities.
• Fee-based – Under fee-based contracts, services such as natural gas gathering, compression and/or processing are performed for a fee. Known Trends and Uncertainties –Supply –Natural gas supply is affected by rig availability, operating and maintenance capability and producer drilling activity, which is sensitive to commodity prices, geological success, available capital and regulatory control. Relatively
stronghigh natural gas and crude oil prices and favorable long-term projections of U.S. demand have continued to drive increasedproductiondrilling in both the Midcontinent and Rocky Mountain regions in 2006.In the Midcontinent region, the gathering and processing assets we acquired in the
WillistonAnadarko andPower RiverHugoton Basinsduringare well established. There is, however, excess processing capacity, particularly in thefirst quarterHugoton production region around the Bushton Plant, which does not have the ability to recover as much natural gas liquids, such as ethane, putting the plant at an economic disadvantage to cryogenic plants. We anticipate declines in certain fields that supply our gathering and processing operations will surpass new gas development from drilling activity in the Midcontinent region. Volumetric declines in the Midcontinent region and the potential loss of2006.gas processing customers to a competitor could result in the temporary idling of the Bushton Plant. We plan to invest approximately $56 million to expand our fractionation capabilities at Bushton in connection with the Overland Pass Pipeline Project. In addition, we are currently exploring alternatives to optimize processing and extraction in the Hugoton Basin which supplies the Bushton Plant.In the Williston Basin, we established a record for the number of well connections during the
first quarter ofsix months ended June 30, 2006, as a result of increased drilling activity. Transportation and refining capacity constraints for crude oil continued to only moderatelyimpactedimpact natural gas production in the WillistonBasin as expected.Basin. Further development of the Big George coals, located in the center of the Powder River Basin, resulted inincreasedgreater volumes during thefirst quarter ofsix months ended June 30, 2006, compared with the samequarterperiod last year for our wholly owned assets and joint venture interests in Bighorn Gas Gathering and Fort Union Gas Gathering.OPERATING RESULTS The Natural Gas Gathering and Processing segment reported income from continuing operations of $19.6 million for the first quarter ended March 31, 2006, an increase of $5.9 million, or 43%, compared with $13.7 million for the same quarter of 2005 primarily as a result of the following: - increased gathering and processing volumes in the Williston Basin; and - higher commodity prices realized on equityDemand –In recent years, crude oil, natural gas and natural gas liquids
derivedprices have been volatile due to market conditions. Storage injection and withdrawal rates as well as available storage capacity can also have an impact on commodity prices. We are exposed to market risk associated with adverse changes in commodity prices. Our primary exposure arises frompercentage-of-proceedsthe relative price differential between natural gas and natural gas liquids with respect to our keep-whole processing contracts and the sale of natural gas, natural gas liquids and condensate with respect to our percent-of-proceeds contracts.20To a lesser extent, we are exposed to the risk of price fluctuations and the cost of intervening transportation at various market locations. Our plant operations can be adjusted to respond to market conditions, such as demand for ethane. By changing the temperature and pressure at which raw natural gas is processed, within limits, more of a specific commodity that has the most favorable price or price spread can be produced.
Seasonality –Demand for gathering and processing services is typically aligned with the supply of natural gas, which generally flows at a relatively steady but gradually declining pace over time unless new reserves are added. Some products, however, are subject to weather-related seasonal demand. Cold temperatures typically increase demand for natural gas and propane, which are used to heat commercial and residential properties. Warm temperatures typically drive demand for natural gas used for gas-fired electric generation. During periods of peak demand for a certain commodity, prices for that product typically increase, which influences processing decisions.
Competition – The gathering and processing business is relatively fragmented despite significant consolidation in the industry. We compete for natural gas supplies with major integrated exploration and production companies, major pipeline companies and their affiliated marketing companies, national and local natural gas gatherers, and independent processors and marketers in the Midcontinent and Rocky Mountain regions.
Due to the unprecedented strength of the energy commodity market in the past two years, rates have become increasingly competitive. As a result, we may not be successful in obtaining new natural gas supplies to offset declines and may lose some existing supplies to competitors. We are responding to these industry conditions by making capital investments to improve plant processing flexibility and reduce operating costs, evaluating consolidation opportunities to maximize earnings, selling assets in non-core operating areas and renegotiating unprofitable contracts. Contracts covering approximately 42 percent of the volumes under keep-whole contracts contain language which effectively converts these contracts into fee-based contracts when the keep-whole spread is negative. It is our strategy to have such conditioning language in 75 percent of our keep-whole contracts by volume to mitigate the impact of an unfavorable gross processing spread and to renegotiate any under-performing gas purchase, gathering and processing contracts.
Selected Financial and Operating Results –The following tables set forth certain selected financial and operating results for our Gathering and Processing segment for the periods indicated.
Three Months Ended
June 30,Six Months Ended
June 30,Financial Results
2006 2005 (a) 2006 2005 (a) (Thousands of dollars) Natural gas liquids and condensate sales
$ 162,741 $ 26,581 $ 312,152 $ 51,045 Gas sales
152,238 23,806 370,899 46,098 Gathering, compression, dehydration and processing fees and other revenue
32,895 10,652 65,563 21,469 Cost of sales and fuel
254,526 35,466 563,405 67,931 Net margin
93,348 25,573 185,209 50,681 Operating costs
36,568 10,754 71,316 22,402 Depreciation and amortization
10,501 3,978 21,068 7,936 Operating income
$ 46,279 $ 10,841 $ 92,825 $ 20,343 Equity earnings from investments
$ 5,276 $ 4,251 $ 10,698 $ 8,255 Three Months Ended
June 30,Six Months Ended
June 30,Operating Information
2006 2005 (a) 2006 2005 (a) Total gas gathered(BBtu/d)
1,142 277 1,149 289 Total gas processed (BBtu/d)
993 91 958 89 Natural gas liquids sales(MBbl/d)
41 8 41 8 Natural gas liquids produced(MBbl/d)
53 8 52 8 Gas sales(BBtu/d)
288 45 298 43 Capital expenditures(Thousands of dollars)
$ 14,581 $ 4,180 $ 22,398 $ 8,127 Realized composite NGL sales price($/gallon)
$ 0.96 $ 0.86 $ 0.91 $ 0.85 Realized condensate sales price($/Bbl)
$ 59.83 $ — $ 58.65 $ — Realized natural gas sales price($/MMBtu)
$ 5.81 $ 5.87 $ 6.88 $ 5.90 Realized gross processing spread($/MMBtu)
$ 6.11 $ — $ 4.70 $ —
(a) Excludes results related to the acquisition of the ONEOK gathering and processing assets.
Six Months Ended
June 30,2006 2005 (a) Keep-whole
NGL shrink(MMBtu/d)
36,974 — Plant fuel(MMBtu/d)
4,861 — Condensate shrink(MMBtu/d)
3,234 — Condensate sales(Bbl/d)
664 — Percentage of total net margin
14 % 0 % Percent-of-proceeds
Wellhead purchases(MMBtu/d)
125,907 — NGL sales(Bbl/d)
7,131 2,199 Residue sales(MMBtu/d)
28,905 11,906 Condensate sales (Bbl/d)
1,115 — Percentage of total net margin
61 % 58 % Fee-based
Wellhead volumes(MMBtu/d)
1,149,272 289,214 Average rate($/MMBtu)
$ 0.22 $ 0.41 Percentage of total net margin
25 % 42 %
(a) Excludes results related to the acquisition of the ONEOK gathering and processing assets. Operating Results – The following financial analysis compares the results of the Gathering and Processing segment with the results of the segment for the respective periods in 2005. The 2005 results for the Gathering and Processing segment do not include the assets acquired by us from ONEOK.
The Gathering and Processing segment reported operating income of $46.3 million and $92.8 million for the three and six months ended June 30, 2006, respectively, compared with $10.8 million and $20.3 million, respectively, for the same periods last year primarily due to the acquisition of ONEOK’s gathering and processing assets.
Net margins increased $67.8 million and $134.5 million for the three and six months ended June 30, 2006, respectively, compared with the same periods last year primarily due to the following:
the acquisition of ONEOK’s gathering and processing assets, which accounts for $63.8 million and $126.2 million of net margins for the three and six months ended June 30, 2006, respectively;increased natural gas gathered volumes in the Rocky Mountain region; andincreased natural gas liquids revenue due to greater volumes and higher prices in the Rocky Mountain region.Operating costs and depreciation and amortization increased primarily due to the acquisition of ONEOK’s gathering and processing assets and gathering system expansions.
Comparative Analysis of Acquired Gathering and Processing Assets –We have provided the following information for additional analysis of the gathering and processing assets we acquired from ONEOK. The transactions with ONEOK were accounted for at historical cost; therefore, the information is comparable between the periods.
Net margins for the acquired assets increased $8.7 million and $18.8 million for the three and six months ended June 30, 2006, respectively, compared with the same periods last year primarily due to the following:
favorable commodity pricing for natural gas and natural gas liquids products on percent-of-proceeds contracts, net of hedging; andhigher realized gross processing spreads on keep-whole contracts; partially offset byreduced gathered and processed volumes driven by natural reserve declines around the systems and contract terminations.The gross processing spread of $6.11 per MMBtu for the second quarter of 2006 remained considerably higher than the previous five-year average of $1.86 per MMBtu. Based on current market conditions, the gross processing spread for the remainder of 2006 is expected to continue to be significantly higher than the previous five-year average.
Operating costs for the acquired assets increased $1.2 million and $2.3 million for the three and six months ended June 30, 2006, respectively, compared with the same period last year primarily due to higher employee and utilities costs.
Natural Gas Liquids Segment
Overview –As part of the ONEOK Transactions described in this section under “Recent Developments,” we acquired all of ONEOK’s natural gas liquids assets and created a new segment which consists solely of these newly acquired natural gas liquids assets.
The natural gas liquids assets we acquired consist of facilities that gather, fractionate and treat natural gas liquids and store natural gas liquids purity products primarily in Oklahoma, Kansas and Texas, as well as an 80 percent interest in fractionation and storage facilities located in Mont Belvieu, Texas. Approximately 90 percent of the pipeline-connected natural gas processing plants, which extract natural gas liquids from raw natural gas to meet natural gas pipeline quality specifications that limit the allowable liquid and Btu content in the natural gas stream, in Oklahoma, Kansas and the Texas panhandle are connected to the gathering systems that we acquired. The natural gas liquids operations gather these natural gas liquids and deliver them to our fractionators. The natural gas liquids are then separated into marketable components, including ethane/propane mix, propane, isobutane, normal butane and natural gasoline, through a fractionation process, to realize the greater economic value of the natural gas liquids components. The individual natural gas liquids components are then stored or distributed to petrochemical manufacturers, refineries and propane distributors. The fractionation and storage facilities we acquired are connected to the key natural gas liquids market centers in Conway, Kansas and Mont Belvieu, Texas by FERC-regulated interstate natural gas liquids pipelines, which are part of the pipelines and storage assets we acquired.
The assets that we acquired that are included in the Natural Gas Liquids segment consist of the following:
approximately 2,050 miles of natural gas liquids gathering pipelines;approximately 163 miles of natural gas liquids distribution pipelines;interests in four natural gas liquids fractionators with proportional operating capacity of approximately 379 MBbl/d;one isomerization unit; andsix owned or leased storage facilities in Oklahoma, Kansas and Texas with operating capacity of approximately 20.4 million barrels.Operating revenue
increased $15.9 million, or 28%,is derived primarily from three types of business activities:
• Exchange Services – Raw natural gas liquids are gathered, fractionated and treated and natural gas liquids purity products are stored and shipped for a fee;
• Optimization – The asset base, contract portfolio and market knowledge are used to optimize purity natural gas liquids products movement between Conway, Kansas and Mont Belvieu, Texas in order to capture location price spreads. Natural gas liquids storage facilities in the Midcontinent and Gulf Coast regions are used to capture seasonal price variances; and
• Isomerization –Normal butane is converted into the more valuable isobutane, which is used by the refining industry to upgrade the octane of motor gasoline at an isomerization unit in Conway, Kansas. Known Trends and Uncertainties –Supply –Supply for the
first quarterNatural Gas Liquids segment depends on the pace of crude oil and natural gas drilling activity by producers, the decline rate of existing production primarily in the Midcontinent region and the liquids content of the natural gas that is produced and processed. The Baker Hughes onshore drilling rig count in Oklahoma, Kansas and Texas increased by more than 13 percent during the six months endedMarch 31,June 30, 2006, compared with the rig count at December 31, 2005. The rig count in Wyoming, Colorado and Utah also increased by more than 16 percent over the samequarterperiod. The Mont Belvieu fractionation operation receives natural gas liquids from a variety of2005 dueprocessors and pipelines located in the Gulf Coast, West and Central Texas and the Rocky Mountain regions.The natural gas liquids gathering pipelines are also affected by operational or market-driven changes that impact the output of natural gas processing plants to
increased revenue from our Williston Basin operations,whichis derived primarily fromthey are connected. The differential between thesaleprice of natural gas liquids and the price of natural gas, particularly the differential between the price of ethane and the price of natural gas and the differential in the composite price of natural gas liquids and the price of natural gas, may influence processing plant output. This differential may impact the volume of natural gas and natural gas liquidsgatheredinjected or withdrawn from storage andprocessed under percentage-of-proceeds contracts. This increase more than offset decreased gathered volumes for our wholly owned Powder River Basin operations. Williston Basin inlet volumes increased 4 MMcf/d, or 7%, as a resultthe volume ofgrowth projects that were completed during the secondnatural gas andthird quarters of 2005. Optimization projects completed during the fourth quarter of 2005 resulted in improvednatural gas liquidsrecoveries. This, in turn, resulted in highershipped through the system, as processors periodically reject ethane from the natural gas liquidssalesstream. When the value of ethane is lower than the relative price of natural gas, some processors will leave the ethane in the natural gas stream instead of producing the ethane in a liquid form, known as ethane rejection, by temporarily adjusting their plant operations. During the first and second quarters of 2006, ethane values remained well above natural gas on a relative price basis, which resulted in maximum ethane recovery from processing plants that deliver to our natural gas liquids gathering pipelines.At June 30, 2006, more than 90 MBbl/d of new natural gas liquids volume was contracted to the system through 2008. Approximately 30 MBbl/d of existing volumes will be subject to renegotiation each year, over the next three years.
Demand –Demand for natural gas liquids and the ability of natural gas processors to successfully and economically sustain their operations impacts the volume of
32.6 million gallonsraw natural gas liquids produced from processing plants, thereby affecting the demand for natural gas liquids gathering and fractionation services. Natural gas and propane are subject to weather-related seasonal demand. Other products are affected by economic conditions and the demand associated with the various industries that utilize the commodity, such as isobutane and natural gasoline, which are used by the refining industry as blending stocks for motor fuel, and ethane, which is used by the petrochemical industry to produce chemical products, such as plastic, rubber and synthetic fiber.In recent years, crude oil, natural gas and natural gas liquids prices have been volatile due to market conditions. We are exposed to market risk associated with adverse changes in the price of natural gas liquids, the basis differential between the Midcontinent and Gulf Coast regions and the relative price differential between natural gas, natural gas liquids and individual natural gas liquids purity products, which impacts our natural gas liquids purchases, sales and storage revenue. When natural gas prices are higher relative to natural gas liquids prices, natural gas liquids production may decline, which could negatively impact our fractionation revenue. When the basis differential between the Midcontinent and Gulf Coast regions is narrow, optimization opportunity and margins may decline. Natural gas liquids storage revenue may be impacted by price volatility and forward pricing of natural gas liquids physical contracts versus the price of natural gas liquids on the spot market. During the first quarter of 2006,
an increaseGulf Coast region natural gas liquids prices were more favorable than Midcontinent region natural gas liquids prices by approximately $0.035 per gallon for ethane and approximately $0.024 per gallon for propane. During the second quarter of3.72006, Gulf Coast region natural gas liquids prices continued to be more favorable than Midcontinent region natural gas liquids prices by approximately $0.033 per gallon for ethane and approximately $0.009 per gallon for propane.Seasonality –Some natural gas liquids products produced by our natural gas liquids facilities are subject to weather-related seasonal demand, such as propane, which is used to heat residential properties during the winter heating season. Isobutane and natural gasoline, which are used by the refining industry as blending stocks for motor fuel, may also be subject to some seasonality when automotive travel is higher.
Competition –The natural gas liquids business we acquired competes with other fractionators and gatherers for natural gas liquids supplies in the Rocky Mountain, Midcontinent and Gulf Coast regions. We intend to make capital investments to improve plant processing flexibility and reduce operating costs so that we may compete effectively. Information about the Natural Gas Liquids segment projected capital expenditures is included in this section under “Liquidity and Capital Resources–Capital Expenditures.”
Selected Financial and Operating Results –The following tables set forth certain selected financial and operating results for our Natural Gas Liquids segment for the periods indicated.
Financial Results
Three Months Ended
June 30, 2006Six Months Ended
June 30, 2006(Thousands of dollars) Natural gas liquids and condensate sales
$ 827,368 $ 1,607,196 Storage and fractionation revenue
54,157 93,752 Cost of sales and fuel
830,980 1,616,660 Net margin
50,545 84,288 Operating costs
15,945 27,170 Depreciation and amortization
5,368 10,767 Operating income
$ 29,232 $ 46,351 Operating Information
Natural gas liquids gathered(MBbl/d)
213 203 Natural gas liquids sales(MBbl/d)
199 203 Natural gas liquids fractionated(MBbl/d)
333 309 Capital expenditures(Thousands of dollars)
$ 5,023 $ 7,977 Operating Results –The Natural Gas Liquids segment reported operating income of $29.2 million
gallons, or 13%,and $46.4 million for the three and six months ended June 30, 2006, respectively, as a result of the acquisition of ONEOK’s natural gas liquids assets. ONEOK acquired these natural gas liquids assets from Koch Industries, Inc. (Koch) in July 2005.Comparative Analysis of Acquired Natural Gas Liquids Assets –We have provided the following information for additional analysis of the natural gas liquids assets we acquired from ONEOK. The transactions with ONEOK were accounted for at historical cost; therefore, the information is comparable between the periods.
Net margins increased $43.4 million and $70.0 million for the three and six months ended June 30, 2006, respectively, compared with
28.9the same periods last year, primarily due to the additional revenue generated from the natural gas liquids assets ONEOK acquired from Koch, and, to a lesser extent, the impact of lower natural gas liquids marketing margins related to lower marketing fees and decreased sales volumes.Operating costs increased $12.9 million
gallonsand $21.8 million for the three and six months ended June 30, 2006, respectively, compared with the samequarterperiods lastyear. Volumesyear primarily due to the increased operating costs related to the acquisition of the natural gas liquids assets ONEOK acquired from Koch.Depreciation and amortization increased $5.3 million and $10.7 million for the three and six months ended June 30, 2006, respectively, compared with the same periods last year due to the acquisition of the natural gas liquids assets ONEOK acquired from Koch.
Pipelines and Storage Segment
Overview –As part of the ONEOK Transactions described in this section under “Recent Developments,” we acquired all of ONEOK’s pipeline and storage assets and created a new segment which consists solely of these newly acquired pipeline and storage assets.
The pipeline and storage assets we acquired gather and transport natural gas through intrastate natural gas transmission pipelines and natural gas liquids through FERC-regulated natural gas liquids gathering and distribution pipelines and operate non-processable natural gas gathering and natural gas storage facilities in Oklahoma, Kansas and Texas.
Our intrastate natural gas pipelines in Oklahoma access major natural gas producing areas, which enables natural gas and natural gas liquids to be moved throughout the state. In Texas, our intrastate natural gas pipelines are connected to the major natural gas producing areas in the Texas panhandle and the Permian Basin, which enables natural gas to be moved to the Waha Hub, where other pipelines may be accessed for transportation east to the Houston Ship Channel market and west to the California market. We also have intrastate natural gas pipelines that access the major natural gas producing area in south central Kansas.
Our regulated natural gas liquids gathering pipelines enable raw natural gas liquids gathered in Oklahoma, Kansas and the Texas panhandle to be delivered primarily to our fractionation facilities in Medford, Oklahoma and to our natural gas liquids distribution pipelines, which access two of the main natural gas liquids market centers in Conway, Kansas and Mont Belvieu, Texas.
The assets that we acquired that are included in the Pipelines and Storage segment consist of the following:
approximately 5,660 miles of intrastate natural gas gathering and transmission pipeline with peak transportation capacity of approximately 2.9 Bcf/d;approximately 2,420 miles of FERC-regulated natural gas liquids gathering and distribution pipelines with peak transportation capacity of approximately 355 MBbls/d; and11 underground natural gas storage facilities in Oklahoma, Kansas and Texas with active working gas capacity of approximately 51.6 Bcf.One of the natural gas storage facilities we acquired has been idle since 2001 following natural gas explosions and eruptions of natural gas geysers in Hutchinson, Kansas. Since that time, the Kansas Department of Health and Environment (KDHE) issued regulations related to storage activity not only at our
wholly owned Powder Riverfacility, but throughout Kansas. We are currently operating under the permit requirements filed with the KDHE that allow us to monitor the field while we complete the engineering, geological and economic studies necessary to determine the steps required to return the field to economical service and be in compliance with the new regulations.The majority of our operating revenue is derived from fee-based services provided to ONEOK and its affiliates. Our transportation contracts for our regulated natural gas and natural gas liquids pipelines are based upon rates stated in our tariffs. Tariffs specify the maximum rates customers can be charged, which can be discounted to meet competition if necessary, and the general terms and conditions for pipeline transportation service, which are established in FERC or appropriate state jurisdictional agency proceedings known as rate cases. In Texas and Kansas, natural gas storage service is a fee-based business that may be regulated by the state in which the facility operates and by the FERC for certain types of services. In Oklahoma, natural gas gathering and natural gas storage operations are not subject to rate regulation and have market-based rate authority from FERC for certain types of services.
Known Trends and Uncertainties –Supply –The supply of natural gas and natural gas liquids to the pipelines and storage assets currently depends on the pace of natural gas drilling activity by producers and the decline rate of existing production in the major natural gas production areas in the Midcontinent region, including the Anadarko Basin,
operations declined 32 MMcf/d, or 15%, forHugoton Basin, Central Kansas Uplift and Permian Basin. The Baker Hughes onshore drilling rig count in Oklahoma, Kansas and Texas increased by more than 13 percent during thefirst quarter ofsix months ended June 30, 2006, compared with the rig count at December 31, 2005. The rig count in Wyoming, Colorado and Utah also increased by more than 16 percent over the samequarterperiod.The natural gas liquids gathering pipelines are also affected by operational or market-driven changes that impact the output of
2005natural gas processing plants to which they are connected. The differential between the price of natural gas liquids and the price of natural gas, particularly the differential between the price of ethane and the price of natural gas and the differential in the composite price of natural gas liquids and the price of natural gas, may influence processing plant output. This differential may impact the volume of natural gas and natural gas liquids shipped through the system, as processors periodically reject ethane from the natural gas liquids stream. When the value of ethane is lower than the relative price of natural gas, some processors will leave the ethane in the natural gas stream instead of producing the ethane in a liquid form, known as ethane rejection, by temporarily adjusting their plant operations. During the first and second quarters of 2006, ethane values remained well above natural gas on a relative price basis, which resulted in maximum ethane recovery from processing plants that deliver to our natural gas liquids gathering pipelines.Demand –Demand for pipeline transportation service and natural gas storage is directly related to demand for natural gas and natural gas liquids products in the markets the pipelines and storage facilities serve, which is affected by the economy, natural gas and natural gas liquids price volatility and weather. The strength of the economy directly impacts manufacturing and industrial companies that rely on natural gas and natural gas liquids products. Volatility in the natural gas market can influence customers’ decisions related to natural gas storage injection and withdrawal activity. The effect of weather on the acquired pipelines and storage operations is discussed under “Seasonality.”
Exposure to market risk occurs when existing contracts expire and are subject to renegotiation with customers that have competitive alternatives and analyze the market price spread or basis differential between receipt and delivery points along the pipeline to determine their expected gross margin. The anticipated margin and its variability are important determinants of the transportation rate customers are willing to pay. We may also be exposed to market risk associated with the relative price differential between natural gas and natural gas liquids prices with respect to our natural gas liquids revenue. Natural gas storage revenue is impacted by the differential between forward pricing of natural gas physical contracts and the price of natural gas on the spot market. Our fuel costs and the value of the retained fuel in-kind are also impacted by adverse changes in the commodity price of natural gas.
Seasonality –Demand for natural gas is seasonal. Weather conditions throughout the United States can significantly impact regional natural gas supply and demand. High temperatures can increase demand for gas-fired electric generation to cool residential and commercial properties. Low precipitation levels can impact the demand for natural gas that is used to fuel irrigation activity in the Midcontinent region. Moderate winter temperatures can lead to a decline in the use of our transportation services due to reduced demand for natural gas. Cold temperatures can lead to greater demand for our transportation services due to increased demand for natural gas. As previously described for the Natural Gas Liquids segment, some natural gas liquids products are subject to weather-related seasonal demand and therefore transportation for these products are also subject to weather-related seasonal demand.
To the extent that pipeline capacity is contracted under firm service transportation agreements, revenue, which is generated from demand charges, is not impacted by seasonal throughput variations. However, when transportation agreements expire, seasonal demand can impact recontracting of firm service transportation capacity.
Natural gas storage is necessary to balance the relatively steady natural gas supply with the seasonal demand of residential, commercial and electric power generation users. While most of the storage capacity is contracted under term agreements, there is a seasonal market for capacity not under term agreements. In 2004, residential, commercial and electric power generation users consumed 65 percent of the total natural gas volume delivered that year according to the Energy Information Administration. Industrial users, who consumed the remaining 35 percent of the total natural gas volume delivered, generally demand a steady load of natural gas to operate their facilities, but will turn to alternative energy sources when it is not economical to use natural gas.
Competition –The natural gas and natural gas liquids pipelines and storage facilities compete with other pipeline companies and other storage facilities for the natural gas and natural gas liquids supply in the Midcontinent region and for markets in the Midcontinent and Gulf Coast regions. Competition among pipelines and natural gas storage facilities is based primarily on fees for service and proximity to natural gas supply areas and markets. Competition for natural gas transportation services continues to increase as the FERC and state regulatory bodies continue to encourage more competition in the natural gas markets.
Selected Financial and Operating Results –The following tables set forth certain selected financial and operating results for our Pipelines and Storage segment for the periods indicated.
Financial Results
Three Months Ended
June 30, 2006Six Months Ended
June 30, 2006(Thousands of dollars) Transportation and gathering revenue
$ 44,317 $ 90,132 Storage revenue
13,014 25,158 Gas sales and other revenue
1,940 6,893 Cost of sales and fuel
8,630 19,421 Net margin
50,641 102,762 Operating costs
18,083 34,873 Depreciation and amortization
7,558 15,141 Gain on sale of assets
— 988 Operating income
$ 25,000 $ 53,736 Equity earnings from investments
$ 25 $ 269 Operating Information
Natural gas transported(MMcf)
112,998 245,533 Natural gas liquids transported(MBbl/d)
208 201 Natural gas liquids gathered(MBbl/d)
58 57 Capital expenditures(Thousands of dollars)
$ 11,914 $ 15,490 Average natural gas price Midcontinent region ($/MMBtu)
$ 5.57 $ 6.40 Operating results –The Pipelines and Storage segment reported operating income of $25.0 million and $53.7 million for the three and six months ended June 30, 2006, respectively, as a result of the acquisition of ONEOK’s pipelines and storage assets.
Comparative Analysis of Acquired Pipelines and Storage Assets –The following information is provided for additional analysis of the pipelines and storage assets we acquired from ONEOK. The transactions with ONEOK were accounted for at historical cost; therefore, the information is comparable between the periods.
Net margins increased $19.4 million and $41.4 million for the three and six months ended June 30, 2006, respectively, compared with the same periods last year primarily due to the
diversion of 45 MMcf/d of low margin gatheredfollowing:additional revenue generated from the natural gasby one producer to its own system duringliquids gathering and distribution pipelines ONEOK acquired from Koch on July 1, 2005; andincreased natural gas transportation revenue from higher realized rates and higher volumes in thesecond quarter of 2005. However, volumes remained relatively flat for the first quarter of 2006 compared with the fourth quarter of 2005. We anticipatecommodity-based short-term business and anincreaseimproved fuel position; partially offset bylower natural gas storage revenue inour wholly owned Powder River volumes duringthe second quarter of 2006 as a result ofseveral system expansions that are currently underway. Better prices were realized on our saleslower injection volumes and commodity prices.Operating costs increased $6.0 million and $11.3 million for the three and six months ended June 30, 2006, respectively, compared to the same periods last year primarily due to increased operating expense associated with ONEOK’s acquisition of natural gas liquids gathering and distribution pipelines from Koch and higher employee-related expenses.
Interstate Natural Gas Pipelines Segment
Overview –The Interstate Natural Gas Pipelines segment, which transports natural gas
liquids retained through percentage-of-proceedsfrom the Western Canada Sedimentary Basin to the Midwestern U.S. along approximately 2,320 miles of pipelines with a design capacity of approximately 4.7 Bcf/d, consists of the following assets:50 percent partnership interest in Northern Border Pipeline;Midwestern Gas Transmission;Viking Gas Transmission; andGuardian Pipeline.In addition, as a result of the ONEOK Transactions, we acquired ONEOK’s interstate natural gas pipeline system, OkTex Pipeline Company, L.L.C., which consists of approximately 110 miles of small pipeline systems in Oklahoma, New Mexico and Texas.
In April 2006, we completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines. We and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline. An affiliate of TransCanada will become operator of the pipeline effective April 1, 2007. As a result, we deconsolidated Northern Border Pipeline, effective as of January 1, 2006, and reflect the pipeline as investment in unconsolidated affiliates on our balance sheet. Our share of Northern Border Pipeline’s operating results is reported as equity earnings from investments on our statement of income.
In April 2006, we acquired a 66 2/3 percent interest in Guardian Pipeline. As a result, we now own 100 percent of Guardian Pipeline. We consolidated Guardian Pipeline in the second quarter of 2006, effective January 1, 2006, instead of accounting for it as an investment under the equity method.
Operating revenue is derived from transportation contracts at rates that are stated in our tariffs. Tariffs specify the maximum rates we can charge our customers and the general terms and conditions for natural gas transportation service on our pipelines. Our pipelines’ tariffs also allow for services to be provided under negotiated and discounted rates. Transportation rates are established periodically in FERC proceedings known as a rate case. Our transportation contracts include specifications regarding the receipt and delivery of natural gas at points along the pipeline systems. The type of transportation contract, either firm or interruptible service, determines the basis by which each customer is charged.
Known Trends and Uncertainties –We continue to expect that Canadian natural gas export volumes in 2006 will remain near 2005 levels. We also continue to expect U.S. demand for natural gas in 2006 to be similar to 2005 levels. The Energy Information Administration projects that industrial demand in 2006 is increasing and will offset the reduced residential demand experienced during the 2005-2006 heating season as a result of warmer-than-normal temperatures.
An increase in natural gas throughput on the TransCanada pipeline system to Eastern U.S. markets, due to increased storage injections in Eastern Canada and lingering supply disruptions related to Hurricanes Katrina and Rita, caused fewer natural gas supplies to be available for transportation on our pipelines.
During the second quarter of 2006, demand for Canadian natural gas in the Western U.S. was much higher than expected primarily due to warmer-than-average temperatures in the Western U.S. The return of normal snowpack and heavier-than-average precipitation in the region during the 2005-2006 winter season were anticipated to cause gas-fired electric generation to be displaced with hydroelectric generation; however, the warmer temperatures created additional demand for gas-fired electric generation in addition to
higher processing volumes, contributed tohydroelectric generation. Demand in thesegment's increased operating revenue. The weighted average priceMidwestern U.S. during the second quarter of 2006 remained moderate.Natural gas storage injections and withdrawals in Western Canada also affect natural gas
realized, net of the effects of hedging, was $8.01 per MMBtuavailable for transportation on our pipelines. During the first quarter of 2006,comparedWestern Canada storage inventories were above average due to lower demand associated with$6.65 per MMBtu forthefirst quarter of 2005. The weighted average price of natural gas liquids realized, net ofwarm winter season. During theeffects of hedging, was $1.11 per gallon for the firstsecond quarter of 2006, Western Canada storage injections slightly declined on a relative basis to the prior year due to the increased throughput to eastern markets. At June 30, 2006, working gas in storage was comparable to last year’s high levels, which we believe will favorably impact demand for transportation service in the third quarter of 2006.Northern Border Pipeline’s contracted capacity averaged approximately 87 percent during the three months ended June 30, 2006, compared with
$0.88 per gallonaverage contracted capacity of 85 percent for thefirst quartersame period last year. At June 30, 2006, 84 percent of2005. Product purchases, which reflect the amounts we paidNorthern Border Pipeline’s capacity was contracted on a firm basis through December 31, 2006. We anticipate that 2006 demand for Northern Border Pipeline’s capacity will be similar toproducers for raw2005 demand based on our expectations of Canadian natural gasincreased $11.6supply and demand for natural gas in the markets that we serve. We believe that discounting transportation rates on a short-term basis may be necessary to maximize revenue and anticipate that the level of discounting in the future may vary from 2005 depending upon current market conditions. Guardian Pipeline was 96 percent contracted for the six months ended June 30, 2006. At June 30, 2006, 98 percent of Guardian Pipeline’s capacity was contracted on a firm basis through December 31, 2006.Selected Financial and Operating Results –The following tables set forth certain selected financial and operating results for our Interstate Natural Gas Pipelines segment for the periods indicated.
Three Months Ended
June 30,Six Months Ended
June 30,Financial Results
2006 2005 2006 2005 (Thousands of dollars) Transportation revenue
$ 23,230 $ 82,541 $ 48,783 $ 179,186 Cost of sales and fuel
— — — — Net margin
23,230 82,541 48,783 179,186 Operating costs
8,384 22,028 17,122 46,466 Depreciation and amortization
3,613 16,598 7,362 33,167 Gain on sale of asset
113,877 — 113,877 — Operating income
$ 125,110 $ 43,915 $ 138,176 $ 99,553 Equity earnings from investments
$ 12,703 $ 167 $ 38,850 $ 640 Minority interest
$ 385 $ 8,629 $ 1,866 $ 20,818
Three Months Ended
June 30,Six Months Ended
June 30,Operating Information (a)
2006 2005 2006 2005 Natural gas delivered(MMcf)
257,482 257,171 562,761 563,864 Natural gas average throughput(MMcf/d)
2,878 2,889 3,172 3,193 Capital expenditures(Thousands of dollars)
$ 3,783 $ 7,656 $ 6,905 $ 13,066
(a) Includes 100 percent of the volumes for joint venture investments. Operating results –The Interstate Natural Gas Pipelines segment reported operating income of $125.1 million and $138.2 million for the
first quarterthree and six months endedMarch 31,June 30, 2006, respectively, compared with $43.9 million and $99.6 million for the samequarter of 2005. Product purchases represented 60% of operating revenue forperiods last year. During thefirstsecond quarter of 2006,compared with 56%we sold a 20 percent partnership interest in Northern Border Pipeline and recorded a gain on sale ofoperating revenueapproximately $113.9 million. Operating income for thesame quarterthree and six months ended June 30, 2005, included $38.8 million and $89.8 million, respectively, related to Northern Border Pipeline, which is no longer consolidated as of2005January 1, 2006. The segment’s operating income increased $4.7 million and $10.0 million for the three and six months ended June 30, 2006, respectively, due todeclining percentage-of-proceeds contract marginsthe consolidation of Guardian Pipeline as a result of our acquisition of the remaining 66 2/3 percent interest.Transportation revenue decreased for the three and six months ended June 30, 2006, as a result of the deconsolidation of Northern Border Pipeline, partially offset by the consolidation of Guardian Pipeline. Transportation revenue for the three and six months ended June 30, 2005, includes $69.8 million and $152.6 million, respectively, related to Northern Border Pipeline, which is no longer consolidated as of January 1, 2006. The segment’s transportation revenue increased
competition. Equity earnings of unconsolidated affiliates increased $1.4$8.5 million and $17.8 million for thefirst quarterthree and six months endedMarch 31,June 30, 2006,compared with the same quarter of 2005, primarilyrespectively, due toincreased volumes inthePowder River Basin, which were partially offset by decreased volumes inconsolidation of Guardian Pipeline.Equity earnings from investments of $12.7 million and $38.9 million for the
Wind River Basin. In addition, since August 2005, we increasedthree and six months ended June 30, 2006, respectively, represent our interest inFort Union Gas GatheringNorthern Border Pipeline that is no longer consolidated as of January 1, 2006. Equity earnings from investments of $0.2 million and $0.6 million for the three and six months ended June 30, 2005, respectively, represent our 33 1/3 percent interest in Guardian Pipeline that is consolidated as of January 1, 2006.Minority interest for the three and six months ended June 30, 2006, represents the 66 2/3 percent interest in Guardian Pipeline that we did not own until we acquired these interests in April 2006. Minority interest for the three and six months ended June 30, 2005, represents the 30 percent interest in Northern Border Pipeline owned by TC PipeLines when Northern Border Pipeline’s results were consolidated.
Regulatory Developments –In November 2005, Northern Border Pipeline filed a rate case with the FERC as required by the provisions of the settlement of its last rate case. The rate case filing proposes, among other things, a 7.8 percent increase to
37% comparedNorthern Border Pipeline’s revenue requirement; a change to its rate design approach with33.3% duringa supply zone and market area utilizing a fixed rate per dekatherm and a dekatherm-mile rate, respectively; a compressor usage surcharge primarily to recover costs related to powering electric compressors; an increase in thefirst quarterdepreciation rate for transmission plant; the implementation of a short-term rate structure on a prospective basis; and the continued inclusion of income taxes in the rate calculation.In December 2005, the FERC issued an order that identified issues that were raised in the proceeding and accepted the proposed rates, but suspended their effectiveness until May 1, 2006. Since that time, the new rates have been collected subject to refund until final resolution of the rate case. The FERC also issued a procedural schedule which set a hearing commencement date of October 4, 2006, with an initial decision scheduled for February 2007. On May 31, 2006, the FERC staff and certain interveners in the case filed their testimony. Settlement discussions are ongoing.
Other
Black Mesa –Black Mesa, which was part of our former Coal Slurry Pipeline segment, consisted of a pipeline that was designed to transport crushed coal suspended in water along 273 miles of pipeline that originates at a coal mine in Kayenta, Arizona and terminates at Mohave Generating Station (Mohave) in Laughlin, Nevada. The coal slurry pipeline was the sole source of fuel for Mohave and was fully contracted to Peabody Western Coal until December 31, 2005.
OTHERThe water used by the coal slurry pipeline was supplied from an aquifer in the Navajo Nation and Hopi Tribe joint use area until December 31, 2005.Under a consent decree, Mohave agreed to install pollution control equipment by December 2005. However, due to the uncertainty surrounding the ongoing source of water supply and coal supply negotiations, Southern California Edison Company (SCE), a 56 percent owner of Mohave, filed a petition before the California Public Utility Commission (CPUC) requesting that they either recognize the end of Mohave’s coal-fired operations on December 31, 2005, or authorize expenditures for pollution control activities required for future operation. In December 2004, the CPUC authorized SCE to make the necessary expenditures for critical path investments and directed interested parties to continue working toward resolution of essential water and coal supply issues.
On December 31, 2005, Black
Mesa'sMesa’s transportation contract with the coal supplier oftheMohaveGenerating Stationexpired and our coal slurry pipeline operations were shut down as expected.UnderPending resolution of the issues confronting Mohave, its owners requested that Black Mesa remain prepared to resume coal slurry operations. Pursuant to an agreement reached with SCE, Black Mesa was reimbursed for certain of its standby costs. In June 2006, SCE completed aconsent decree,comprehensive study of theMohave Generating Station must complete significant pollution control investments to operate in the future. In addition, issues surrounding the use of an alternativewater source, coal supply and transportation issues and announced that it would no longer pursue the resumption of plant operations. As a result, Black Mesa is no longer receiving reimbursement for its standby costs. SCE and the other Mohave co-owners are jointly exploring options for Mohave, including the possibility of selling the plant. SCE is also conducting discussions with all involved parties regarding Mohave’s future.In preparation of our financial statements for the three months ended June 30, 2006, we reassessed our coal slurry pipeline
must be resolved.operation as a result of the developments described above. We concluded that the likelihood of Black Mesais workingresuming operations was significantly reduced and a goodwill and asset impairment of $8.4 million and $3.4 million, respectively, would need toresolve coal slurry transportation issuesbe recorded as depreciation andinterested parties continue to negotiate water and coal supply issues so that operations may resumeamortization in thefuture. If these issued are resolved and the project receives a favorable Environmental Impact Statement, portions of the pipeline would be modified or reconstructed beginning in late 2008 and 2009, supported by revenue from a new transportation contract, for an anticipated in-service date during 2010. Black Mesa reported an operating loss of $0.1 million for the first quarter ended March 31, 2006, compared with operating income of $0.9 million for the samesecond quarter of2005. We expect the impact associated with the shutdown will be a2006. The reductionofto net incomeof approximately $6 million in 2006 compared with 2005, which includes approximately $2 million to $4 million of operations and maintenance expense we expect to incur related to standby costs. Negotiations continue with various parties that may result in the recovery of some of these standby costs. 21after taxes was $10.5 million. LIQUIDITY AND CAPITAL RESOURCES
OVERVIEWOverview –Our principal sources of liquidity include cash generated from operating activities and bank credit facilities. We fund our operating expenses, debt service and cash distributions to our limited and general partners primarily with operating cash flow.
Part of our growth strategy is to expand our existing businesses and strategically acquire related businesses that strengthen and complement our existing assets. Capital resources for acquisitions and maintenance and growth expenditures are funded by a variety of sources, including cash generated from operating activities, borrowings under bank credit facilities, issuance of senior unsecured notes or sale of additional limited partner interests. Our ability to access capital markets for debt and equity financing under reasonable terms depends on our financial condition, credit ratings and market conditions.
We believe that our ability to obtain financing
at reasonable ratesand our history of consistent cash flow from operating activities provide a solid foundation to meet our future liquidity and capital resource requirements.DEBT AND CREDIT FACILITIESRevolving Credit Agreements–At June 30, 2006, we had borrowings of $311 million and a $15 million letter of credit outstanding under our $750 million revolving credit agreement. We were in compliance with the covenants that are described in Note 4 of the consolidated financial statements. The
following table summarizes our and Northern Border Pipeline's debt and credit facilities outstanding as of March 31, 2006:
PAYMENTS DUE BY PERIOD ---------------------- LESS THAN LONG-TERM TOTAL ONE YEAR PORTION ---------- --------- ---------- (In thousands)Northern Border Pipeline: $175 million credit agreement due 2010, $ 7,000 $ 7,000 $ -- average 5.16% (a) 6.25% senior notes due 2007 150,000 -- 150,000 7.75% senior notes due 2009 200,000 -- 200,000 7.50% senior notes due 2021 250,000 -- 250,000 Northern Border Partners: $750 million credit agreement due 2011, average 7.75% (a) 231,000 231,000 -- 8.875% senior notes due 2010 250,000 -- 250,000 7.10% senior notes due 2011 225,000 -- 225,000 ---------- -------- ---------- Total $1,313,000 $238,000 $1,075,000 ========== ======== ==========(a) Northern Border Partners and Northern Border Pipeline are each required to pay a facility fee of 0.125% and 0.075%, respectively,average interest rate on theprincipal commitment amountamounts outstanding at June 30, 2006, was 5.75 percent.In April 2006, we acquired the remaining interest and now own 100 percent of
their credit agreements. REVOLVING CREDIT AGREEMENTSGuardian Pipeline. At June 30, 2006, Guardian Pipeline had outstanding borrowings of $3.0 million under its $10 million revolving note agreement with an average interest rate of 6.60 percent, due November 8, 2007.Bridge Facility–In
MarchApril 2006, we entered into a$750 million amended and restated revolving$1.1 billion, 364-day credit agreement (Bridge Facility) withcertain financial institutions and terminated our existing $500 million revolving credit agreement. The weighted average interest rate on amounts outstandinga syndicate of banks to finance a portion of the acquisition of the ONEOK Energy Assets described in this section underthese agreements during the first quarter of 2006 was 5.40%.“Recent Developments.” At our option, the interest rate applied totheamounts outstanding under thecredit agreementBridge Facility may be thelender'slender’s base rate or an adjustedLondon Interbank Offered Rate (LIBOR)LIBOR plus a spread that is based on our long-term unsecured debt ratings. Weare requiredmust make mandatory prepayments on any outstanding balance under the Bridge Facility with the net cash proceeds of any asset disposition in excess of $10 million, or from the net cash proceeds received from any issuance of equity or debt having a term greater than one year. Amounts outstanding under the Bridge Facility must be repaid on or before April 5, 2007. We intend topay interest onrefinance theoutstanding amounts periodically. The term ofBridge Facility with long-term financing prior to theagreement is five years, at which time we are required to pay off all outstanding amounts.maturity date.We are required to comply with certain financial, operational and legal covenants, including the maintenance of an EBITDA (net income plus minority interests in net income, interest expense, income taxes and depreciation and amortization) to interest expense ratio of greater than 3 to 1 and a debt to adjusted EBITDA (EBITDA adjusted for pro forma operating results of acquisitions made during the year) ratio of no more than 4.75 to 1. If we consummate one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of debt to adjusted EBITDA will be increased to 5.25 to 1 for two calendar quarters following the acquisition. If we breach any of these covenants, amounts outstanding under the Bridge Facility may become immediately due and
payable immediately. 22payable. At
March 31,June 30, 2006, we had outstanding borrowings of$231 million$1.05 billion under our$750 million revolving credit agreementBridge Facility and we were in compliance with its covenants.On April 6, 2006, we borrowed an additional $75 million to fund working capital related to certain of the businesses acquired pursuant to the ONEOK transactions described in this section under "Recent Developments." At May 4, 2006, we had outstanding borrowings of $306 million and a $15 million letter of credit under our agreement. We may from time to time draw on the amended and restated credit agreement to meet working capital requirements, which borrowings are intended to be repaid with cash generated from operations. As of March 31, 2006, Northern Border Pipeline had outstanding borrowings of $7.0 million under its $175 million revolving credit agreement and was in compliance with its covenants.Theweightedaverage interest raterelated toon theborrowings on Northern Border Pipeline's credit agreementamount outstanding at June 30, 2006, was5.16% at March 31, 2006. BRIDGE FACILITY In April 2006, we entered into, and borrowed $1.05 billion under a $1.1 billion, 364-day credit agreement with several financial institutions to complete the transactions with ONEOK described in this section under "Recent Developments." At our option, the interest rate applied to amounts outstanding under the bridge facility may be the lender's base rate or an adjusted LIBOR plus a spread that is based on our long-term unsecured debt ratings. We must make mandatory prepayments with the net cash proceeds of any asset disposition in excess of $10 million or from the net cash proceeds received from any issuance of equity or debt having a term greater than one year. Amounts outstanding under the agreement must be repaid on or before April 5, 2007. We are required to comply with certain financial, operational and legal covenants, including the maintenance of an EBITDA to interest expense ratio of greater than 3 to 1 and a debt to adjusted EBITDA ratio of no more than 4.75 to 1. If we consummate one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of debt to adjusted EBITDA will be increased to 5.25 to 1 for two calendar quarters following the acquisition. If we breach any of these covenants, amounts outstanding under the bridge facility may become immediately due and payable. DEBT SECURITIES In March 2006, we redeemed all of the outstanding Viking Gas Transmission Series A, B, C and D senior notes, due in 2008 through 2014, at a premium of $3.6 million.5.67 percent.Debt Securities–In April 2006, we acquired the remaining interest and now own
100%100 percent of Guardian Pipeline.As of May 4,At June 30, 2006, Guardian Pipeline hadapproximately $155 million ofsenior notesoutstanding;outstanding of approximately $152 million. The interest rates on the notes range from7.61%7.61 percent to8.27%,8.27 percent, with an average rate of7.85%. We anticipate issuing fixed-rate senior notes to repay borrowings under our $1.1 billion, 364-day credit facility prior to7.85 percent on theApril 2007 termination date of the credit agreement. EQUITY ISSUANCESamounts outstanding at June 30, 2006.Equity Issuances–In April 2006, we amended our
Partnership Agreementpartnership agreement to provide for the issuance of Class B limited partner units and issued36,494,126approximately 36.5 Class B limited partner units to ONEOKin exchange for allas part ofits gathering and processing and pipelines and storage assets in a transactionthe ONEOK Transactions described in this section under"Recent“Recent Developments."” The new class of equity securities is entitled to the same distribution rights as our outstanding common units, but has limited voting rights andwill beis subordinated to the common units with respect to the minimum quarterly distribution. The number of Class B units issued was determined by using the average closing price of our common units for the 20 trading days prior to the signing of the Contribution Agreement between ONEOK andus.us on February 14, 2006. The Class B limited partner units were issued on April 6, 2006.We will hold a special election for holders of common units as soon as practical but within 12 months, subject to extension, of issuing the Class B units, to approve the conversion of the Class B units into common units and certain amendments to our MLP Partnership Agreement. The proposed amendments would grant voting rights for common units held by our general partner if a vote is held to remove our general partner and require fair market value compensation for the general partner interest if the general partner is removed.
If the common unitholders do not approve the conversion and the amendments, the Class B unit distribution rights will increase to
115%115 percent of thedistributioncash distributions paid on the common units. If the conversion and the amendments are approved by the common unitholders, the Class B units will convert into common units on a one-for-one basis.23CASH FLOW FROM OPERATING, INVESTING AND FINANCING ACTIVITIES OPERATING ACTIVITIESIf the common unit holders vote to remove ONEOK or its affiliates as our general partner at any time prior to the approval of the conversion and certain amendments to the MLP Partnership Agreement, the Class B unit distribution rights will continue to be subordinated in the manner described above unless and until the conversion described above has been approved, and the amount payable on such Class B units would increase to 125 percent of the cash distributions payable with respect to the common units.Cash Flow Analysis
Operating Activities –Cash provided by operating activities was
$70.2$342.6 million for thethreesix months endedMarch 31,June 30, 2006, compared with$67.1$111.3 million for the samequarter of 2005.period last year. Cash provided by operating activities increasedduringfor thefirst quartersix months ended June 30, 2006, primarily due to the acquisition of the ONEOK Energy Assets. Changes in components of working capital, net of the effect of the acquisition, increased operating cash flow by $101.8 million for the six months ended June 30, 2006,primarilycompared with a decrease of $5.9 million for same period last year as a result ofthe following: -decreased accounts receivable and increasedcash receipts from our natural gas gatheringaccounts payable andprocessing operations as a result of higher operating revenue during the quarter; and - increased distributions received from unconsolidated affiliates of $8.0 million, $5.5 million of which we received from Lost Creek Gathering to true-up our throughput volume allocation. The increased cash provided by operating activities during the first quarter of 2006 was partially offset by the following: - reduced cash flow of $3.2 million related to the shutdown of our coal slurry operations on December 31, 2005; and - increased interest expense of $3.2 million primarily due to higher interest rates. INVESTING ACTIVITIEScommodity exchange payable.Investing Activities –Cash used in investing activities was
$18.4 million$1.2 billion for thethreesix months endedMarch 31,June 30, 2006, compared with$11.3$24.6 million for the samequarterperiod last year. The increased use of cash during thefirst quarter ofsix months ended June 30, 2006, was primarily due tohigher growththe following:the acquisition of the ONEOK Energy Assets for approximately $1.35 billion;
• the acquisition of a 66 2/3 percent interest in Guardian Pipeline for approximately $77 million; payment to Williams for initial capital expenditures incurred of$8.3$11.4 millionby the Interstate Natural Gas Pipeline segment, $6.7 million of which wasrelated to the Overland Pass Pipeline Company natural gas liquids pipeline joint venture;increased capital expenditures primarily related to the ONEOK Energy Assets of $43.5 million; andan equity contribution to Northern Border PipelineChicago III Expansion Projectof $7.2 million; partially offset bythe sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million.During the six months ended June 30, 2006, we used borrowings from our Bridge Facility and
$2.4revolving credit agreement and cash provided by operating activities to fund our investing activities.Financing Activities –Cash provided by financing activities was $856.8 million for the six months ended June 30, 2006, compared with cash used by financing activities of $111.4 million for the same period last year.
Cash distributions to our general and limited partners for the six months ended June 30, 2006, increased $4.9 million compared with the same period last year due to the increased available cash as a result of the ONEOK Transactions described in this section under “Recent Developments.” We increased our cash distribution by $0.08 per unit to $0.88 per unit for the first quarter of 2006. Our cash distributions to our limited and general partners were $77.9 million and $6.8 million, respectively, for the six months ended June 30, 2006.
Distributions to minority interests for the six months ended June 30, 2006, decreased $31.8 million compared with the same period last year primarily due to the deconsolidation of Northern Border Pipeline. Distribution to minority interest for the six months ended June 30, 2005, includes distributions related to TC PipeLines’ 30 percent interest in Northern Border Pipeline prior to the sale.
We reported cash flow retained by ONEOK of $177.0 million, which represents the cash flows generated from the first quarter of 2006 for the ONEOK Energy Assets prior to the acquisition.
The net change in our borrowings was net borrowings of $1.1 billion for the six months ended June 30, 2006 compared with net borrowings of $4.3 million for the same period last year. During the second quarter of 2006, we borrowed $1.05 billion under our Bridge Facility to finance a portion of the acquisition of the ONEOK Energy Assets and $77 million under our revolving credit agreement to acquire the 66 2/3 percent interest in Guardian Pipeline.
Capital Expenditures –As a result of the acquisition of the ONEOK Energy Assets described in this section under “Recent Developments,” our projected capital expenditures have increased to include growth and maintenance capital expenditures related to the acquired assets. We classify expenditures that are expected to generate additional revenue or significant operating efficiencies as growth capital expenditures. Any remaining capital expenditures are classified as maintenance capital expenditures. The following table summarizes our consolidated projected growth and maintenance capital expenditures for 2006 as of June 30, 2006:
2006 Projected Capital Expenditures
Growth Maintenance Total (Millions of dollars) Gathering and Processing
$ 66 $ 17 $ 83 Natural Gas Liquids
20 17 37 Pipelines and Storage
111 14 125 Interstate Natural Gas Pipelines
35 13 48 Total projected capital expenditures
$ 232 $ 61 $ 293 In May 2006, we entered into an agreement with a subsidiary of The Williams Companies, Inc. (Williams) to form a joint venture called Overland Pass Pipeline Company, described in this section under “Recent Developments.” The pipeline project is estimated to cost approximately $433 million. In addition, we plan to invest approximately $173 million to expand our existing fractionation capabilities and the capacity of our natural gas liquids distribution pipelines. Financing for both projects may include a combination of short- or long-term debt or equity. In 2006, we estimate that we will spend approximately $114 million related to the project.
Other significant projected growth expenditures for 2006 include approximately $25 million related to the Midwestern Gas Transmission Eastern Extension Project and approximately $8 million related to the Guardian Pipeline II Project.
LowerAdditional information about these projects is included under Item 1, “Business–Narrative Description of Business–Interstate Natural Gas Pipelinesegment maintenance expendituresSegment,” in our Annual Report on Form 10-K for the year ended December 31, 2005.Commitments and
investmentsContingenciesContractual Obligations –The following table sets forth our contractual obligations related to debt, operating leases and other long-term obligations as of June 30, 2006, and reflects the deconsolidation of Northern Border Pipeline due to the sale of a 20 percent interest in
unconsolidated affiliatesthe pipeline, consolidation of Guardian Pipeline due to the acquisition of a 66 2/3 percent interest in the pipeline and additional contractual obligations resulting from the ONEOK Transactions. Additional information about these transactions, which occurred during thefirstsecond quarter of 2006,comparedis included in this section under “Recent Developments.”
Payments Due by Period Contractual Obligations
Total 2006 2007 2008 2009 2010 Thereafter (Thousands of dollars) ONEOK Partners
$1.1 billion credit agreement
$ 1,050,000 $ — $ 1,050,000 $ — $ — $ — $ — $750 million credit agreement
311,000 311,000 — — — — — Senior notes – 8.875%
250,000 — — — — 250,000 — Senior notes – 7.10%
225,000 — — — — — 225,000 Guardian Pipeline
$10 million credit agreement
3,000 — 3,000 — — — — Senior notes – various
151,537 5,965 11,931 11,931 11,931 11,930 97,849 Interest payments on debt
298,129 55,090 64,822 48,981 48,043 35,088 46,105 Operating leases
81,080 7,955 14,501 13,695 12,294 12,218 20,417 Purchase commitments, rights of way and other
86,229 3,603 73,981 1,975 1,787 1,746 3,137 Firm transportation contracts
43,994 5,878 11,659 11,691 11,087 3,679 — Total
$ 2,499,969 $ 389,491 $ 1,229,894 $ 88,273 $ 85,142 $ 314,661 $ 392,508 Operating Leases– Our operating leases include office space, vehicles and equipment.
Other Long-Term Obligations – Firm transportation agreements with
the same quarter last year partially offset the Interstate Natural Gas Pipeline segment's increased growth expenditures. During the first quarter of 2006, we also used operating cash, borrowings fromourcredit facilityRocky Mountain region gathering andequity contributions from our minority interest holder to fund our investing activities. FINANCING ACTIVITIES Cash used in financing activities was $76.2 million for the three months ended March 31, 2006, compared with $52.4 million for the same quarter of 2005. Distributions to minority interests during the first quarter ended March 31, 2006, decreased $2.7 million compared with the same quarter of 2005 primarily due to Northern Border Pipeline's lower net income in the fourth quarter of 2005. Northern Border Pipeline received equity contributions of $3.1 million from its minority interest holder during the first quarter of 2006 for its shareprocessing joint ventures require minimum monthly payments. As part of theequity fundingONEOK Transactions, we acquired contractual rights to process natural gas at the Bushton, Kansas processing plant (Bushton Plant) that is leased by a subsidiary of ONEOK, ONEOK Bushton Processing, Inc. (OBPI). Our Processing and Services Agreement with ONEOK and OBPI sets out the terms by which OBPI will provide processing and relatedtoservices at theChicago III Expansion Project. The net change in our long-term borrowings wasBushton Plant through 2012. In exchange for such services, we will pay OBPI for all direct costs and expenses of operating the Bushton Plant, including reimbursement of arepaymentportion of$22.0 million forOBPI’s obligations under equipment leases covering thefirst quarter of 2006 compared with net borrowings of $3.7 million for the same quarter last year. We borrowed $197 million to pay the outstanding balance of our existing $500 million revolving credit agreement and terminated that agreement. We borrowed an additional $33 million under our amended and restated revolving credit agreement and redeemed all of the outstanding Viking Gas Transmission Series A, B, C and D senior notes and paid a premium of $3.6 million. COMMITMENTS AND CONTINGENCIES CASH DISTRIBUTIONSBushton Plant.Cash Distributions –We distribute
100%100 percent of our available cash, which generally consists of all cash receipts less adjustments for cash disbursements and net change to reserves, to our general and limited partners. Our income is allocated to the generalpartnerspartner and limited partners according to their partnership percentages of2%2 percent and98%,98 percent, respectively, after the effect of any incremental income allocations for incentive distributions to the generalpartners. 24partner. In April 2006, we increased our cash distribution by $0.08 per unit to $0.88 per unit for the first quarter of 2006,
payablewhich was paid on May 15, 2006, to unitholders of record as of April 28, 2006.LEGALIn July 2006, we increased our cash distribution by $0.07 per unit to $0.95 per unit for the second quarter of 2006, payable on August 14, 2006, to unitholders of record as of July 31, 2006.Legal –Various legal actions that have arisen in the ordinary course of business are pending. We believe that the resolution of these issues will not have a material adverse impact on our results of operations or financial position.
ENVIRONMENTALEnvironmental Liabilities –Our operations are subject to extensive federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to the protection of the
environment.environment, including air emissions, water quality, wastewater discharges, solid wastes and hazardous material and substance management. These laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws and regulations can result in substantial penalties, enforcement actions and remedialliabilities. We believeliabilities that could be material to theresolutionresults ofvarious environmental issues that have arisenoperations. If an accidental leak or spill of hazardous materials occurs from our lines or facilities, in theordinary courseprocess ofbusiness will nottransporting natural gas or natural gas liquids, or at any facility that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including investigation and clean up costs, which could materiallyimpactaffect our results of operations and cash flows. In addition, emission controls required under the Federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our business, financial condition and results of operations.Our overall expenditures for environmental evaluation and remediation to date have not been significant in relation to the results of operations and there were no material effects upon earnings during the three and six months ended June 30, 2006 related to compliance with environmental regulations.
RECENT ACCOUNTING PRONOUNCEMENTS
In December 2004, the FASB issued SFAS No. 123R,
"Share-Based Payments,"“Share-Based Payment” (SFAS No. 123R), which requires companies to expense the fair value of share-based payments and includes changes related to the expense calculation for share-based payments.Northern PlainsONEOK Partners GP and NBP Services adopted SFAS No. 123R as of January 1, 2006, andwillcharge us for our proportionate share of theexpenserecordedby Northern Plains and NBP Services.expense. The impact of adopting SFAS No. 123R does not have a material impact on our results of operations or financial position.In September 2005, the FASB ratified the consensus reached in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (EITF 04-13). EITF 04-13 defines when a purchase and a sale of inventory with the same party that operates in the same line of business should be considered a single nonmonetary transaction. EITF 04-13 is effective for new arrangements that a company enters into in periods beginning after March 15, 2006. We completed our review of the applicability of EITF 04-13 to our operations and determined that it did not have a material impact on our results of operations or financial position.
FORWARD-LOOKING STATEMENTS
TheSome of the statements contained and incorporated in this
quarterly report thatQuarterly Report on Form 10-Q arenot historical information, includingforward-looking statements. The forward-looking statementsconcerningrelate to: anticipated financial performance; management’s plans and objectivesof managementfor futureoperations, economic performance or related assumptions, areoperations; business prospects; outcome of regulatory and legal proceedings; market conditions and other matters. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-lookingstatements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act.statements.Forward-looking statements
mayinclude the items identified in the preceding paragraph, the information concerning possible or assumed future results of our operations and other statements contained or incorporated in this Quarterly Report on Form 10-Q identified by words such as"anticipate," "estimate," "expect," "project," "intend," "plan," "believe," "should"“anticipate,” “estimate,” “plan,” “expect,” “forecast,” “intend,” “believe,” “projection” or “goal.”You should not place undue reliance on forward-looking statements. Known and unknown risks, uncertainties and other
wordsfactors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements. Those factors may affect our operations, markets, products, services andterms of similar meaning. Although we believe that our expectations regarding future events are based on reasonableprices. In addition to any assumptionswe can give no assurance that our goals will be achieved. Importantand other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, theforward-looking statements include: -following:the effects of weather and other natural phenomena on our operations, demand for our services and energy prices;-competition from other U.S. and Canadian energy suppliers and transporters as well as alternative forms of energy;-the timing and extent of changes in commodity prices for natural gas, natural gas liquids, electricity and crude oil;-impact on drilling and production by factors beyond our control, including the demand for natural gas and refinery-grade crude oil;producers'producers’ desire and ability to obtain necessary permits; reserve performance; and capacity constraints on the pipelines that transport crude oil, natural gascrude oiland natural gas liquids from producing areas and our facilities;-risks of trading and hedging activities as a result of changes in energy prices or the financial condition of our counterparties;- the ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our FERC-regulated rates; -the timely receipt of approval bythe FERCapplicable governmental entities for construction and operation of ourinterstate natural gaspipeline projects and required regulatory clearances; our ability to acquire all necessary rights-of-wayand obtain agreements for interconnectsin a timely manner, and our ability to promptly obtain all necessary materials and supplies required for construction;- the impact of unsold and discounted capacity on Northern Border Pipeline being greater than expected; -the ability to market pipeline capacity on favorable terms;- orders by the FERC related to Northern Border Pipeline's November 2005 rate case which are significantly different than our assumptions; 25-risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines which outpace new drilling;- impactthe mechanical integrity ofa potential impairment charge if we are unable to renew our coal slurry pipeline contract; -facilities operated;the effects of changes in governmental policies and regulatory actions, including changes with respect to income taxes, environmental compliance, authorized rates or recovery of gas costs;-the results of administrative proceedings and litigation, regulatory actions and receipt of expected clearances involving regulatory authorities or any other local, state or federal regulatory body, including the FERC;-actions by rating agencies concerning our credit ratings;-the impact of unforeseen changes in interest rates, equity markets, inflation rates, economic recession and other external factors over which we have no control, including the effect on pension expense and funding resulting from changes in stock and bond market returns;-our ability to access capital at competitive rates or on terms acceptable to us;-demand for our services in the proximity of our facilities;-the profitability of assets or businesses acquired by us;-the risk that material weaknesses or significant deficiencies in our internal control over financial reporting could emerge or that minor problems could become significant;-the impact and outcome of pending and future litigation;-our ability to successfully integrate the operations of the assets acquired from ONEOK with our current operations;-performance of contractual obligations by our customers;-the uncertainty of estimates, including accruals;ability to control operating costs; and-acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or oursuppliers'suppliers’ orshippers'shippers’ facilities.These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also have material adverse effects on our future results. These and other risks are described in greater detail under Part II, Item 1A, “Risk Factors,” in this
quarterly reportQuarterly Report and under Part I, Item 1A,"Risk“Risk Factors," and under Item 1A, "Risk Factors,"” in ourannual reportAnnual Report on Form 10-K for the year ended December 31, 2005. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
OVERVIEWOverview –Our exposure to market risk discussed below includes forward-looking statements and represents an estimate of possible changes in future earnings that would occur assuming hypothetical future movements in interest rates or commodity prices. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur since actual gains and losses will differ from those estimated based on actual fluctuations in interest rates or commodity prices and the timing of transactions.
We are exposed to market risk due to interest rate and commodity price volatility. Market risk is the risk of loss arising from adverse changes in market rates and prices. We
utilizemay use financial instruments, including forwards, swaps, collars and futures, to manage the risks of certain identifiable or anticipated transactions and achieve a more predictable cash flow. Our risk management function follows established policies and procedures to monitor interest rates and natural gas and natural gas liquids marketing activities to ensure our hedging activities mitigate market risks. We do not use financial instruments for trading purposes.26INTEREST RATE RISKInterest Rate Risk –We utilize both fixed- and variable-rate debt and are exposed to market risk due to the floating interest rates on our credit facilities. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk. As of
March 31,June 30, 2006,we and Northern Border Pipeline had $388 million ofour variable-rate debt outstanding was $1.5 billion, including $150 million of our long-term debt of which we converted from fixed-rate to variable-rate debt through interest rate swap agreements.Primarily as a result of the transactions described in
this section under "Recent Developments,"Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Executive Summary,” our variable-rate debt outstanding increasedto $1,506 million as of May 1, 2006, $150 millionby $1.13 billion, of whichwe converted from fixed-rate$1.05 billion is outstanding under our Bridge Facility. We intend tovariable-rate debt through interest rate swap agreements.refinance the Bridge Facility with long-term financing prior to April 5, 2007.If interest rates increased
1%one percent on our borrowings outstanding as ofMay 1,June 30, 2006, our annual consolidated interest expense would increase and our projected consolidated income before income taxes would decrease by approximately $15 million.COMMODITY PRICE RISKCommodity Price Risk –Our Interstate Natural Gas
Pipeline segmentPipelines andthe recently acquired pipelinesPipelines andstorage assetsStorage segments are exposed to commodity price risk because our interstate and intrastate pipelines collect natural gas from their customers as part of their fee for services provided. When the amount of natural gas utilized in operations by these pipelines differs from the amount provided by their customers, the pipelines must buy or sell natural gas, or use natural gas from inventory, and are exposed to commodity price risk.We have not entered into anyAt June 30, 2006, there were no hedges in place with respect to our interstate and intrastate pipeline operations.Our
recently acquired natural gas liquids assets areNatural Gas Liquids segment is exposed to commodity price risk primarily as a result of natural gas liquids in storage, spread risk associated with the relative values of the various components of the natural gas liquids stream and the relative value of natural gas liquids purchases at one location andsalesales at another location, known as basis risk. We have not entered into any hedges with respect to our natural gas liquids marketing activities.Our
Natural GasGathering and Processing segment receives a significant portion of its revenue from the sale of commodities in exchange for gathering and processing services and is exposed to market risk due to changes in natural gas and natural gas liquids prices.To minimize earnings volatility related to natural gas and natural gas liquids price fluctuations, we may enter intoWe use commodity financial instruments, including NYMEX contracts, fixed price swaps and collars, which are all designated as cash flowhedges. As of March 31, 2006, we hedged a portion of our projectedhedges, to minimize earnings volatility related to natural gas and natural gas liquidsvolumesprice fluctuations. The following table sets forth our hedging information for the remainder of 2006 for our Gathering and Processing segment asfollows:of June 30, 2006:
Year Ending
December 31, 2006
Product
Volumes
HedgedAverage
Price Per UnitPercent-of-proceeds
Condensate (Bbl/d) (a)
815 $52.00 - 60.00 Natural gas liquids (Bbl/d) (b)
2,813 $44.13 Natural gas(MMBtu/d) (a)
5,217 $6.15 - 11.00 Natural gas(MMBtu/d) (b)
7,000 $7.92 Keep-whole
Gross processing spread(MMBtu/d)
10,550 $6.01
NINE MONTHS ENDED WEIGHTED DECEMBER 31, 2006 AVERAGE HEDGE HEDGED COMMODITY INSTRUMENT HEDGED VOLUME PRICE PER UNIT - ---------------- ---------------- ----------------- ---------------Natural Gas (in MMBtu/d) Collar 5,236 $6.15 - $11.00 Natural Gas (in MMBtu/d) Fixed Price Swap 7,000 $7.87 Natural Gas Liquids (in Bbl/d) Collar 818 $52.08 - $60.06 Natural Gas Liquids (in Bbl/d) Fixed Price Swap 1,354 $43.81(a) Hedged with NYMEX-based collars.
(b) Hedged with fixed-price swaps. Our commodity price market risk
excluding the effects of hedging,is estimated as a hypotheticaldecreasechange in the price of natural gas,andnatural gas liquids and crude oil atMarch 31,June 30, 2006. Our condensate sales are based on the price of crude oil. We estimate that a $1.00 perMMBtubarrel decrease in theweighted averageprice ofnatural gascrude oil wouldincreasedecrease annual net income by approximately$11 million.$0.5 million, excluding the effects of hedging. We estimate that a$0.10$0.01 per gallon decrease in theweighted averageprice of natural gas liquids would decrease annual net income by approximately$30 million. 27$2.5 million, excluding the effects of hedging. We estimate that a $0.10 per MMBtu increase in the price of natural gas would decrease annual net income by approximately $0.5 million, excluding the effects of hedging. For the remainder of 2006, the Gathering and Processing segment is approximately 96 percent hedged on its projected percent-of-proceeds condensate volumes, approximately 35 percent hedged on its projected percent-of-proceeds natural gas liquids volumes, approximately 40 percent hedged on its projected percent-of-proceeds natural gas volumes and approximately 31 percent hedged on its projected keep-whole gross processing spread.
ITEM 4. CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURESEvaluation of Disclosure Controls and Procedures –As of the end of the period covered by this report,
ourthe chief executive officer and chief financial officer of ONEOK Partners GP evaluated the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in this report is communicated to management of ONEOK Partners GP, including the officers of ONEOK Partners who are the equivalent of our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. Based on their evaluation, they concluded that as ofMarch 31,June 30, 2006, our disclosure controls and procedures were effective in ensuring that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in theSEC'sSEC’s rules and forms.CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTINGChanges in Internal Control Over Financial Reporting –There were no changes in our internal control over financial reporting that occurred during the
firstsecond quarter endedMarch 31,June 30, 2006, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.In
MayApril 2006,Northern Border Pipeline is implementing system modificationswe entered into a services agreement with ONEOK and also acquired the ONEOK Energy Assets. In addition, ONEOK now owns 100 percent of our general partner interest and the operations currently managed in our Omaha, Nebraska and Denver, Colorado offices will be moved tomeet new transaction billing requirementsTulsa, Oklahoma. The Denver office operations are anticipated to be transitioned to Tulsa by the end of the year and the Omaha office operations by April 2007. In July 2005, ONEOK acquired natural gas liquids assets from Koch, which we subsequently acquired as part of the ONEOK Energy Assets. As part of our ongoing integration activities, we are inconjunctionthe process of developing and incorporating controls and procedures related to the ONEOK Energy Assets into our internal controls over financial reporting. Until such controls are more fully developed, we have implemented and are relying on compensating controls and have performed extensive reviews of our reported results. As withits rate case. This activityany acquisition, there are inherent risks in the timing, development and implementation of internal controls that could negatively impact us; however, we do not believe they willcause changes to Northern Border Pipeline'smaterially affect our internal control over financialreporting during the second quarter of 2006.reporting.During the fourth quarter of 2005, we began implementing a new contracting and billing system to support
the Natural Gasour Gathering and Processingsegment. The new system will automatesegment by automating certain transactional processes, including scheduling, plant allocations and invoicing, that are currently handled manually. Implementation is scheduled to take place during the third quarter of 2006at which time weand willhaveresult in changes to our internal control over financialreporting. In April 2006,reporting; however, weentered into a services agreement with ONEOK and also acquired all of ONEOK's gas gathering and processing, natural gas liquids and pipeline and storage assets. In addition, ONEOK now owns 100% of our general partnership interest. As a result of these activities and the integration of the operations of the ONEOK acquired assets with our existing operations, there could be changes todo not believe they will materially affect our internal control over financial reporting.ITEM 1. LEGAL PROCEEDINGS
WILL PRICE, ET AL. V. GAS PIPELINES, ET AL. (F/K/A QUINQUE OPERATING COMPANY, ET AL. V. GAS PIPELINES, ET AL.Information about our other legal proceedings is included under Part II, Item 1, “Legal Proceedings,” in our Quarterly Report on Form 10-Q for the three months ended March 31, 2006, and under Item 3, “Legal Proceedings,” in our Annual Report on Form 10-K for the year ended December 31, 2005.
Will Price, et al. v. Gas Pipelines, et al. (f/k/a Quinque Operating Company, et al. v. Gas Pipelines, et al.),
26TH JUDICIAL DISTRICT, DISTRICT COURT OF STEVENS COUNTY, KANSAS, CIVIL DEPARTMENT, CASE NO.26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 99C30(PRICE(Price I).Plaintiffs brought suit on May 28, 1999, against MidContinent Market Center, Inc., ONEOK Field Services Company, ONEOK WesTex Transmission, L.P., and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP), all of which were recently acquired by us, as well as approximately 225 other defendants. Plaintiffs sought class certification for their claims that the defendants had underpaid gas producers and royalty owners throughout the United States by intentionally understating both the volume and the heating content of purchased gas. After extensive briefing and a hearing, the court refused to certify the class sought by the plaintiffs. Plaintiffs then filed an amended petition limiting the purported class to gas producers and royalty owners in Kansas, Colorado and Wyoming and limiting the claim to under measurement of volumes. Oral argument on the
plaintiffs'plaintiffs’ motion to certify this suit as a class action was conducted on April 1, 2005. Plaintiffs seek an unspecified amount of damages. The court has not yet ruled on the class certification issue.28WILL PRICE AND STIXON PETROLEUM, ET AL. V. GAS PIPELINES, ET AL.Will Price and Stixon Petroleum, et al. v. Gas Pipelines, et al.,
26TH JUDICIAL DISTRICT, DISTRICT COURT OF STEVENS COUNTY, KANSAS, CIVIL DEPARTMENT, CASE NO.26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 03C232(PRICE(Price II).This action was filed by the plaintiffs on May 12, 2003, after the court had denied class status in Price I. Plaintiffs claim that 21 groups of defendants, including MidContinent Market Center, Inc., ONEOK Field Services Company, ONEOK WesTex Transmission, L.P., and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP), all of which were recently acquired by us, intentionally underpaid gas producers and royalty owners by understating the heating content of purchased gas in Kansas, Colorado and Wyoming. Price II has been consolidated with Price I for the determination of whether either or both cases may properly be certified as class actions. Oral argument on the
plaintiffs'plaintiffs’ motion to certify this suit as a class action was conducted on April 1, 2005. Plaintiffs seek an unspecified amount of damages. The court has not yet ruled on the class certification issue.PRAXAIR, INC. V.Praxair, Inc. v. ONEOK
FIELD SERVICES COMPANY, ET AL.Field Services Company, et al.,DISTRICT COURT OF ELLSWORTH COUNTY, KANSAS, CASE NO. 04-C-17.District Court of Ellsworth County, Kansas, Case No. 04-C-17.Plaintiff is alleging that ONEOK Field Services Company and ONEOK Bushton Processing, Inc. wrongfully declared force majeure under its agreement with Plaintiff for delivery of helium.
Plaintiff'sPlaintiff’s initial petition filed in March 2004 claimed damages for breach of contract and breach of good faith and fair dealing in excess of $20 million. Plaintiff seeks to recover $41.5 million in breach of contract damages for the failure to deliver helium from ONEOK Field Services Company and ONEOK Bushton Processing, Inc. Discoveryphase ofin theproceedingcase isstill underway. In latecontinuing. The trial is currently scheduled for March2006, the plaintiff increased its damage claim to $41.5 million. Trial is scheduled to begin October 10, 2006.2007.The following new or modified risk factors, most of which relate to the assets and businesses acquired from ONEOK, should be read in conjunction with the risk factors disclosed in Part I, Item 1A, “Risk Factors,” of our
annual reportAnnual Report on Form 10-K for the year ended December 31, 2005:RISKS INHERENT IN OUR BUSINESS THE VOLATILITY OF NATURAL GAS AND NATURAL GAS LIQUIDS PRICES COULD ADVERSELY AFFECT OUR CASH FLOW.Risks Inherent in Our Business
The volatility of natural gas and natural gas liquids prices could adversely affect our cash flow.
A significant portion of our natural gas gathering and processing revenue is derived from the sale of commodities
we retainfor our gathering and processing services. Additionally, certain of our gas gathering and processing assets recently acquired in Oklahoma and Kansas have"keep whole"keep-whole processing contracts, under which we extract natural gas liquids and return to the producer volumes of merchantable natural gas containing the same amount of Btus that were removed as natural gas liquids. This type of contract exposes us tothe keep wholekeep-whole spread, or gross processing spread, which is the relative difference in the prices of natural gasliquidsand natural gas liquids on a Btu basis. As a result, we are sensitive to natural gas and natural gas liquids price fluctuations. Natural gas and natural gas liquids prices have been and are likely to continue to be volatile in the future. The recent record high natural gas and natural gas liquids prices may not continue and could drop precipitously in a short period of time. The prices of natural gas and natural gas liquids are subject to wide fluctuations in response to a variety of factors beyond our control, including the following:-relatively minor changes in the supply of, and demand for, domestic and foreign natural gas and natural gas liquids;-market uncertainty;-availability and cost of transportation capacity;-the level of consumer product demand;-political conditions in international naturalgas-producinggas- and crude oil-producing regions;-weather conditions;-domestic and foreign governmental regulations and taxes;-the price and availability of alternative fuels;-speculation in the commodity futures markets;-overall domestic and global economic conditions;-the price of natural gas and natural gas liquids imports; and-the effect of worldwide energy conservation measures.29These external factors and the volatile nature of the energy markets make it difficult to reliably estimate future prices of natural gas and natural gas liquids. As natural gas and natural gas liquids prices decline, we are paid less for our commodities, thereby reducing our cash flow. In addition, production and related volumes could also decline.
WE DO NOT FULLY HEDGE AGAINST PRICE CHANGES IN COMMODITIES. THIS COULD RESULT IN DECREASED REVENUES AND INCREASED COSTS, THEREBY RESULTING IN LOWER MARGINS AND ADVERSELY AFFECTING OUR RESULTS OF OPERATIONS.We do not fully hedge against price changes in commodities. This could result in decreased revenues and increased costs, thereby resulting in lower margins and adversely affecting our results of operations.
Our businesses are exposed to market risk and the impact of market fluctuations in natural gas, natural gas liquids, crude oil and power prices. Market risk refers to the risk of loss in cash flows and future earnings arising from adverse changes in commodity energy prices. Our primary exposure arises from natural gas liquids in storage utilized by our natural gas liquids operations and the difference between natural gas and natural gas liquids prices with respect to our
keep wholekeep-whole processing agreements. To minimize the risk from market fluctuations in natural gas, natural gas liquids andcrude oilcondensate prices, we use commodity derivative instruments such as futures contracts, swaps and options to manage the market risk of existing or anticipated purchases and sales of natural gas, natural gas liquids andcrude oil.condensate. However, we do not fully hedge against commodity price changes and we therefore retain some exposure to market risk.We adhereAccordingly, any adverse changes topoliciescommodity prices could result in decreased revenue andprocedures that limitincreased costs.If the level of drilling and production in the Midcontinent, Rocky Mountain and Gulf Coast regions and the Williston Basin substantially declines, our
exposurevolumes and revenue related tomarket risk from open positionsour Gathering andthat monitor our market risk exposure. IF THE LEVEL OF DRILLING AND PRODUCTION IN OKLAHOMA, KANSAS, THE PANHANDLE OF TEXAS AND THE WILLISTON, POWDER RIVER AND WIND RIVER BASINS SUBSTANTIALLY DECLINES, OUR GATHERING AND PROCESSING VOLUMES AND REVENUE COULD DECLINE.Processing segment, Natural Gas Liquids segment and Pipelines and Storage segment could decline.Our ability to maintain or expand our
natural gas gathering and processing business dependsbusinesses related to these segments depend largely on the level of drilling and production in the areas where ourgathering and processingfacilities are locatedwhich include Oklahoma, Kansas,in thepanhandle of TexasMidcontinent, Rocky Mountain andthe Williston, Powder River and Wind River Basins.Gulf Coast regions. Drilling and production are impacted by factors beyond our control, including:-demand for natural gas and refinery-grade crude oil;- producers'producers’ desire and ability to obtain necessary permits in a timely and economic manner;-natural gas field characteristics and production performance;-surface access and infrastructure issues; and-capacity constraints on natural gas, crude oil and natural gas liquids pipelinesthat transport gasfrom the producing areas and our facilities.In addition, drilling and production in the Powder River Basin are impacted by environmental regulations governing water discharge associated with coalbed methane production. If the level of drilling and production in any of these areas substantially declines, our gathering and processing volumes and revenue could be reduced.
PIPELINE INTEGRITY PROGRAMS AND REPAIRS MAY IMPOSE SIGNIFICANT COSTS AND LIABILITIES.Pipeline integrity programs and repairs may impose significant costs and liabilities.
In December 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs for our intrastate natural gas, interstate natural gas and natural gas liquids pipelines located near
"high“high consequence areas,"” where a leak or rupture could do the most harm. The final rule requires operators to perform ongoing assessments of pipeline integrity; identify and characterize applicable threats to pipeline segments that could impact a high consequence area; improve data collection, integration and analysis; repair and remediate the pipeline as necessary; and implement preventive and mitigating actions. The final rule incorporates the requirements of the Pipeline Safety Improvement Act of 2002 and became effective in January 2004. The results of these testing programs could cause us to incur significant capital and operating expenditures in response to repair, remediation, preventative or mitigating actions that are determined to be necessary.30A
DOWNGRADE OF OUR CREDIT RATING MAY REQUIRE US TO OFFER TO REPURCHASE OUR SENIOR NOTES OR IMPAIR OUR ABILITY TO ACCESS CAPITAL.downgrade of our credit rating may require us to offer to repurchase our senior notes or impair our ability to access capital.We could be required to offer to repurchase certain of our senior notes at par value, plus any associated penalties and premiums, if
Moody'sMoody’s Investor Services or Standard &Poor'sPoor’s Rating Services rate our senior notes below investment grade. We may not have sufficient cash on hand to repurchase the senior notes at par value, which may cause us to borrow money under our credit facilities or seek alternative financing sources to finance the repurchase. We could also face difficulties accessing capital or our borrowing costs could increase, impacting our ability to obtain financing for acquisitions or capital expenditures and to refinance indebtedness, including refinancing the amount outstanding under our364-day credit agreementBridge Facility used topurchasefinance a portion of theassets from ONEOK. WE MAY NOT BE ABLE TO SUCCESSFULLY INTEGRATE THE OPERATIONS OF THEacquisition of the ONEOKSUBSIDIARIES THAT WE ACQUIRED WITH OUR CURRENT OPERATIONS.Energy Assets.We may not be able to successfully integrate the operations of the ONEOK Energy Assets that we acquired with our current operations or successfully transfer the operations of Northern Border Pipeline.
The integration of the operations of the ONEOK
subsidiariesEnergy Assets that we recently acquired with our current operations will be a complex, time-consuming and costly process. Failure to timely and successfully integrate the operations of the ONEOKsubsidiariesEnergy Assets may have a material adverse effect on our business, financial condition and results of operations. Integrating the ONEOK Energy Assets’ operations will present challenges to our management, including:-operating a significantly larger combined company with operations in new geographic areas;-managing relationships with new customers for whom we have not previously provided services;-integrating personnel with diverse backgrounds and organizational cultures;-experiencing operational interruptions or the loss of key employees, customers or suppliers;-inefficiencies and complexities that may arise due to unfamiliarity with the new operations and the businesses associated with them, including with their markets;-assimilating the operations, technologies, services and products of the acquired operations;-incurring additional costs related to reorganization, severance, and relocation of employees;-assessing the internal controls and procedures for the combined entity that we are required to maintain under the Sarbanes-Oxley Act of2002;2002 and-other regulatory requirements; andconsolidating other corporate and administrative functions.We will also be exposed to risks that are commonly associated with transactions similar to this acquisition, such as unanticipated liabilities and costs, some of which may be material, and diversion of
management'smanagement’s attention. As a result, the anticipated benefits of the acquisition may not be fullyrealized, if at all. THE ISSUANCE OF CLASSrealized.The transfer of Northern Border Pipeline’s operations to an affiliate of TransCanada related to the ONEOK Transactions will be a complex and time-consuming process. Failure to successfully transfer the operations of Northern Border Pipeline may have a material adverse effect on Northern Border Pipeline’s business, financial condition and results of operations and consequently our financial condition and results of operations.
Risks Inherent in an Investment in Us
The issuance of Class B
UNITS TOunits to ONEOKIN CONNECTION WITH THE ACQUISITION OF CERTAIN OF ITS SUBSIDIARIES WILL DILUTE OUR CURRENT UNITHOLDERS' OWNERSHIP INTERESTS UPON THE CONVERSION OF THE CLASSin connection with the acquisition of certain of its subsidiaries will dilute our current unitholders’ ownership interests upon the conversion of the Class BUNITS TO COMMON UNITS.units to common units.In connection with the acquisition of certain ONEOK subsidiaries, we issued approximately 36.5 million Class B
units representinglimited partnerinterests in usunits to ONEOK. The Class B units will convert to common units on a one-for-one basis at theholder'sholder’s option upon the requisite approval of such conversion by our unitholders at a special meeting of unitholders, or automatically upon the requisite approval of both the conversion and certain amendments to our partnership agreement by our unitholders at a special meeting of unitholders. The conversion of the Class B units willhave the following effects: -decrease ourunitholders'unitholders’ proportionate ownership interest in uswill decrease; -and may also have the following effects:the distributions on each common unit may decrease;-the relative voting strength of each previously outstanding common unit may be diminished; and-the market price of the common units may decline.In addition, ONEOK may, from time to time, sell all or a portion of its common units. Sales of substantial amounts of
theirits common units, or the anticipation of such sales, could lower the market price of our common units and may make it more difficult for us to sell our equity securities in the future at a time and price that we deem appropriate.31RISKS INHERENT IN AN INVESTMENT IN US WE DO NOT OPERATE ALL OF OUR ASSETS NOR DO WE DIRECTLY EMPLOY ANY OF THE PERSONS RESPONSIBLE FOR PROVIDING US WITH ADMINISTRATIVE, OPERATING AND MANAGEMENT SERVICES. THIS RELIANCE ON OTHERS TO OPERATE OUR ASSETS AND TO PROVIDE OTHER SERVICES COULD ADVERSELY AFFECT OUR BUSINESS AND OPERATING RESULTS.We do not operate all of our assets nor do we directly employ any of the persons responsible for providing us with administrative, operating and management services. This reliance on others to operate our assets and to provide other services could adversely affect our business and operating results.
We rely on ONEOK,
Northern PlainsONEOK Partners GP and NBP Services to provide us with administrative, operating and management services. We have a limited ability to control our operations or the associated costs of such operations. The success of these operations depends on a number of factors that are outside our control, including the competence and financial resources of the provider. ONEOK,Northern PlainsONEOK Partners GP and NBP Services may outsource some or all of these services to third parties, and a failure to perform by these third-party providers could lead to delays in or interruptions of these services. Should ONEOK,Northern PlainsONEOK Partners GP or NBP Services not perform their respective contractual obligations, we may have to contract elsewhere for these services, which may cost more than we are currently paying. In addition, we may not be able to obtain the same level or kind of service or retain or receive the services in a timely manner, which may impact our ability to perform under our transportation contracts and negatively affect our business and operating results. Our reliance on ONEOK,Northern Plains,ONEOK Partners GP, NBP Services and the third-party providers with which they contract, together with our limited ability to control certain costs, could harm our business and results of operations.THE PARTNERSHIP POLICY COMMITTEE, OUR GENERAL PARTNERS AND THEIR AFFILIATES HAVE CONFLICTS OF INTEREST AND LIMITED FIDUCIARY DUTIES, WHICH MAY PERMIT THEM TO FAVOR THEIR OWN INTERESTS.The Board of Directors of our general partner, our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests.
ONEOK owns
100%100 percent of our general partner interests and a43.7%43.7 percent limited partner interest in us. Although ONEOK, through thePartnership Policy Committee,Board of Directors of our general partner, has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, theboardBoard ofdirectorsDirectors of ONEOK has a fiduciary duty to manage our generalpartnerspartner in a manner beneficial to ONEOK.Some membersA member of the Board of Directors of ourPartnership Policy Committee aregeneral partner is alsomembersa member ofONEOK's boardONEOK’s Board ofdirectors.Directors. Conflicts of interest may arise between our generalpartnerspartner andtheirits affiliates and us and our unitholders. In resolving these conflicts, our generalpartnerspartner may favortheirits own interests and the interests oftheir respectiveits affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:- the Partnership Policy Committee andour generalpartners,partner, whichareis owned by ONEOK, and the Board of Directors of our general partner, are allowed to take into account the interests of parties other than us in resolving conflicts of interest, which has the effect of limiting their fiduciary duty to our unitholders;-therespectiveaffiliates of our generalpartnerspartner may engage in competition with us;-our partnership agreement limits the liability and reduces the fiduciary duties of the members of thePartnership Policy Committee andBoard of Directors of our generalpartnerspartner and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;-thePartnership Policy CommitteeBoard of Directors of our general partner determines the amount and timing of our cash reserves, asset purchases and sales, capital expenditures, borrowings and issuances of additional partnership securities, each of which can affect the amount of cash that is distributed to our unitholders;-thePartnership Policy CommitteeBoard of Directors of our general partner approves the amount and timing of any capital expenditures and determines whether they are maintenance capital expenditures or growth capital expenditures, which can affect the amount of cash that is distributed to our unitholders;-thePartnership Policy CommitteeBoard of Directors of our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions;-thePartnership Policy CommitteeBoard of Directors of our general partner determines which costs incurred bythem,the Board of Directors, our generalpartnerspartner andtheirits respective affiliates are reimbursable by us;-our partnership agreement does not restrict the members of thePartnership Policy CommitteeBoard of Directors of our general partner from causing us to paythem,the Board of Directors, our generalpartnerspartner ortheirits respective affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;-our generalpartnerspartner may exercisetheirits limited right to call and purchase common units iftheyit andtheirits respective affiliates own more than80%80 percent of the common units; and-thePartnership Policy CommitteeBoard of Directors of our general partner decides whether to retain separate counsel, accountants or others to perform services for us.32OUR GENERAL PARTNERS AND THEIR AFFILIATES MAY COMPETE DIRECTLY WITH US AND HAVE NO OBLIGATION TO PRESENT BUSINESS OPPORTUNITIES TO US.Our general partner and its affiliates may compete directly with us and have no obligation to present business opportunities to us.
ONEOK and
theirits affiliates are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. ONEOK may acquire, construct or dispose of additional midstream or other assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets. In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to ONEOK and its affiliates. As a result, neither ONEOK nor any of its affiliates has any obligation to present business opportunities to us.Please read, “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Results of Operations–Other,” for information regarding impairment charges related to Black Mesa incurred during the second quarter of 2006, which information is incorporated herein by reference.
ITEM 6. EXHIBITS
The following exhibits are filed as part of this quarterly report on Form 10-Q: #2.1 Contribution Agreement by and among ONEOK, Inc., Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership dated February 14, 2006 (incorporated by reference to Exhibit 2.1 to Northern Border Partners, L.P.'s Form 10-K filed on March 7, 2006 (File No. 1-12202)). #2.2 First Amendment to Contribution Agreement by and among ONEOK, Inc., Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership dated April 6, 2006 (incorporated by reference to Exhibit 2.2 to Northern Border Partners, L.P.'s Form 8-K filed on April 12, 2006 (File No. 1-12202)). #2.3 Purchase and Sale Agreement by and between ONEOK, Inc. and Northern Border Partners, L.P. dated February 14, 2006 (incorporated by reference to Exhibit 2.2 to Northern Border Partners, L.P.'s Form 10-K filed on March 7, 2006 (File No. 1-12202)). #2.4 First Amendment to Purchase and Sale Agreement by and between ONEOK, Inc. and Northern Border Partners, L.P. dated April 6, 2006 (incorporated by reference to Exhibit 2.4 to Northern Border Partners, L.P.'s Form 8-K filed on April 12, 2006 (File No. 1-12202)). #2.5 Partnership Interest Purchase and Sale Agreement by and between Northern Border Intermediate Limited Partnership and TC Pipeline Intermediate Limited Partnership dated as of December 31, 2005 (incorporated by reference to Exhibit 2.3 to Northern Border Partners, L.P.'s Form 10-K filed on March 7, 2006 (File No. 1-12202)). #2.6 Purchase and Sale Agreement by and among Wisconsin Energy Corporation and WPS Investments, LLC and Northern Border Intermediate Limited Partnership dated as of March 30, 2006 (incorporated by reference to Exhibit 2.1 to Northern Border Partners, L.P. Form 8-K filed March 30, 2006 (File No. 1-2202)). 3.1 Amended and Restated Agreement of Limited Partnership of Northern Border Partners, L.P. dated October 1, 1993 (incorporated by reference to Exhibit 3.2 to Northern Border Partners, L.P.'s Form 10-K for the year ended December 31, 2004 (File No. 1-12202)). 3.2 Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Northern Border Partners, L.P. dated April 6, 2006. 4.1 Form of Class B unit certificate (incorporated by reference to Exhibit 4.1 to Northern Border Partners, L.P.'s Form 8-K filed on April 12, 2006 (File No. 1-12202)). 10.1 364-Day Credit Agreement dated April 6, 2006, by and among Northern Border Partners, L.P., the several banks and other financial institutions and lenders from time to time party hereto, SunTrust Bank, as Administrative Agent, Citicorp North America, Inc., as Syndication Agent and Bank of Montreal (doing business as Harris Nesbitt), UBS Loan Finance LLC, and Wachovia Bank, National Association, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Northern Border Partners, L.P.'s Form 8-K filed on April 12, 2006 (File No. 1-12202)). 10.2 First Amended and Restated General Partnership Agreement of Northern Border Pipeline Company dated April 6, 2006 by and between Northern Border Intermediate Limited Partnership and TC Pipelines Intermediate Limited Partnership (incorporated by reference to Exhibit 3.1 to Northern Border Pipeline Company's Form 8-K filed April 12, 2006 (File No. 333-87753)). 3310.3 Services Agreement dated April 6, 2006, by and among ONEOK, Inc., Northern Plains Natural Gas Company, LLC, NBP Services, LLC, Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership (incorporated by reference to Exhibit 10.3 to Northern Border Partners, L.P.'s Form 8-K filed on April 12, 2006 (File No. 1-12202)). 10.4 Consent and Amendment to Operating Agreement dated April 6, 2006, by and between Northern Border Pipeline Company and Northern Plains Natural Gas Company, LLC (incorporated by reference to Exhibit 10.2 to Northern Border Pipeline Company's Form 8-K filed April 12, 2006 (File No. 333-87753)). 10.5 Operating Agreement dated April 6, 2006, by and between Northern Border Pipeline Company and TransCan Northwest Border Ltd. (incorporated by reference to Exhibit 10.3 to Northern Border Pipeline Company's Form 8-K filed April 12, 2006 (File No. 333-87753)). 10.6 Amended and Restated Revolving Credit Agreement dated March 30, 2006, among Northern Border Partners, L.P., the lenders from time to time party thereto; SunTrust Bank, as administrative agent; Wachovia Bank, National Association, as Syndication Agent; Harris Nesbit Financing, Inc., Barclays Bank PLC and Citibank, N.A., as Co-Documentation Agents. (incorporated by reference to Exhibit 10.1 to Northern Border Partners, L.P. Form 8-K filed March 31, 2006 (File No. 1-2202)). 10.7 The First Amendment to Revolving Credit Agreement dated March 29, 2006, among Northern Border Pipeline Company, the lenders from time to time party thereto; Wachovia Bank, National Association, as Administrative Agent; SunTrust Bank, as syndication agent; and Harris Nesbit Financing, Inc., Barclays Bank PLC, and Citibank, N.A., as co-documentation agents (incorporated by reference to Exhibit 10.1 to Northern Border Pipeline Company's Form 8-K filed April 4, 2006 (File No. 333-87753)). +31.1 Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer. +31.2 Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer. +32.1 Section 1350 Certification of Chief Executive Officer. +32.2 Section 1350 Certification of Chief Financial Officer. The total amount of securities of the Partnership authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the Partnership and its subsidiaries on a consolidated basis. The Partnership agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to the Securities and Exchange Commission. # Northern Border Partners agrees to furnish supplementally to the SEC, upon request, any schedules and exhibits to this agreement, as set forth in the Table of Contents of the agreement, that have not been filed herewith pursuant to Item 601(b)(2) of Regulation S-K. + Filed herewith 34SIGNATURE 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. NORTHERN BORDER PARTNERS, L.P. (A Delaware Limited Partnership) Date: May 4, 2006 By: /s/ Jim Kneale ------------------------------------ Jim Kneale Chief Financial Officer (Signing on behalf of the Registrant and as Chief Financial Officer) 35EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION OF EXHIBIT - ----------- ----------------------Exhibit No.
Description of Exhibit
#2.1 Contribution Agreement by and among ONEOK, Inc., Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership dated February 14, 2006 (incorporated by reference to Exhibit 2.1 to Northern BorderONEOK Partners, L.P.'s’s Form 10-K filed on March 7, 2006 (File No. 1-12202)).#2.2 First Amendment to Contribution Agreement by and among ONEOK, Inc., Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership dated April 6, 2006 (incorporated by reference to Exhibit 2.2 to Northern BorderONEOK Partners, L.P.'s’s Form 8-K filed on April 12, 2006 (File No. 1-12202)).#2.3 Purchase and Sale Agreement by and between ONEOK, Inc. and Northern Border Partners, L.P. dated February 14, 2006 (incorporated by reference to Exhibit 2.2 to Northern BorderONEOK Partners, L.P.'s’s Form 10-K filed on March 7, 2006 (File No. 1-12202)).#2.4 First Amendment to Purchase and Sale Agreement by and betweenamong ONEOK, Inc., Northern Border Partners, L.P. and Northern BorderPartners, L.P.Intermediate Limited Partnership dated April 6, 2006 (incorporated by reference to Exhibit 2.4 to Northern Border Partners, L.P.'s’s Form 8-K filed on April 12, 2006 (File No. 1-12202)).#2.5 Partnership Interest Purchase and Sale Agreement by and between Northern Border Intermediate Limited Partnership and TC PipelinePipeLines Intermediate Limited Partnership dated as of December 31, 2005 (incorporated by reference to Exhibit 2.3 toNorthern Border Partners,ONEOK, L.P.'s’s Form 10-K filed on March 7, 2006 (File No. 1-12202)).#2.6 Purchase and Sale Agreement by and among Wisconsin Energy Corporation and WPS Investments, LLC and Northern Border Intermediate Limited Partnership dated as of March 30, 2006 (incorporated by reference to Exhibit 2.1 to Northern BorderONEOK Partners, L.P.’s Form 8-K filed on March 30, 2006 (File No.1-2202)1-12202)).3.1 Amended†#2.7 Purchase and RestatedSale Agreementofby and between Williams Field Services Company, LLC and Northern Border Intermediate Limited Partnership dated as of May 2, 2006.†#2.8 First Amendment to Purchase and Sale Agreement and Assignment, Delegation, Acceptance and Assumption of Rights and Obligations by and among Williams Field Services Company, LLC, ONEOK Partners Intermediate Limited Partnership and ONEOK Overland Pass Holdings, L.L.C. dated as of May 31, 2006. 3.1 Northern Border Partners, L.P. Certificate of Limited Partnership, Certificate of Amendment dated October 1, 1993February 16, 2001, and Certificate of Amendment dated May 20, 2003 (incorporated by reference to Exhibit3.23.1 toNorthern BorderONEOK Partners, L.P.'s’s Form 10-K for the year ended December 31, 2004 (File No. 1-12202)).3.2 Certificate of Amendment to Certificate of Limited Partnership of Northern Border Partners, L.P. (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.’s Form 8-K filed on May 23, 2006 (File No. 1 to1-12202)).3.3 Second Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P. (incorporated by reference to Exhibit 3.2 to ONEOK Partners, L.P.’s Form 8-K filed on May 23, 2006 (File No. 1-12202)).
3.4 Northern Border Intermediate Limited Partnership Certificate of Limited Partnership, Certificate of Amendment dated February 16, 2001, and Certificate of Amendment dated May 20, 2003 (incorporated by reference to Exhibit 3.3 to ONEOK Partners, L.P. dated April 6, 2006.’s Form 10-K for the year ended December 31, 2004 (File No. 1-12202)).��3.5 Certificate of Formation of ONEOK Partners GP, L.L.C., as amended. †3.6 Second Amended and Restated Limited Liability Company Agreement of ONEOK Partners GP, L.L.C. 3.7 Certificate of Amendment to Certificate of Limited Partnership of Northern Border Intermediate Limited Partnership (incorporated by reference to Exhibit 3.3 to ONEOK Partners, L.P.’s Form 8-K filed on May 23, 2006 (File No. 1-12202)). 3.8 Second Amended and Restated Agreement of Limited Partnership of ONEOK Partners Intermediate Limited Partnership (incorporated by reference to Exhibit 3.4 to ONEOK Partners, L.P.’s Form 8-K filed on May 23, 2006 (File No. 1-12202)) 4.1 Form of Class B unitCommon Unit certificate (incorporated by reference to Exhibit 4.1 toNorthern BorderONEOK Partners, L.P.'s’s Form 8-K filed on May 23, 2006 (File No. 1-12202)).4.2 Form of Class B Unit certificate (incorporated by reference to Exhibit 4.1 to ONEOK Partners, L.P.’s Form 8-K filed on April 12, 2006 (File No. 1-12202)). 10.1 364-Day Credit Agreement dated April 6, 2006, by and among Northern Border Partners, L.P., the several banks and other financial institutions and lenders from time to time party hereto,thereto, SunTrust Bank, as Administrative Agent, Citicorp North America, Inc., as Syndication Agent,andBank of Montreal (doing business as Harris Nesbitt), UBS Loan Finance LLC, and Wachovia Bank, National Association, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 toNorthern BorderONEOK Partners, L.P.'s’s Form 8-K filed on April 12, 2006 (File No. 1-12202)).10.2 First Amended and Restated General Partnership Agreement of Northern Border Pipeline Company dated April 6, 2006 by and between Northern Border Intermediate Limited Partnership and TC Pipelines Intermediate Limited Partnership(incorporated by reference to Exhibit 3.1 to Northern Border PipelineCompany'sCompany’s Form 8-K filed on April 12, 2006 (File No.333-87753)333-88577)).10.3 Services Agreement dated April 6, 2006, by and among ONEOK, Inc., Northern Plains Natural Gas Company, LLC, NBP Services, LLC, Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership (incorporated by reference to Exhibit 10.3 to Northern BorderONEOK Partners, L.P.'s’s Form 8-K filed on April 12, 2006 (File No. 1-12202)).10.4 Consent and Amendment to Operating Agreement dated April 6, 2006, by and between Northern Border Pipeline Company and Northern Plains Natural Gas Company, LLC (incorporated by reference to Exhibit 10.210.1 to Northern Border PipelineCompany'sCompany’s Form 8-K filed on April 12, 2006 (File No.333-87753)333-88577)).36
10.5 Operating Agreement dated April 6, 2006, by and between Northern Border Pipeline Company and TransCan Northwest Border Ltd. (incorporated by reference to Exhibit 10.310.2 to Northern Border PipelineCompany'sCompany’s Form 8-K filed on April 12, 2006 (File No.333-87753)333-88577)).†10.6 Amended and Restated RevolvingLimited Liability Company Agreement of Overland Pass Pipeline Company LLC entered into between ONEOK Overland Pass Holdings, L.L.C. and Williams Field Services Company, LLC dated May 31, 2006.†10.7 Processing and Gathering Services Agreement between ONEOK Field Services Company, L.L.C, ONEOK, Inc. and ONEOK Bushton Processing, Inc. dated April 6, 2006.
†12.1 Statement of Computation of Ratio of Earnings to Fixed Charges. †21
Subsidiaries of the Registrant.
†31.1
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
†31.2
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
†32.1
Section 1350 Certification of Chief Executive Officer.
†32.2
Section 1350 Certification of Chief Financial Officer.
# ONEOK Partners agrees to furnish supplementally to the SEC, upon request, any schedules and exhibits to this agreement, as set forth in the Table of Contents of the agreement, that have not been filed herewith pursuant to Item 601(b)(2) of Regulation S-K.
† Filed herewith The total amount of securities of ONEOK Partners, L.P. authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10 percent of the total assets of ONEOK Partners, L.P. and its subsidiaries on a consolidated basis. ONEOK Partners, L.P. agrees, upon request of the SEC, to furnish copies of any or all of such instruments to the SEC.
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 hereunto duly authorized.
ONEOK PARTNERS, L.P. By: ONEOK Partners GP, L.L.C., its General Partner Date: August 4, 2006 By: /s/ Jim Kneale
Jim Kneale Executive Vice President – Finance and Administration and Chief Financial Officer (Signing on behalf of the Registrant and as Principal Financial Officer) EXHIBIT INDEX
Exhibit No.
Description of Exhibit
#2.1 Contribution Agreement by and among ONEOK, Inc., Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership dated February 14, 2006 (incorporated by reference to Exhibit 2.1 to ONEOK Partners, L.P.’s Form 10-K filed on March 7, 2006 (File No. 1-12202)). #2.2 First Amendment to Contribution Agreement by and among ONEOK, Inc., Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership dated April 6, 2006 (incorporated by reference to Exhibit 2.2 to ONEOK Partners, L.P.’s Form 8-K filed on April 12, 2006 (File No. 1-12202)). #2.3 Purchase and Sale Agreement by and between ONEOK, Inc. and Northern Border Partners, L.P. dated February 14, 2006 (incorporated by reference to Exhibit 2.2 to ONEOK Partners, L.P.’s Form 10-K filed on March 7, 2006 (File No. 1-12202)). #2.4 First Amendment to Purchase and Sale Agreement by and among ONEOK, Inc., Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership dated April 6, 2006 (incorporated by reference to Exhibit 2.4 to Northern Border Partners, L.P.’s Form 8-K filed on April 12, 2006 (File No. 1-12202)). #2.5 Partnership Interest Purchase and Sale Agreement by and between Northern Border Intermediate Limited Partnership and TC PipeLines Intermediate Limited Partnership dated as of December 31, 2005 (incorporated by reference to Exhibit 2.3 to ONEOK Partners, L.P.’s Form 10-K filed on March 7, 2006 (File No. 1-12202)). #2.6 Purchase and Sale Agreement by and among Wisconsin Energy Corporation and WPS Investments, LLC and Northern Border Intermediate Limited Partnership dated as of March 30, 2006 (incorporated by reference to Exhibit 2.1 to ONEOK Partners, L.P.’s Form 8-K filed on March 30, 2006 (File No. 1-12202)). †#2.7 Purchase and Sale Agreement by and between Williams Field Services Company LLC and Northern Border Intermediate Limited Partnership dated as of May 2, 2006. †#2.8 First Amendment to Purchase and Sale Agreement and Assignment, Delegation, Acceptance and Assumption of Rights and Obligations by and among Williams Field Services Company, LLC, ONEOK Partners Intermediate Limited Partnership and ONEOK Overland Pass Holdings, L.L.C. dated as of May 31, 2006. 3.1 Northern Border Partners, L.P. Certificate of Limited Partnership, Certificate of Amendment dated February 16, 2001, and Certificate of Amendment dated May 20, 2003 (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.’s Form 10-K for the year ended December 31, 2004 (File No. 1-12202)). 3.2 Certificate of Amendment to Certificate of Limited Partnership of Northern Border Partners, L.P. (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.’s Form 8-K filed on May 23, 2006 (File No. 1-12202)). 3.3 Second Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P. (incorporated by reference to Exhibit 3.2 to ONEOK Partners, L.P.’s Form 8-K filed on May 23, 2006 (File No. 1-12202)). 3.4 Northern Border Intermediate Limited Partnership Certificate of Limited Partnership, Certificate of Amendment dated February 16, 2001, and Certificate of Amendment dated May 20, 2003 (incorporated by reference to Exhibit 3.3 to ONEOK Partners, L.P.’s Form 10-K for the year ended December 31, 2004 (File No. 1-12202)). †3.5 Certificate of Formation of ONEOK Partners GP, L.L.C., as amended. †3.6 Second Amended and Restated Limited Liability Company Agreement of ONEOK Partners GP, L.L.C. 3.7 Certificate of Amendment to Certificate of Limited Partnership of Northern Border Intermediate Limited Partnership (incorporated by reference to Exhibit 3.3 to ONEOK Partners, L.P.’s Form 8-K filed on May 23, 2006 (File No. 1-12202)). 3.8 Second Amended and Restated Agreement of Limited Partnership of ONEOK Partners Intermediate Limited Partnership (incorporated by reference to Exhibit 3.4 to ONEOK Partners, L.P.’s Form 8-K filed on May 23, 2006 (File No. 1-12202))
4.1 Form of Common Unit certificate (incorporated by reference to Exhibit 4.1 to ONEOK Partners, L.P.’s Form 8-K filed on May 23, 2006 (File No. 1-12202)). 4.2 Form of Class B Unit certificate (incorporated by reference to Exhibit 4.1 to ONEOK Partners, L.P.’s Form 8-K filed on April 12, 2006 (File No. 1-12202)). 10.1 364-Day Credit Agreement dated March 30,April 6, 2006, by and among Northern Border Partners, L.P., the several banks and other financial institutions and lenders from time to time partythereto;thereto, SunTrust Bank, asadministrative agent;Administrative Agent, Citicorp North America, Inc., as Syndication Agent, Bank of Montreal (doing business as Harris Nesbitt), UBS Loan Finance LLC, and Wachovia Bank, National Association, asSyndication Agent; Harris Nesbit Financing, Inc., Barclays Bank PLC and Citibank, N.A., asCo-DocumentationAgents.Agents (incorporated by reference to Exhibit 10.1 to ONEOK Partners, L.P.’s Form 8-K filed on April 12, 2006 (File No. 1-12202)).10.2 First Amended and Restated General Partnership Agreement of Northern Border Pipeline Company (incorporated by reference to Exhibit 3.1 to Northern Border Pipeline Company’s Form 8-K filed on April 12, 2006 (File No. 333-88577)). 10.3 Services Agreement dated April 6, 2006, by and among ONEOK, Inc., Northern Plains Natural Gas Company, LLC, NBP Services, LLC, Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership (incorporated by reference to Exhibit 10.3 to ONEOK Partners, L.P.’s Form 8-K filed March 31,on April 12, 2006 (File No.1-2202)1-12202)).10.7 The First10.4 Consent and Amendment to Revolving CreditOperating Agreement datedMarch 29,April 6, 2006,amongby and between Northern Border Pipeline Companythe lenders from time to time party thereto; Wachovia Bank, National Association, as Administrative Agent; SunTrust Bank, as syndication agent;andHarris Nesbit Financing, Inc., Barclays Bank PLC, and Citibank, N.A., as co-documentation agentsNorthern Plains Natural Gas Company, LLC (incorporated by reference to Exhibit 10.1 to Northern Border PipelineCompany'sCompany’s Form 8-K filed on April4,12, 2006 (File No.333-87753)333-88577)).+31.110.5 Operating Agreement dated April 6, 2006, by and between Northern Border Pipeline Company and TransCan Northwest Border Ltd. (incorporated by reference to Exhibit 10.2 to Northern Border Pipeline Company’s Form 8-K filed on April 12, 2006 (File No. 333-88577)). †10.6 Amended and Restated Limited Liability Company Agreement of Overland Pass Pipeline Company LLC entered into between ONEOK Overland Pass Holdings, L.L.C. and Williams Field Services Company, LLC dated May 31, 2006. †10.7 Processing and Gathering Services Agreement between ONEOK Field Services Company, L.L.C, ONEOK, Inc. and ONEOK Bushton Processing, Inc. dated April 6, 2006. †12.1 Statement of Computation of Ratio of Earnings to Fixed Charges. †21 Subsidiaries of the Registrant. †31.1 Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer. +31.2†31.2 Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer. +32.1†32.1 Section 1350 Certification of Chief Executive Officer. +32.2†32.2 Section 1350 Certification of Chief Financial Officer. # Northern Border
# ONEOK Partners, L.P. agrees to furnish supplementally to the SEC, upon request, any schedules and exhibits to this agreement, as set forth in the Table of Contents of the agreement, that have not been filed herewith pursuant to Item 601(b)(2) of Regulation S-K.
† Filed herewith The total amount of securities of ONEOK Partners, L.P. authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10 percent of the total assets of ONEOK Partners, L.P. and its subsidiaries on a consolidated basis. ONEOK Partners, L.P. agrees, upon request of the SEC, to furnish
supplementallycopies of any or all of such instruments to theSEC, upon request, any schedules and exhibits to this agreement, as set forth in the Table of Contents of the agreement, that have not been filed herewith pursuant to Item 601(b)(2) of Regulation S-K. + Filed herewith 37
67