-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Ae4ptcH6L7Nl5KmNDDQzRFlH7tPA+wLFH8tuAxmgAJJZosrFk6zHZsbH1wFlBFix uemh1l5L/jakSzbOetSQMQ== 0000950129-05-007873.txt : 20050808 0000950129-05-007873.hdr.sgml : 20050808 20050808153110 ACCESSION NUMBER: 0000950129-05-007873 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 20050630 FILED AS OF DATE: 20050808 DATE AS OF CHANGE: 20050808 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTHERN BORDER PARTNERS LP CENTRAL INDEX KEY: 0000909281 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION [4922] IRS NUMBER: 931120873 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-12202 FILM NUMBER: 051005824 BUSINESS ADDRESS: STREET 1: 13710 FIRST NATIONAL BANK STREET 2: PARKWAY CITY: OMAHA STATE: NE ZIP: 68154-5200 BUSINESS PHONE: 4024927300 MAIL ADDRESS: STREET 1: 13710 FIRST NATIONAL BANK STREET 2: PARKWAY CITY: OMAHA STATE: NE ZIP: 68154-5200 10-Q 1 h27464e10vq.txt NORTHERN BORDER PARTNERS, L.P. - JUNE 30, 2005 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 For the quarterly period ended JUNE 30, 2005 or [ ] 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 BORDER PARTNERS, L.P. (Exact name of registrant as specified in its charter) Delaware 93-1120873 ---------------------------------------- ------------------------------- (State or other jurisdiction (I.R.S. Employer Identification of incorporation or organization) Number) 13710 FNB Parkway Omaha, Nebraska 68154-5200 ---------------------------------------- ------------------------------- (Address of principal executive offices) (Zip code) (402) 492-7300 ---------------------------------------------------- (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] No [ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes [X] No [ ] The number of common units outstanding as of August 1, 2005 was 46,397,214. 1 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES QUARTERLY REPORT ON FORM 10-Q TABLE OF CONTENTS
Page No. -------- PART I. FINANCIAL INFORMATION Item 1. Financial Statements Consolidated Statement of Income - Three Months Ended June 30, 2005 and 2004 and Six Months Ended June 30, 2005 and 2004 .........................3 Consolidated Statement of Comprehensive Income - Three Months Ended June 30, 2005 and 2004 and Six Months Ended June 30, 2005 and 2004 .........................4 Consolidated Balance Sheet - June 30, 2005 and December 31, 2004 .............................5 Consolidated Statement of Cash Flows - Six Months Ended June 30, 2005 and 2004 .........................6 Consolidated Statement of Changes in Partners' Equity - Six Months Ended June 30, 2005 ..................................7 Notes to Consolidated Financial Statements .......................8-12 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations ...................................13-27 Item 3. Quantitative and Qualitative Disclosures About Market Risk .........27 Item 4. Controls and Procedures ............................................28 PART II. OTHER INFORMATION Item 5. Other Information ..................................................28 Item 6. Exhibits ........................................................28-29 Signature ........................................................................30
2 PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ------------------------ ------------------------- 2005 2004 2005 2004 ---------- ---------- ---------- ---------- (IN THOUSANDS EXCEPT PER UNIT AMOUNTS) OPERATING REVENUE $ 149,417 $ 142,476 $ 309,796 $ 286,249 ---------- ---------- ---------- ---------- OPERATING EXPENSES Product purchases 35,466 23,468 67,931 44,881 Operations and maintenance 30,042 28,998 63,214 58,397 Depreciation and amortization 21,456 21,318 42,848 42,824 Taxes other than income 8,989 8,097 18,801 17,791 ---------- ---------- ---------- ---------- Operating expenses 95,953 81,881 192,794 163,893 ---------- ---------- ---------- ---------- OPERATING INCOME 53,464 60,595 117,002 122,356 ---------- ---------- ---------- ---------- INTEREST EXPENSE 21,372 18,534 42,538 37,102 ---------- ---------- ---------- ---------- OTHER INCOME (EXPENSE) Equity earnings in unconsolidated affiliates 4,418 3,602 8,895 9,965 Other income 1,082 1,331 1,823 1,852 Other expense (234) (474) (457) (609) ---------- ---------- ---------- ---------- Other income, net 5,266 4,459 10,261 11,208 ---------- ---------- ---------- ---------- MINORITY INTEREST IN NET INCOME 8,629 12,389 20,818 24,916 ---------- ---------- ---------- ---------- INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 28,729 34,131 63,907 71,546 INCOME TAXES 997 1,259 1,896 2,822 ---------- ---------- ---------- ---------- INCOME FROM CONTINUING OPERATIONS 27,732 32,872 62,011 68,724 DISCONTINUED OPERATIONS, NET OF TAX 358 393 748 1,156 ---------- ---------- ---------- ---------- NET INCOME TO PARTNERS $ 28,090 $ 33,265 $ 62,759 $ 69,880 ========== ========== ========== ========== CALCULATION OF LIMITED PARTNERS' INTEREST IN NET INCOME: Net income to partners $ 28,090 $ 33,265 $ 62,759 $ 69,880 Less: General partners' interest in net income 2,552 2,655 5,235 5,377 ---------- ---------- ---------- ---------- Limited partners' interest in net income $ 25,538 $ 30,610 $ 57,524 $ 64,503 ========== ========== ========== ========== LIMITED PARTNERS' PER UNIT NET INCOME: Income from continuing operations $ 0.54 $ 0.65 $ 1.22 $ 1.37 Discontinued operations, net of tax 0.01 0.01 0.02 0.02 ---------- ---------- ---------- ---------- Net income $ 0.55 $ 0.66 $ 1.24 $ 1.39 ========== ========== ========== ========== NUMBER OF UNITS USED IN COMPUTATION 46,397 46,397 46,397 46,397 ========== ========== ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. 3 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ------------------------ ------------------------ 2005 2004 2005 2004 ---------- ---------- ---------- ---------- (IN THOUSANDS) Net income to partners $ 28,090 $ 33,265 $ 62,759 $ 69,880 Other comprehensive income: Changes associated with current period hedging transactions (2,483) 711 (5,208) 1,190 Changes associated with current period foreign currency translation (424) (433) (445) (733) ---------- ---------- ---------- ---------- Total comprehensive income $ 25,183 $ 33,543 $ 57,106 $ 70,337 ========== ========== ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. 4 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (UNAUDITED)
JUNE 30, DECEMBER 31, 2005 2004 ------------ ------------ (IN THOUSANDS) ASSETS CURRENT ASSETS Cash and cash equivalents $ 9,283 $ 33,980 Accounts receivable, net of allowance for doubtful accounts of $7,442 and $9,175 at June 30, 2005, and December 31, 2004, respectively 62,572 70,007 Materials and supplies, at cost 4,754 5,654 Prepaid expenses and other 6,764 5,650 Derivative financial instruments 429 1,996 ------------ ------------ Total current assets 83,802 117,287 ------------ ------------ PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment 2,962,667 2,939,465 Less: Accumulated provision for depreciation and amortization 1,044,891 1,002,041 ------------ ------------ Property, plant and equipment, net 1,917,776 1,937,424 ------------ ------------ INVESTMENTS AND OTHER ASSETS Investment in unconsolidated affiliates 281,442 273,202 Goodwill 152,782 152,782 Derivative financial instruments 2,639 2,555 Other 27,320 27,306 ------------ ------------ Total investments and other assets 464,183 455,845 ------------ ------------ Total assets $ 2,465,761 $ 2,510,556 ============ ============ LIABILITIES AND PARTNERS' EQUITY CURRENT LIABILITIES Current maturities of long-term debt $ 3,656 $ 5,126 Accounts payable 26,638 35,095 Accrued taxes other than income 27,713 32,563 Accrued interest 16,766 16,530 Derivative financial instruments 1,204 -- ------------ ------------ Total current liabilities 75,977 89,314 ------------ ------------ LONG-TERM DEBT, NET OF CURRENT MATURITIES 1,328,460 1,325,232 ------------ ------------ MINORITY INTERESTS IN PARTNERS' EQUITY 278,797 290,142 ------------ ------------ RESERVES AND DEFERRED CREDITS Deferred income taxes 8,136 7,186 Derivative financial instruments 131 840 Other 7,632 8,508 ------------ ------------ Total reserves and deferred credits 15,899 16,534 ------------ ------------ COMMITMENTS AND CONTINGENCIES (Note 6) PARTNERS' EQUITY General partners 15,262 15,603 Common units: 46,397,214 units issued and outstanding at June 30, 2005, and December 31, 2004 747,838 764,550 Accumulated other comprehensive income 3,528 9,181 ------------ ------------ Total partners' equity 766,628 789,334 ------------ ------------ Total liabilities and partners' equity $ 2,465,761 $ 2,510,556 ============ ============
The accompanying notes are an integral part of these consolidated financial statements. 5 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)
SIX MONTHS ENDED JUNE 30, ------------------------ 2005 2004 ---------- ---------- (IN THOUSANDS) CASH FLOW FROM OPERATING ACTIVITIES: Net income to partners $ 62,759 $ 69,880 ---------- ---------- Adjustments to reconcile net income to partners to net cash provided by operating activities: Depreciation and amortization 43,023 43,219 Minority interests in net income 20,818 24,916 Reserves and deferred credits (858) (1,657) Equity earnings in unconsolidated affiliates (8,895) (9,965) Distributions received from unconsolidated affiliates 2,653 7,519 Changes in components of working capital (5,861) (608) Other (2,332) (3,490) ---------- ---------- Total adjustments 48,548 59,934 ---------- ---------- Net cash provided by operating activities 111,307 129,814 ---------- ---------- CASH FLOW FROM INVESTING ACTIVITIES: Sale of gathering and processing assets -- 512 Investment in unconsolidated affiliates (1,454) -- Capital expenditures for property, plant and equipment (23,161) (9,531) ---------- ---------- Net cash used in investing activities (24,615) (9,019) ---------- ---------- CASH FLOW FROM FINANCING ACTIVITIES: Cash distributions: General and limited partners (79,812) (79,812) Minority interests (31,943) (31,318) Equity contributions from minority interests -- 39,000 Issuance of long-term debt 86,000 90,000 Long-term debt financing costs (1,327) -- Retirement of long-term debt (81,653) (134,841) Payments upon termination of derivatives (2,654) -- ---------- ---------- Net cash used in financing activities (111,389) (116,971) ---------- ---------- NET CHANGE IN CASH AND CASH EQUIVALENTS (24,697) 3,824 Cash and cash equivalents-beginning of period 33,980 35,895 ---------- ---------- Cash and cash equivalents-end of period $ 9,283 $ 39,719 ========== ========== - -------------------------------------------------------------------------------------- Supplemental Disclosures of Cash Flow Information: Cash paid for interest, net of amount capitalized $ 44,341 $ 39,642 ========== ========== Changes in components of working capital: Accounts receivable $ 8,149 $ (1,065) Materials and supplies, prepaid expenses and other (214) 3,539 Accounts payable (9,182) 2,240 Accrued taxes other than income (4,850) (5,150) Accrued interest 236 (172) ---------- ---------- Total $ (5,861) $ (608) ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. 6 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY (UNAUDITED)
ACCUMULATED OTHER TOTAL GENERAL COMMON COMPREHENSIVE PARTNERS' PARTNERS UNITS INCOME EQUITY ------------- ------------- ------------- ------------- (IN THOUSANDS) Balance at December 31, 2004 $ 15,603 $ 764,550 $ 9,181 $ 789,334 Net income to partners 5,235 57,524 -- 62,759 Changes associated with current period hedging transactions -- -- (5,208) (5,208) Changes associated with current period foreign currency translation -- -- (445) (445) Distribution to partners (5,576) (74,236) -- (79,812) ------------- ------------- ------------- ------------- Balance at June 30, 2005 $ 15,262 $ 747,838 $ 3,528 $ 766,628 ============= ============= ============= =============
The accompanying notes are an integral part of these consolidated financial statements. 7 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. BASIS OF PRESENTATION In this report, references to "we," "us," "our" or the "Partnership" collectively refer to Northern Border Partners, L.P. and our subsidiary, Northern Border Intermediate Limited Partnership and its subsidiaries. We have prepared the consolidated financial statements included herein without audit pursuant to the rules and regulations of the Securities and Exchange Commission. 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 with U.S. generally accepted accounting principles (U.S. GAAP) have been 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 financial statements and the notes thereto included in our annual report on Form 10-K for the year ended December 31, 2004. The preparation of financial statements in conformity with U.S. GAAP requires management to make assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. We own a 70% general partner interest in Northern Border Pipeline Company. Our wholly-owned subsidiaries are: Crestone Energy Ventures, L.L.C.; Bear Paw Energy, L.L.C.; Border Midstream Services, Ltd.; Midwestern Gas Transmission Company; Viking Gas Transmission Company; and Black Mesa Pipeline, Inc. We also own a 49% common membership interest and a 100% preferred A share interest in Bighorn Gas Gathering, L.L.C.; a 33.33% interest in Fort Union Gas Gathering, L.L.C.; a 35% interest in Lost Creek Gathering, L.L.C.; and a 33-1/3% interest in Guardian Pipeline, L.L.C. 2. CREDIT FACILITIES The Partnership and Northern Border Pipeline entered into revolving credit facilities, which are to be used for capital expenditures, acquisitions, general business purposes and refinancing existing indebtedness. Northern Border Pipeline entered into a $175 million five-year credit agreement (2005 Pipeline Credit Agreement) with certain financial institutions in May 2005. We entered into a $500 million five-year credit agreement (2005 Partnership Credit Agreement) with certain financial institutions in May 2005. Both of the revolving credit facilities permit the Partnership and Northern Border Pipeline to choose the lender's base rate or the London Interbank Offered Rate (LIBOR) plus a spread that is based on each of our long-term unsecured debt ratings as the interest rate on our outstanding borrowings, specify the portion of the borrowings to be covered by specific interest rate options and to specify the interest rate period. Both the Partnership and Northern Border Pipeline are required to pay a fee on the principal commitment amounts. As of June 30, 2005, there was $198 million outstanding under the 2005 Partnership Credit Agreement and no amounts outstanding under the 2005 Pipeline Credit Agreement. Each of the 2005 Partnership and Pipeline Credit Agreements require the Partnership and Northern Border Pipeline to comply with certain financial, operational and legal covenants. The agreements require, among other things, that the Partnership and Northern Border Pipeline maintain ratios 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. The agreements also require the maintenance of the 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 for the Partnership and 4.50 to 1 for Northern Border Pipeline. Pursuant to the credit agreements, if one or more acquisitions are consummated in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA is increased to 5.25 to 1 for the Partnership and to 5 to 1 for Northern Border Pipeline for two calendar quarters following the acquisition. Upon any breach of these covenants, amounts outstanding under the 2005 Partnership and Pipeline Credit Agreements may become immediately due and payable. As of June 30, 2005, the Partnership and Northern Border Pipeline were in compliance with these covenants. 8 3. DERIVATIVE INSTRUMENTS AND HEDGING 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 as well as the approval, reporting and monitoring of financial instrument activities. On December 9, 2004, we entered into forward-starting interest rate swap agreements with a total notional amount of $100 million in anticipation of a ten-year senior note issuance. These swap agreements expired in late May and early June of 2005, which resulted in the Partnership paying $2.7 million to the counterparties. In June 2005, we entered into a Treasury lock interest rate agreement with a total notional amount of $200 million in anticipation of a ten-year senior note issuance in 2005. In July 2005, the Partnership paid $0.1 million to the counterparty at expiration of the Treasury lock interest rate agreement. In the third quarter of 2005, we will commence amortization of amounts related to the termination of the forward-starting interest rate swaps and the Treasury lock as an increase to interest expense. We record in accumulated other comprehensive income amounts related to terminated interest rate swap agreements for cash flow hedges with such amounts amortized to interest expense over the term of the hedged debt. During the three and six months ended June 30, 2005, we amortized approximately $0.5 million and $1.0 million, respectively, related to the terminated interest rate swap agreements as a reduction to interest expense from accumulated other comprehensive income and expect to amortize approximately $0.5 million in each of the remaining quarters of 2005. We have outstanding interest rate swap agreements with notional amounts totaling $150 million that expire in March 2011. Under these agreements, we make payments to counterparties at variable rates based on the London Interbank Offered Rate and in return receive payments based on a 7.10% fixed rate. As of June 30, 2005, the average effective interest rate on our interest rate swap agreements was 5.80%. Our interest rate swap agreements have been designated as fair value hedges as they hedge the fluctuations in the market value of the senior notes issued by us in 2001. The accompanying consolidated balance sheet at June 30, 2005, reflects long-term derivative financial instrument assets of $2.6 million with a corresponding increase in long-term debt related to our fair value hedges. The Partnership and Northern Border Pipeline record in long-term debt amounts received or paid related to terminated or amended interest rate swap agreements for fair value hedges with such amounts amortized to interest expense over the remaining life of the interest rate swap agreement. The Partnership and Northern Border Pipeline amortized approximately $1.3 million and $2.6 million as a reduction to interest expense in the three and six months ended June 30, 2005, respectively, and expect to amortize approximately $1.3 million in each of the remaining quarters of 2005. Bear Paw Energy periodically enters into commodity derivative contracts and fixed-price physical contracts. Bear Paw Energy primarily utilizes price swaps and collars, which have been designated as cash flow hedges, to hedge its exposure to natural gas and natural gas liquids price volatility. During the three months and six months ended June 30, 2005, Bear Paw Energy recognized losses of $0.1 million and gains of $1.2 million, respectively, from the settlement of derivative contracts. As of June 30, 2005, the consolidated balance sheet reflected an unrealized gain of $0.4 million in current derivative financial instrument assets and an unrealized loss of approximately $1.2 million in current derivative financial instrument liabilities with a corresponding offset to accumulated other comprehensive income. If prices remain at current levels, Bear Paw Energy expects to reclassify approximately $0.7 million from accumulated other comprehensive income as a decrease to operating revenues in the remaining quarters of 2005. However, this decrease would be offset with increased operating revenues due to the higher prices assumed. 4. BUSINESS SEGMENT INFORMATION Our business is divided into three 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 natural gas transportation services; 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; and the Coal Slurry Pipeline segment, which transports crushed coal suspended in water. 9 BUSINESS SEGMENT DATA (IN THOUSANDS)
NATURAL GAS INTERSTATE GATHERING THREE MONTHS ENDED NATURAL GAS AND COAL SLURRY JUNE 30, 2005 PIPELINE PROCESSING PIPELINE OTHER(a) TOTAL - ------------------ ----------- ----------- ----------- ----------- ----------- Revenue from external customers $ 82,541 $ 61,039 $ 5,837 $ -- $ 149,417 Operating income (loss) 43,915 10,841 1,252 (2,544) 53,464 EBITDA 61,234 19,133 2,215 (2,097) 80,485 THREE MONTHS ENDED JUNE 30, 2004 - ------------------ Revenue from external customers $ 94,517 $ 42,585 $ 5,374 $ -- $ 142,476 Operating income (loss) 56,667 4,351 1,022 (1,445) 60,595 EBITDA 74,030 11,708 1,888 (570) 87,056 SIX MONTHS ENDED JUNE 30, 2005 - ------------------ Revenue from external customers $ 179,186 $ 118,612 $ 11,998 $ -- $ 309,796 Operating income (loss) 99,553 20,343 2,178 (5,072) 117,002 EBITDA 134,057 36,839 4,080 (3,819) 171,157 SIX MONTHS ENDED JUNE 30, 2004 - ------------------ Revenue from external customers $ 192,143 $ 83,326 $ 10,780 $ -- $ 286,249 Operating income (loss) 115,241 9,161 1,716 (3,762) 122,356 EBITDA 149,869 26,089 3,858 (1,454) 178,362
(a) Includes other items not allocable to segments. TOTAL ASSETS BY SEGMENT (IN THOUSANDS)
JUNE 30, DECEMBER 31, 2005 2004 ----------- ------------ Interstate Natural Gas Pipeline $ 1,852,747 $ 1,900,555 Natural Gas Gathering and Processing 576,160 570,101 Coal Slurry Pipeline 15,779 18,268 Other (a) 21,075 21,632 ----------- ------------ Total assets $ 2,465,761 $ 2,510,556 =========== ============
(a) Includes other items not allocable to segments. We evaluate performance based on EBITDA (earnings before interest, taxes, depreciation and amortization) less the 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. 10 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. RECONCILIATION OF NET INCOME (LOSS) TO EBITDA (IN THOUSANDS)
NATURAL GAS INTERSTATE GATHERING THREE MONTHS ENDED NATURAL GAS AND COAL SLURRY JUNE 30, 2005 PIPELINE PROCESSING PIPELINE OTHER (a) TOTAL - ------------------ ----------- ----------- ----------- ----------- ----------- Net income (loss) $ 24,048 $ 15,110 $ 1,109 $ (12,177) $ 28,090 Minority interest 8,629 -- -- -- 8,629 Interest expense, net 11,228 40 -- 10,104 21,372 Depreciation and amortization 16,598 3,978 965 -- 21,541 Income tax 849 5 141 (24) 971 AFUDC (118) -- -- -- (118) ----------- ----------- ----------- ----------- ----------- EBITDA $ 61,234 $ 19,133 $ 2,215 $ (2,097) $ 80,485 =========== =========== =========== =========== =========== THREE MONTHS ENDED JUNE 30, 2004 - ------------------- Net income (loss) $ 33,195 $ 7,849 $ 865 $ (8,644) $ 33,265 Minority interest 12,389 -- -- -- 12,389 Interest expense, net 10,562 108 2 7,862 18,534 Depreciation and amortization 16,807 3,745 858 105 21,515 Income tax 1,090 6 163 107 1,366 AFUDC (13) -- -- -- (13) ----------- ----------- ----------- ----------- ----------- EBITDA $ 74,030 $ 11,708 $ 1,888 $ (570) $ 87,056 =========== =========== =========== =========== =========== SIX MONTHS ENDED JUNE 30, 2005 - ------------------- Net income (loss) $ 56,197 $ 28,800 $ 1,854 $ (24,092) $ 62,759 Minority interest 20,818 -- -- -- 20,818 Interest expense, net 22,432 94 -- 20,012 42,538 Depreciation and amortization 33,167 7,936 1,920 -- 43,023 Income tax 1,579 9 306 261 2,155 AFUDC (136) -- -- -- (136) ----------- ----------- ----------- ----------- ----------- EBITDA $ 134,057 $ 36,839 $ 4,080 $ (3,819) $ 171,157 =========== =========== =========== =========== =========== SIX MONTHS ENDED JUNE 30, 2004 - ------------------- Net income (loss) $ 67,445 $ 18,475 $ 1,539 $ (17,579) $ 69,880 Minority interest 24,916 -- -- -- 24,916 Interest expense, net 21,444 214 11 15,433 37,102 Depreciation and amortization 33,484 7,387 2,136 212 43,219 Income tax 2,637 13 172 480 3,302 AFUDC (57) -- -- -- (57) ----------- ----------- ----------- ----------- ----------- EBITDA $ 149,869 $ 26,089 $ 3,858 $ (1,454) $ 178,362 =========== =========== =========== =========== ===========
(a) Includes other items not allocable to segments. 11 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 distribution to partners amount shown on the accompanying consolidated statement of changes in partners' equity included incentive distributions to the general partners of approximately $4.0 million. On July 19, 2005, the Partnership declared a cash distribution of $0.80 per unit ($3.20 per unit on an annualized basis) for the quarter ended June 30, 2005. The distribution is payable on August 12, 2005, to unitholders of record at July 29, 2005. 6. COMMITMENTS AND CONTINGENCIES 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. 7. RELATIONSHIPS WITH ENRON In June 2005, Northern Border Pipeline Company, Crestone Gathering Services, a wholly-owned subsidiary of Crestone Energy Ventures, and Bear Paw Energy, LLC executed term sheets with a third party for the sale of their unsecured claims held against Enron Corp. and Enron North America Corp. Proceeds from the sale are expected to be $14.6 million. In 2004, we adjusted our allowance for doubtful accounts to reflect an estimated $3.4 million ($3.0 million, net to the Partnership) recovery for our claims. In the second quarter of 2005, we made an adjustments to our allowance for doubtful accounts of approximately $1.8 million ($1.6 million, net to the Partnership) to reflect the agreements for the sales. As a result of the sale, Northern Border Pipeline anticipates recognizing additional income of $9.4 million ($6.6 million, net to the Partnership) later in 2005. 8. ACCOUNTING PRONOUNCEMENTS In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation (FIN) 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement (SFAS)No. 143." The statement clarifies the term conditional asset retirement obligation, as used in SFAS No. 143, and when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The effective date of this interpretation is no later than the end of the fiscal year ending after December 15, 2005. The effect of adopting FIN 47 is not expected to be material to our results of operations or financial position. 9. SUBSEQUENT EVENTS In July 2005, Crestone Energy Ventures executed a purchase and sale agreement to acquire an additional 3.7% interest of Fort Union Gas Gathering, L.L.C., bringing its total interest to approximately 37%, for $5.3 million, subject to normal closing adjustments. We expect to close the transaction in August of 2005. In July 2005, we negotiated a settlement agreement with our partner in Bighorn Gas Gathering related to provisions of the joint venture agreement that provided for cash flow incentives based on well connections. These incentives were provided to us through our ownership of preferred A shares in Bighorn Gas Gathering. Due to the settlement agreement, we anticipate recognizing $5.4 million of equity earnings associated with incentives due to us for 2004 and 2005. The settlement agreement also eliminates any future incentives. Therefore, our preferred A shares have been cancelled and effectively redeemed and capital accounts adjusted accordingly. 12 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 included in Item 1 of this quarterly report on Form 10-Q. References to "we," "us," "our" or the "Partnership" collectively refer to Northern Border Partners, L.P. and our subsidiary, Northern Border Intermediate Limited Partnership and its subsidiaries. EXECUTIVE SUMMARY OVERVIEW Northern Border Partners, L.P. is a publicly-traded limited partnership listed on the New York Stock Exchange under the symbol "NBP." Formed in 1993, our purpose is to acquire, own and manage pipeline and other midstream energy assets. We are a leading transporter of natural gas imported from Canada into the United States. We conduct our operations through three business segments. Our business segments and the proportionate share of identifiable assets of each, as of June 30, 2005, are: o the interstate natural gas pipeline segment, which provides natural gas transportation services, accounting for 76% of our identifiable assets; o the natural gas gathering and processing segment, which gathers, treats, processes and compresses natural gas as well as fractionates natural gas liquids, accounting for 23% of our identifiable assets; and o the coal slurry pipeline segment, which transports crushed coal suspended in water, accounting for 1% of our identifiable assets. RECENT DEVELOPMENTS NORTHERN BORDER PIPELINE CONTRACTING - During the second quarter ended June 30, 2005, Northern Border Pipeline Company had available capacity on the Port of Morgan, Montana to Ventura, Iowa portion of the pipeline which remained uncontracted. Northern Border Pipeline discounted transportation rates on a short-term basis to maximize overall revenue, and has since contracted all of its available capacity based on summer design on the Port of Morgan, Montana to Ventura, Iowa portion of the pipeline through September of 2005. Currently, we expect Northern Border Pipeline's revenue for 2005 will be $15 million to $18 million ($11 million to $13 million, net to the Partnership), lower than 2004 revenue which generally reflected contracting nearly all capacity at maximum rate levels. CREDIT AGREEMENTS - In May 2005, we entered into a five-year $500 million revolving credit agreement and Northern Border Pipeline entered into a five-year $175 million revolving credit agreement. We terminated our existing $275 million credit facility and Northern Border Pipeline terminated its existing $175 million credit facility in conjunction with the execution of the new agreements. Please read "Liquidity and Capital Resources - Debt and Credit Facilities" in this section for more information. TRANSITION - In May 2005, the transition, from CCE Holdings to ONEOK, Inc., of services provided to us was completed. MIDWESTERN GAS TRANSMISSION'S EASTERN EXTENSION PROJECT - In June 2005, Midwestern Gas Transmission filed an application for the Eastern Extension Project with the Federal Energy Regulatory Commission (FERC). This project is expected to cost $22 million to $25 million and will add 30 miles of pipeline with 120 million cubic feet per day (mmcfd) of transportation capacity from Portland, Tennessee to planned interconnections with Columbia Gulf Transmission Company and East Tennessee Pipeline Company. 13 BANKRUPTCY CLAIMS - In June 2005, Northern Border Pipeline Company, Crestone Gathering Services, a wholly-owned subsidiary of Crestone Energy Ventures, and Bear Paw Energy, LLC executed term sheets with a third party for the sale of their unsecured claims held against Enron Corp. and Enron North America Corp. Proceeds from the sale are expected to be $14.6 million. In 2004, we adjusted our allowance for doubtful accounts to reflect an estimated $3.4 million ($3.0 million, net to the Partnership) recovery for our claims. In the second quarter of 2005, we made favorable adjustments to our allowance for doubtful accounts of approximately $1.8 million ($1.6 million, net to the Partnership) to reflect the agreements for the sales. As a result of the sale, Northern Border Pipeline anticipates recognizing additional income of $9.4 million ($6.6 million, net to the Partnership) later in 2005. INTEREST IN FORT UNION GAS GATHERING - In July 2005, Crestone Energy Ventures executed a purchase and sale agreement to acquire an additional 3.7% interest of Fort Union Gas Gathering, L.L.C., bringing its total interest to approximately 37%, for $5.3 million, subject to normal closing adjustments. We expect to close the transaction in August of 2005. BIGHORN GAS GATHERING PREFERRED A SETTLEMENT - In July 2005, we negotiated a settlement agreement with our partner in Bighorn Gas Gathering related to provisions of the joint venture agreement that provided for cash flow incentives based on well connections. These incentives were provided to us through our ownership of preferred A shares in Bighorn Gas Gathering. Due to the settlement agreement, we anticipate recognizing $5.4 million of equity earnings associated with incentives due to us for 2004 and 2005. The settlement agreement also eliminates any future incentives. Therefore, our preferred A shares have been cancelled and effectively redeemed and capital accounts adjusted accordingly. MINNESOTA FUEL TAX - In July 2005, the Minnesota legislature passed an omnibus tax bill, which included a provision restoring the sales tax on pipeline fuel and equipment purchases. The provision is effective for purchases made after July 31, 2005. As a result, the value of the gas provided in-kind and used in the operation of Northern Border Pipeline and Viking Gas Transmission's compressor stations will be taxed. We estimate that this additional tax will be approximately $2.3 million to $3.0 million per year. We are evaluating whether there is a legal basis for challenging the imposition of this tax on our operations. RECENT ACCOUNTING PRONOUNCEMENTS The Financial Accounting Standards Board (FASB) recently issued FASB Interpretation (FIN) 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143." For more information about this recent accounting pronouncement and how it may affect our future financial statements, please refer to Note 8 of the Notes to Consolidated Financial Statements included in Item 1 of this quarterly report on Form 10-Q. CRITICAL ACCOUNTING POLICIES AND ESTIMATES In our financial reporting process, we make assumptions and use estimates that affect the reported amount of the assets and liabilities, disclosure of contingent assets and liabilities, and the reported amount of revenue and expenses during the reporting period. Actual results could differ from these estimates if the underlying assumptions are incorrect. Any effects on our financial position or results of operations resulting from revisions to these estimates are recorded in the period during which the facts that gave rise to the revision become known. Key estimates used by management include: o the economic useful life of our assets used to determine depreciation and amortization; o the fair value used to determine possible asset impairment charges; o the fair value used to record derivative assets and liabilities; o the fair value of assets acquired; and o the amount of expense accruals. 14 In general, there have been no significant changes in our critical accounting policies since December 31, 2004. For a detailed discussion of these policies, please refer to Note 2 of the Notes to Consolidated Financial Statements - Summary of Significant Accounting Policies, in our annual report on Form 10-K for the year ended December 31, 2004. Details of our most significant accounting policies are noted as follows: REGULATORY ASSETS The interstate natural gas pipeline segment's accounting policies conform to SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Accordingly, assets that result from the ratemaking process are reflected on the balance sheet as regulatory assets. We consider factors such as regulatory changes and the impact of competition to determine the probability of future recovery of these assets. If we determine future recovery is no longer probable, we would be required to write off the regulatory assets at that time. As of June 30, 2005, the interstate natural gas pipeline segment reflected regulatory assets of $12.8 million that we expect to recover from our customers over varying time periods up to 44 years. ESTIMATED USEFUL LIVES OF PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION METHODS Our long-lived assets are recorded at original cost. We estimate the economic useful lives of our assets based on historical experience and make adjustments when changes in planned use, technological advances, or other factors show that a different life is more appropriate. The depreciation rates for our regulated interstate natural gas pipelines are determined by the FERC's ratemaking process. Revisions to the estimated economic useful lives of our assets would impact our depreciation and amortization expense in future periods. RECOVERABILITY OF LONG-LIVED ASSETS We review our long-lived assets for impairment according to SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," when events or changes in circumstances indicate that the value of our assets on the balance sheet may not be recoverable. We compare our asset's book value to its expected future net cash flow to determine recoverability. If an asset is considered to be impaired, an impairment charge equal to the difference between the fair value of the asset and its book value would be recognized. GOODWILL Our accounting for goodwill is in accordance with SFAS No. 142, "Goodwill and Other Intangible Assets." We have selected the fourth quarter to perform our annual testing. DERIVATIVE INSTRUMENTS We use derivative instruments to mitigate commodity price exposure in our natural gas gathering and processing segment and interest rate risk related to our financing activities. We record our derivatives at fair value according to SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The fair value of a derivative instrument is determined by the present value of its future cash flows, based on market prices from third party sources. The accounting treatment for changes in the derivative's fair value depends on whether it has been designated and qualifies as part of a hedge relationship. If specific hedge criteria are met, the derivative's gains and losses may offset the hedged item's related results in the income statement. As of June 30, 2005, the consolidated balance sheet included assets from derivative financial instruments of $3.1 million and liabilities from derivative financial instruments of $1.3 million. REVENUE RECOGNITION For the interstate natural gas pipeline segment, we recognize revenue when transportation service is provided to our customers according to each transportation contract. Under our firm transportation agreements, our customers are obligated to pay a fee for capacity on our pipelines, regardless of how much natural gas is actually transported. For the natural gas gathering and processing segment, we record operating revenue when gas is processed in or transported through our facilities. Revenue from cash payments received from producers prior to providing gathering services are deferred and recognized based on the depletion of the natural gas reserves associated with the gathering system. For the coal slurry pipeline segment, revenue is recognized based on a contracted demand payment, actual tons of coal transported and direct reimbursement of certain other expenses. 15 RESULTS OF OPERATIONS SELECTED FINANCIAL AND OPERATING RESULTS The following table summarizes financial and operating results for the three and six months ended June 30, 2005, and 2004 by segment (in thousands, unless otherwise noted):
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ------------------------ ------------------------ 2005 2004 2005 2004 ---------- ---------- ---------- ---------- Operating revenue: Interstate Natural Gas Pipeline $ 82,541 $ 94,517 $ 179,186 $ 192,143 Natural Gas Gathering and Processing 61,039 42,585 118,612 83,326 Coal Slurry Pipeline 5,837 5,374 11,998 10,780 ---------- ---------- ---------- ---------- Total operating revenue 149,417 142,476 309,796 286,249 ---------- ---------- ---------- ---------- Operating income (loss): Interstate Natural Gas Pipeline 43,915 56,667 99,553 115,241 Natural Gas Gathering and Processing 10,841 4,351 20,343 9,161 Coal Slurry Pipeline 1,252 1,022 2,178 1,716 Other (2,544) (1,445) (5,072) (3,762) ---------- ---------- ---------- ---------- Total operating income 53,464 60,595 117,002 122,356 ---------- ---------- ---------- ---------- Income (loss) from continuing operations: Interstate Natural Gas Pipeline 24,048 33,195 56,197 67,445 Natural Gas Gathering and Processing 15,110 7,849 28,800 18,475 Coal Slurry Pipeline 1,109 865 1,854 1,539 Other (12,535) (9,037) (24,840) (18,735) ---------- ---------- ---------- ---------- Total income from continuing operations 27,732 32,872 62,011 68,724 ---------- ---------- ---------- ---------- Discontinued operations, net of tax 358 393 748 1,156 ---------- ---------- ---------- ---------- Net income $ 28,090 $ 33,265 $ 62,759 $ 69,880 ========== ========== ========== ========== Operating data (1): Interstate Natural Gas Pipeline: Million cubic feet per day ( mmcfd) 257,171 272,763 563,864 575,578 Average daily throughput (mmcfd) 2,889 3,065 3,193 3,237 Natural Gas Gathering and Processing: Gathering (mmcfd) 1,005 1,020 1,029 998 Processing (mmcfd) 63 56 62 53 Coal Slurry Pipeline: Thousands of tons of coal shipped 1,102 975 2,384 2,129
(1) Operating data includes 100% of the volumes for joint venture investments as well as for wholly-owned subsidiaries. 16 CONSOLIDATED OPERATING RESULTS Our income from continuing operations was $27.7 million for the second quarter of 2005, or $0.54 per unit, compared with $32.9 million in 2004, or $0.65 per unit, for the same quarter last year. This $5.2 million, or 16%, decrease is largely attributable to the revenue impact of the uncontracted capacity on Northern Border Pipeline and higher interest expense offset by improved results from our natural gas gathering and processing segment due to increased prices of natural gas and natural gas liquids and increased volumes processed. For the six months ended June 30, 2005, income from continuing operations was $62.0 million, or $1.22 per unit, compared with $68.7 million, or $1.37 per unit, for the six months ended June 30, 2004. This $6.7 million, or 10%, decrease was primarily the result of the revenue impact of Northern Border Pipeline's uncontracted capacity as well as increased interest expense for the six months ended June 30, 2005, offset by improved results from our gas gathering and processing segment due to increased commodity prices realized and volumes processed. INTERSTATE NATURAL GAS PIPELINE SEGMENT OVERVIEW Our interstate natural gas pipeline segment transports natural gas for its customers. Operating revenue is derived from transportation contracts under tariffs regulated by the FERC. The tariffs specify the maximum rate we can charge our customers, which is determined through a ratemaking process. During this process, which is called a rate case in the industry, a determination is reached by the FERC, either through a hearing or a settlement on a just maximum rate that includes recovery of our prudent cost-based investment and a reasonable return for our investors. Our firm transportation customers are obligated to pay a fee for capacity on our pipelines, regardless of how much natural gas they actually transport, in addition to a fee based on the volume of natural gas transported. Our interruptible transportation customers pay a fee based only on the volume of natural gas transported. Our interstate natural gas pipeline segment is made up of the following subsidiaries: o a 70% general partnership interest in Northern Border Pipeline Company; o Midwestern Gas Transmission Company; and o Viking Gas Transmission Company, which includes a 33-1/3% interest in Guardian Pipeline, L.L.C. For the six months ended June 30, 2005, Northern Border Pipeline accounted for 85% of our interstate natural gas pipeline segment revenue, Midwestern Gas Transmission accounted for 6%, and Viking Gas Transmission accounted for 9%. MARKET CONDITIONS As of December 31, 2004, approximately 88% of the natural gas we transported on Northern Border Pipeline was produced in the Western Canada Sedimentary Basin. Therefore, the continuous supply of Canadian natural gas is crucial to our long-term financial condition. Of equal importance is the demand for natural gas in the Midwestern United States markets that we serve, including in the Chicago market area, which is served directly by Northern Border Pipeline and Midwestern Gas Transmission. Some of the significant factors that may impact our customer's desire to move natural gas on our interstate pipelines include: o the amount of Canadian natural gas available for export, which is impacted by Canadian supply and demand; o the ability to transport Canadian gas on other pipelines; o the amount of storage capacity for Canadian gas and demand for storage injection; o the availability of natural gas from other supply sources that could be transported to the Midwestern United States; o the demand for natural gas in other markets, which may affect the supply in the Midwestern United States, primarily as a result of temperature and/or hydro electric generation levels; and o the natural gas market price spread between Alberta, Canada and the Midwestern United States. For a discussion about market factors that may impact supply and demand for natural gas, please read "Business - Demand for Interstate Pipeline Transportation Capacity" in our annual report on Form 10-K for the year ended December 31, 2004. 17 KNOWN TRENDS AND UNCERTAINTIES CANADIAN SUPPLY - Our projections assume that Canadian supply will remain fairly stable and import levels will be flat in 2005. NATURAL GAS STORAGE LEVELS - We observed rising demand for storage of Canadian natural gas during the second quarter ended June 30, 2005, and believe this may be primarily due to an increased price differential between summer natural gas prices in the United States compared with projected natural gas prices for the coming winter season. The changing mix of natural gas users may also be a factor in the growing demand for storage, from the steady demand of industrial users to temperature-sensitive residential, commercial, and electric generation users. We anticipate additional storage projects in Alberta, Canada to be in service in 2006. SEASONALITY - Supply and demand in the various geographic regions of the United States as a result of weather conditions can significantly affect one another as the market attempts to balance each region's natural gas needs. In addition to traditional winter heating demand load, Canadian supply helps serve western United States' summer demand for natural gas for electric generation. This market may be sensitive to precipitation levels that affect the supply of hydro electric generation. During the summer, in the Western United States, the effects of low hydro electric generation levels combined with high temperature demand loads impact Canadian natural gas pricing. In the Midwestern United States, pipeline infrastructure is designed to meet winter heating demand load. During the summer when there may be excess pipeline capacity, there is greater competition from other supply sources. Winter season is considered to be November to March, and summer season is considered to be the remaining months. Peak summer season for electric generation includes July, August and September. During the second quarter ended June 30, 2005, we observed weakened demand for natural gas consistent with typical seasonal demand factors. COMPETITION - In 2005, new supply from the Rockies via Cheyenne Plains Pipeline as well as natural gas from the San Juan and Permian Basins has been redirected from Western United States markets into the Mid-continent region creating greater supply competition in the Midwestern United States market. Cheyenne Plains is expected to complete an expansion project that will increase its pipeline capacity by 170 million dekatherms per day by early 2006. CONTRACTING RISK - Natural gas supply and demand may significantly impact our business; however, a significant portion of our revenue is generated from long-term firm transportation contracts. As long as our pipeline capacity is fully contracted, under normal circumstances, we can expect to collect operating revenue regardless of short-term market dynamics that may impact natural gas flows. When we are not fully contracted, we are directly affected by the current market fundamentals and are most sensitive to changes in supply and demand for natural gas which impact the demand for our capacity. As previously disclosed, Northern Border Pipeline had uncontracted capacity during the second quarter ended June 30, 2005, on its Port of Morgan, Montana to Ventura, Iowa portion of pipeline. Expiring long-term transportation contracts were replaced with primarily short-term contracts. When demand is light relative to supply, our customers may not want to commit for long periods to a certain rate if they believe the cost supported by the market will be lower. Seasonal demand suggests that this situation is more likely to impact our revenue at certain times of the year. Accordingly, we believe throughput on our system may be more seasonal in the future and some discounting may be required to maximize revenue. GROWTH PROJECTS - We are focused on modifying our existing systems to meet market demand (organic growth) in addition to seeking new pipeline development projects. Organic growth projects currently underway include: o Chicago III Expansion - Northern Border Pipeline o Eastern Extension - Midwestern Gas Transmission o Southbound Expansion - Midwestern Gas Transmission For the Chicago III Expansion, a proposed expansion of Northern Border Pipeline's system into the Chicago market area, Northern Border Pipeline has filed its application for a certificate of public convenience and necessity for the construction and operation of the facilities. Northern Border Pipeline anticipates the issuance of a certificate by the FERC during the third quarter of 2005. This project is fully subscribed and estimated to cost approximately $21 million. It will add 130 mmcfd of transportation capacity from Harper, Iowa to Chicago, Illinois. 18 In June 2005, Midwestern Gas Transmission filed an application for a certificate of public convenience and necessity for the Eastern Extension Project with the FERC. This project is expected to cost $22 million to $25 million and will add 30 miles of pipeline with 120 mmcfd of transportation capacity from Portland, Tennessee to planned interconnections with Columbia Gulf Transmission Company and East Tennessee Pipeline Company. Midwestern Gas Transmission's Southbound Expansion will increase its pipeline's southbound capacity by 86,000 dekatherms per day. This fully-subscribed expansion project is expected to go into service in November of 2005. Please refer to "Management's Discussion and Analysis of Financial Condition and Results of Operations - Interstate Natural Gas Pipeline Segment" in our annual report on Form 10-K for the year ended December 31, 2004, for more information about our expansion projects. REGULATORY DEVELOPMENTS RATE CASE - Under the terms of Northern Border Pipeline's 1999 rate case, Northern Border Pipeline must file a new rate case on November 1, 2005. Elements to be decided in the rate case include billing units, rate base, our depreciation rate on transmission plant, return on equity, rate design and issues related to the inclusion of an income tax allowance. We believe the new rate would take effect on May 1, 2006. The resulting rate may be subject to reduction based upon FERC's review. The outcome will be finally determined by FERC approval of a settlement or decided by the FERC based on hearings. INCOME TAX ALLOWANCE - In May 2005, the FERC issued a policy statement permitting the inclusion in rates of an income tax allowance for partnership interests if the partners have an actual or potential income tax liability on that income. Northern Border Pipeline's present rates reflect an allowance for income taxes. More information regarding our upcoming rate case and income tax allowance can be found in "Business - Interstate Pipeline Regulation" in our annual report on Form 10-K for the year ended December 31, 2004. INTERSTATE NATURAL GAS PIPELINE SEGMENT OPERATING RESULTS The interstate natural gas pipeline segment reported net income of $24.0 million for the second quarter ended June 30, 2005, compared with $33.2 million for the second quarter ended June 30, 2004. The $9.2 million, or 28%, decline for the second quarter ended June 30, 2005, was primarily due to the revenue impact from uncontracted and discounted capacity in 2005 on Northern Border Pipeline on the Port of Morgan, Montana to Ventura, Iowa portion of the pipeline. For the six months ended June 30, 2005, net income was $56.2 million compared with $67.4 million for the six months ended June 30, 2004. The $11.2 million, or 17%, decrease for the six months ended June 30, 2005, was primarily the result of the second quarter revenue impact from uncontracted and discounted capacity on Northern Border Pipeline. Operating revenue decreased $12.0 million, or 13%, for the second quarter ended June 30, 2005, compared with the same quarter last year primarily impacted by $13.0 million decreased revenue associated with the uncontracted and discounted transportation capacity for Northern Border Pipeline, partially offset by $1.3 million increased short-term and other transportation service revenue for Northern Border Pipeline. Operating revenue decreased $13.0 million, or 7%, for the six months ended June 30, 2005, compared with the same period in 2004, reflecting the impact of the second quarter ended June 30, 2005, items and one additional day of transportation revenue in the first quarter ended March 31, 2004, due to leap year. Operations and maintenance expense increased slightly by $0.2 million for the second quarter ended June 30, 2005, compared with the same quarter last year. The quarter ended June 30, 2005, included a reduction of Northern Border Pipeline's allowance for doubtful accounts of approximately $0.6 million related to bankruptcy claims against Enron and Enron North America. The second quarter ended June 30, 2004, included a credit of approximately $1.2 million to true up previously recorded corporate charges which was partially offset by $0.7 million of amortization expense for the renewal of a right-of-way easement. 19 Operations and maintenance expense increased $2.3 million for the six months ended June 30, 2005, compared with the same period last year primarily as a result of adjustments recorded in 2005 and 2004 for operational gas volume imbalances on Viking Gas Transmission. Interest expense increased $0.7 million for the second quarter ended June 30, 2005, and $1.0 million for the six months ended June 30, 2005, compared with the same periods last year as a result of higher average interest rates that were partially offset by lower average debt outstanding. NATURAL GAS GATHERING AND PROCESSING SEGMENT OVERVIEW Our natural gas gathering and processing segment accepts delivery of raw gas from natural gas wells and central collection points located primarily in the Powder River Basin in Wyoming and the Williston Basin in Montana and North Dakota. Our pipelines gather the wellhead production and transport the raw gas to central collection points where it is processed and compressed for entry into the transmission pipeline grid. Revenue is derived primarily from two types of gathering and processing agreements based on volumetric fees or percentage-of-proceeds (POP) contracts. We are sensitive to fluctuations in the price of natural gas and natural gas liquids because a significant portion of this segment's revenue is from POP agreements. Under these agreements, we retain a percentage of the commodities as payment for our services, which we sell in the open market. We use derivative instruments to mitigate our commodity price exposure. Our natural gas gathering and processing segment is made up of the following subsidiaries: o Bear Paw Energy, LLC, with operations in the Williston and Powder River Basins; and o Crestone Energy Ventures, which owns: - a 49% interest in Bighorn Gas Gathering, L.L.C., with operations in the Powder River Basin; - a 33.33% interest in Fort Union Gas Gathering, L.L.C., with operations in the Powder River Basin; and - a 35% interest in Lost Creek Gathering, L.L.C., with operations in the Wind River Basin, located in Wyoming. In July 2005, Crestone Energy Ventures executed a purchase and sale agreement to acquire an additional 3.7% interest of Fort Union Gas Gathering, L.L.C., bringing its total interest to approximately 37%, for $5.3 million, subject to normal closing adjustments. We expect to close the transaction in August of 2005. MARKET CONDITIONS Key factors that may impact Bear Paw Energy and our joint venture interests are: o the pace of reserve development by producers, which is affected by: - a producer's ability to obtain drilling and production permits in a timely and economic manner; - reserve characteristics and performance; - surface access and infrastructure issues; - significant volumes of water associated with coalbed methane production; - environmental issues; o the decline rate of existing wells; o the composition of the gathered raw gas stream; and o the value of natural gas and natural gas liquids. For a more detailed discussion of market factors that may impact our gathering and processing segment, please read "Business - Future Demand and Competition" in our annual report on Form 10-K for the year ended December 31, 2004. 20 KNOWN TRENDS AND UNCERTAINTIES NATURAL GAS AND NATURAL GAS LIQUIDS PRICING - Our financial performance in the gathering and processing segment may be significantly impacted by the price of natural gas and natural gas liquids, particularly for the Williston Basin operations which involve primarily POP contracts. In the second quarter ended June 30, 2005, realized commodity prices, net of the effects of hedging, continued to increase: the weighted average price per gallon of natural gas liquids increased 50%, to $0.87 for the second quarter ended June 30, 2005, compared with $0.58 for the same period last year; the weighted average price per million British thermal units (mmBtu) of natural gas increased 23%, to $6.15 for the second quarter ended June 30, 2005, compared with $5.00 for the same period last year. RAW GAS COMPOSITION - Changes in the raw gas composition may impact our operating margins. Most of the wells connected to our Williston Basin facilities produce casinghead gas, which is significantly higher in energy content (measured in Btu) than coalbed methane gas that is produced in the Powder River Basin. Although generally the value of natural gas and natural gas liquids is related to the Btu content, certain products have greater value per Btu than others. GATHERING VOLUMES - Our financial performance in the gathering and processing segment may be impacted by the volume and pressure of gas gathered, particularly in the Powder River Basin. These contracts are primarily volumetric fee-based contracts. We provide two different levels of service depending on gas pressure. Our processing margins are higher for low pressure gas gathered compared with high pressure gas because of the amount of compression required to transport gas in our gathering system and into the interstate pipeline grid. As a result of these different services, the revenue impact from changes in our processing volumes does not change proportionately. POWDER RIVER BASIN DEVELOPMENT - The development of new facilities is based on well growth, field production, economics, permit considerations, and other factors that impact producers' decision to drill and produce coalbed methane gas. In the Powder River Basin, we believe drilling activity for the remainder of 2005 will be similar to that in 2004. Production is shifting westward in the basin toward the Big George Coal where dewatering times are lengthier but production volume is greater than in the eastern part of the basin. WILLISTON BASIN DEVELOPMENT - Bear Paw Energy owns and operates the Grasslands, Baker, Marmarth, Little Beaver and Lignite gathering and processing facilities. As a result of increased drilling and development in the Williston Basin, we expect continued growth in this area. We are selectively expanding our facilities and systems to enhance our financial performance. At current oil prices, we expect casinghead gas volume to increase at least through 2006. Due to additional land dedication in the Bakken Play, a second phase of expansion was initiated and completed in the second quarter ended June 30, 2005. A separate expansion is also under way in the Beaver Creek area. NATURAL GAS GATHERING AND PROCESSING SEGMENT OPERATING RESULTS The natural gas gathering and processing segment reported net income of $15.1 million for the second quarter ended June 30, 2005, compared with $7.8 million for the second quarter ended June 30, 2004. Net income was $28.8 million for the six months ended June 30, 2005, compared with $18.5 million for the same period last year. The increase of $7.3 million, or 94%, and $10.3 million, or 56%, for the three and six months ended June 30, 2005, respectively, as compared with the prior year, were largely attributable to favorable pricing for natural gas and natural gas liquids and increased processing volumes. Operating revenue increased $18.4 million, or 43%, in the second quarter ended June 30, 2005, compared with the second quarter ended June 30, 2004. Of this amount, $19.0 million was due to increased revenue realized in the Williston Basin as a result of increased natural gas and natural gas liquids prices and volumes, which were partially offset by lower volumes in the Powder River Basin. Operating revenue increased $35.3 million, or 42%, for the six months ended June 30, 2005, compared with the same period last year. Of this amount, $37.0 million was due to increased revenue realized in the Williston Basin, partially offset by $1.7 million decreased revenue realized in the Powder River Basin due a decline of our low margin gathering volumes. Product purchases were $35.5 million for the second quarter ended June 30, 2005, compared with $23.5 million for the same period last year. Product purchases were $67.9 million for the six months ended June 30, 2005, compared with $44.9 million for the six months ended June 30, 2004. Product purchases increased due to increased commodity prices and volumes processed. 21 Operations and maintenance expense decreased $0.4 million for the second quarter ended June 30, 2005, compared with the second quarter ended June 30, 2004, primarily due to a $1.2 million reduction of our allowance for doubtful accounts reflecting the agreements for the sale of the bankruptcy claims held against Enron and Enron North America, partially offset by increased expenses of $0.2 million related to the Charlie Creek expansion and increased general expenses of $0.2 million. Operations and maintenance expense increased $0.3 million for the six months ended June 30, 2005, which included increased operating expense related to the Charlie Creek expansion of $0.8 million. Equity earnings increased $0.8 million, or 24%, for the second quarter ended June 30, 2005, compared with the same period last year due to the overall growth in the Powder and Wind River Basins that resulted in higher volumes at Fort Union and Lost Creek. Equity earnings for the six months ended June 30, 2005, decreased $1.1 million compared with the same period in 2004 as a result of the Bighorn Gas Gathering preferred A cash flow incentives of $2.7 million recognized in 2004. For the six months ended June 30, 2005, equity earnings for Fort Union and Lost Creek increased $1.7 million compared with the same period last year due to the overall growth in the Powder and Wind River Basins. COAL SLURRY PIPELINE SEGMENT OVERVIEW Our coal slurry pipeline segment, which includes Black Mesa Pipeline Company, transports crushed coal suspended in water. Revenue is derived from a transportation contract with the sole supplier of coal to the Mohave Generating Station in Nevada. This contract generates fee-for-service revenue through December 31, 2005. KNOWN TRENDS AND UNCERTAINTIES Upon expiration of our transportation contract at the end of this year, we expect Black Mesa Pipeline to be temporarily shut down. Interested parties are working to resolve water supply, coal supply and transportation contracting issues in order for operations to resume. In addition, a final Environmental Impact Statement for the project must be issued which is anticipated in late 2006. We believe that successful resolution of these issues should result in the modification and reconstruction of our coal slurry pipeline in late 2008 and 2009. If these issues are not resolved and the Mohave Generating Station is permanently closed, we expect to incur shut down costs related to our pipeline of approximately $5 million to $7 million, and to have a non-cash charge of approximately $12 million related to goodwill and the remaining undepreciated cost of the pipeline. For more information about the environmental issues surrounding our coal slurry pipeline, please read "Business - Coal Slurry Pipeline Segment" in our annual report on Form 10-K for the year ended December 31, 2004. OPERATING RESULTS The coal slurry pipeline segment reported net income of $1.1 million for the second quarter ended June 30, 2005, compared with $0.9 million for the same period last year. Second quarter 2005 results include increased electricity costs of $0.3 million that were charged to the customer and recovered through operating revenue. Net income was $1.9 million for the six months ended June 30, 2005, compared with $1.5 million for the same period last year. Operating revenue increased $1.2 million and operating expense increased $0.9 million due to increased electricity costs. 22 OTHER Items that are not attributable to any segment included certain of our general and administrative expenses, interest expense on our debt and other income and expense items. For the second quarter ended June 30, 2005, interest expense not allocated to any segment increased $2.2 million as compared with the second quarter ended June 30, 2004, due to higher average debt outstanding and increased average interest rates. For the second quarter ended June 30, 2005, operations and maintenance expense increased $1.0 million as compared with the second quarter ended June 30, 2004. Operations and maintenance expense for 2005 included $0.4 million of expenses that will be allocated to our segments. Expenses in 2004 included a $0.5 million credit for previously accrued corporate charges. For the six months ended June 30, 2005, interest expense not allocated to any segment increased $4.6 million due to higher average debt outstanding and increased average interest rates. Operations and maintenance expense for the six months ended June 30, 2005, increased $1.3 million which included $0.8 million of relocation charges and other expenses that will be allocated to our segments. LIQUIDITY AND CAPITAL RESOURCES OVERVIEW We believe our liquidity is adequate to fund future recurring operating activities and investments. We rely on our operating cash flow and the credit facilities listed in the following table to meet our short-term liquidity needs. We expect to meet our other liquidity needs by issuing long-term debt and/or additional limited partner interests. The timing and our ability to complete such offerings will depend on various factors, including: o the prevailing market conditions; o interest rates; o our financial condition; and o our credit rating. DEBT AND CREDIT FACILITIES The Partnership's debt and credit facilities outstanding as of June 30, 2005, are as follows (in thousands):
Payments Due by Period ----------------------- Current Portion Long-Term Total < 1 Year Portion ---------- ---------- ---------- Northern Border Pipeline: $175 million credit agreement due 2010 (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 Viking Gas Transmission: Series A, B, C, and D senior notes due 2008 to 2014 average 7.46% 30,053 2,133 27,920 Northern Border Partners, L.P.: $500 million credit agreement due 2010 (a), average 3.75% 198,000 -- 198,000 8.875% senior notes due 2010 250,000 -- 250,000 7.10% senior notes due 2011 225,000 -- 225,000 ---------- ---------- ---------- Total $1,303,053 $ 2,133 $1,300,920 ========== ========== ==========
(a) Northern Border Partners, L.P. and Northern Border Pipeline are each required to pay a facility fee of 0.125% and 0.075%, respectively, on the principal commitment amount of their credit agreements. 23 On May 16, 2005, we entered into a five-year $500 million revolving credit agreement with several financial institutions. Under this agreement, we borrowed $186 million to pay the entire balance of our existing $275 million revolving credit agreement and terminated that agreement. At our option, the interest rate on the outstanding borrowings may be the lender's base rate or the London Interbank Offered Rate (LIBOR) plus a spread that is based on our long-term unsecured debt ratings. We are required to comply with certain financial, operational, and legal covenants, including the maintenance of EBITDA to interest expense ratio of greater than 3 to 1 and debt to EBITDA ratio of no more than 4.75 to 1. If we consummate one or more acquisitions in which the total purchase price exceeds $25 million, the allowable ratio of debt to adjusted EBITDA is increased to 5.25 to 1 for two calendar quarters following the acquisition. If we breach any of these covenants, the balance outstanding may become due and payable immediately. Also on May 16, 2005, Northern Border Pipeline Company entered into a five-year $175 million revolving credit agreement with several financial institutions. Under this agreement, Northern Border Pipeline borrowed $29 million to pay the entire balance on its existing $175 million revolving credit agreement and terminated that agreement. The borrowings of $29 million were subsequently repaid in the second quarter ended June 30, 2005. Similar to the Partnership's revolving credit agreement, Northern Border Pipeline may select the lender's base rate or the LIBOR plus a spread that is based on Northern Border Pipeline's long-term unsecured debt ratings as its interest rate on the borrowings. Northern Border Pipeline is required to comply with certain financial, operational, and legal covenants, including the maintenance of EBITDA to interest expense ratio of greater than 3 to 1 and debt to EBITDA ratio of no more than 4.50 to 1. If Northern Border Pipeline consummates one or more acquisitions in which the total purchase price exceeds $25 million, the allowable ratio of debt to adjusted EBITDA is increased to 5 to 1 for two calendar quarters following the acquisition. If Northern Border Pipeline breaches any of these covenants, the balance outstanding may become due and payable immediately. As of June 30, 2005, the Partnership and Northern Border Pipeline were in compliance with the covenants of their respective credit agreements. DEBT SECURITIES We anticipate issuing ten-year fixed rate senior notes during 2005 to reduce amounts drawn under our $500 million revolving credit agreement. HEDGING ACTIVITIES In 2004, we entered into forward-starting interest rate swap agreements with a total notional amount of $100 million in anticipation of a ten-year fixed rate senior notes issuance. The forward-starting interest rate agreements expired in late May and early June of 2005, which resulted in the Partnership paying $2.7 million to counterparties. In June 2005, we entered into a Treasury lock interest rate agreement with a total notional amount of $200 million in anticipation of a ten-year senior note issuance. In July 2005, we paid $0.1 million to the counterparty upon expiration of the June 2005 Treasury lock interest rate agreement. Our outstanding interest rate swap agreements with notional amounts totaling $150 million are due to expire in March of 2011. Under these agreements, we make payments to counterparties at variable rates based on LIBOR and receive payments based on a 7.10% fixed rate of return. As of June 30, 2005, the average effective interest rate on our interest rate swap agreements was 5.80%. OPERATING ACTIVITIES Net cash provided by operating activities decreased $18.5 million for the six months ended June 30, 2005, compared with the same period last year, as a result of decreased net income, which is discussed in the "Results of Operations" section of this quarterly report. Other factors were a $4.9 million decrease in distributions received from unconsolidated affiliates related to payments received in 2004 for our Bighorn Gas Gathering preferred A cash flow incentives and a net decrease in working capital of $5.9 million for the six months ended June 30, 2005, compared with a net decrease in working capital of $0.6 million for the same period in 2004. 24 INVESTING ACTIVITIES Net cash used in investing activities increased $15.6 million for six months ended June 30, 2005, as compared with the same period in 2004 primarily due to increased capital expenditures. Our investment in unconsolidated affiliates was $1.5 million for the six months ended June 30, 2005, representing contributions made to Bighorn Gas Gathering for its capital expenditures. Capital expenditures were $23.2 million for the six months ended June 30, 2005, including $13.0 million for the interstate natural gas pipeline segment and $9.6 million for the natural gas gathering and processing segment. For the interstate natural gas pipeline segment, approximately $1.6 million of the capital expenditures is related to Northern Border Pipeline's Chicago III Expansion Project and $2.1 million is related to Midwestern Gas Transmission's growth projects. The remaining capital expenditures for the six months ended June 30, 2005, were primarily related to renewals and replacements of existing facilities. For the natural gas gathering and processing segment, the capital expenditures for the six months ended June 30, 2005, were primarily related to the Partnership's expansions in the Williston Basin. Capital expenditures in the six months ended June 30, 2004, were $9.5 million which included $5.6 million for the interstate natural gas pipeline segment, $2.4 million for the natural gas gathering and processing segment and $1.5 million for the coal slurry pipeline segment. Total capital expenditures for 2005 are estimated to be approximately $87 million, which includes $55 million for the interstate natural gas pipeline segment. Of the $55 million projected expenditures for the interstate natural gas pipeline segment, approximately $12 million relates to Northern Border Pipeline's Chicago III Expansion Project, $8 million to $9 million relates to Midwestern Gas Transmission's Eastern Extension Project, and $2 million relates to Midwestern Gas Transmission's Southbound Expansion Project. Capital expenditures for the natural gas gathering and processing segment are estimated to be $28 million for 2005 primarily for growth capital expenditures. Funds required to meet our capital expenditure requirements for 2005 are anticipated to be provided from our credit facility and operating cash flow. Northern Border Pipeline currently anticipates funding its 2005 capital expenditures primarily by borrowing on its credit facility and using operating cash flow. FINANCING ACTIVITIES Net cash used in financing activities decreased $5.6 million for the six months ended June 30, 2005, compared with the same period in 2004. In the six months ended June 30, 2004, Northern Border Pipeline received equity contributions from its general partners which included $39 million from its minority interest holder that was used to repay existing debt. Borrowings on long-term debt for the six months ended June 30, 2005, were $86.0 million compared with $90.0 million for the six months ended June 30, 2004. Debt repayments for the six months ended June 30, 2005, were $81.7 million and $134.8 million for the six months ended June 30, 2004. Payments for the termination of derivative instruments were $2.7 million for the six months ended June 30, 2005. THE IMPACT OF ENRON'S CHAPTER 11 FILING ON OUR BUSINESS In June 2005, Northern Border Pipeline Company, Crestone Gathering Services and Bear Paw Energy, LLC executed term sheets with a third party for the sale of their unsecured claims held against Enron and Enron North America. Proceeds from the sale are expected to be $14.6 million. In 2004, we adjusted our allowance for doubtful accounts to reflect an estimated $3.4 million ($3.0 million, net to the Partnership) recovery for our claims. In the second quarter of 2005, we made an adjustment to our allowance for doubtful accounts of approximately $1.8 million ($1.6 million, net to the Partnership) to reflect the agreements for the sales. As a result of the sale, Northern Border Pipeline anticipates recognizing additional income of $9.4 million ($6.6 million, net to the Partnership) later in 2005. 25 In June 2005, Enron filed an amended motion in the bankruptcy court seeking approval to terminate the Enron Gas Pipeline Employee Benefit Trust (Trust) and to distribute its assets among certain identified companies, one being Northern Border Pipeline's operator, Northern Plains Natural Gas Company, LLC. If Enron's relief is granted as requested, Northern Plains would assume retiree benefit liabilities, estimated as of November 17, 2004, of approximately $2.3 million with an asset allocation of approximately $1.7 million. Northern Natural Gas Company, a participant in the Trust through June 30, 2002, along with other parties have filed a motion to strike Enron's amended motion alleging that allocation of the assets and liabilities of the Trust should be decided in a pending lawsuit filed in the United States District Court for the District of Nebraska and not in the bankruptcy court. For more information about the bankruptcy claims held by us against Enron and Enron North America, please refer to "Management's Discussion and Analysis of Financial Condition and Results of Operations - Update on the Impact of Enron's Chapter 11 Filing on our Business" in our annual report on Form 10-K for the year ended December 31, 2004, and our quarterly report on Form 10-Q for the first quarter ended March 31, 2005. FORWARD-LOOKING STATEMENTS AND RISK FACTORS The statements in this quarterly report that are not historical information are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. 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 include the following: Interstate Natural Gas Pipeline Segment: o the impact of uncontracted capacity on Northern Border Pipeline being greater than expected; o the ability to market pipeline capacity on favorable terms, which is affected by: - future demand for and prices of natural gas; - competitive conditions in the overall natural gas and electricity markets; - availability of supplies of Canadian natural gas; - availability of additional storage capacity; - weather conditions; and - competitive developments by Canadian and U.S. natural gas transmission peers; o performance of contractual obligations by the shippers; o political and regulatory developments that impact FERC proceedings involving interstate pipelines and the interstate pipelines' success in sustaining their positions in such proceedings; o the ability to recover costs in our rates; Natural Gas Gathering and Processing Segment: o the rate of development, gas quality, and competitive conditions in gas fields near our natural gas gathering systems in the Powder River and Williston Basins and our investments in the Powder River and Wind River Basins; o prices of natural gas and natural gas liquids; o the composition and quality of the natural gas we gather and process in our plants; o the efficiency of our processing plants in extracting natural gas and natural gas liquids; Coal Slurry Pipeline Segment: o renewal of the coal slurry transportation contract under favorable terms; General: o developments in the December 2, 2001, filing by Enron of a voluntary petition for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code affecting our settled claims; o regulatory actions and receipt of expected regulatory clearances; o actions by rating agencies; o the ability to control operating costs; o conditions in the capital markets and the ability to access the capital markets; and o acts of nature, sabotage, terrorism or other similar acts causing damage to our facilities. 26 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 future results. These and other risks are described in greater detail in the section entitled "Management's Discussion and Analysis of Financial Condition and Results of Operations - Risk Factors and Information Regarding Forward-Looking Statements" included in our annual report on Form 10-K for the year ended December 31, 2004. 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 the securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or changes in circumstances, changes in expectations or otherwise. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK OVERVIEW We may be exposed to market risk through changes in interest rates and commodity prices. We may utilize financial instruments to manage interest rate and commodity price risk to reduce our exposure to interest rate and price fluctuations and achieve a more predictable cash flow. We established policies and procedures to assess risk and to approve, report, and monitor our financial instrument activities. We do not use these instruments for trading purposes. INTEREST RATE RISK Our interest rate exposure is a result of variable rate borrowings. To reduce our sensitivity to interest rate fluctuations, we may maintain a portion of our consolidated debt portfolio in fixed-rate debt. We may also use interest rate swap agreements to manage interest expense by converting a portion of fixed-rate debt to variable-rate debt. As of June 30, 2005, we had $348 million of variable-rate debt outstanding, $150 million of which we converted from fixed-rate to variable-rate debt through interest rate swap agreements. Approximately 73% of our debt portfolio was fixed-rate debt as of June 30, 2005. To summarize our sensitivity to interest rate fluctuations, if interest rates on average change by one percent versus rates that were in effect as of June 30, 2005, consolidated annual interest expense would change by approximately $3.5 million. The impact of the hypothetical interest rates on our variable rate borrowings outstanding was determined as of the end of the second quarter ended June 30, 2005. COMMODITY PRICE RISK Bear Paw Energy's natural gas gathering and processing contracts are sensitive to the price of natural gas and natural gas liquids because a significant portion of its revenue is from the sale of commodities received from POP agreements. As of June 30, 2005, approximately 67% of our commodity price-sensitive revenue for the remainder of 2005, based on our projected throughput volume, was hedged. Considering the effects of hedging, each $0.10 per mmBtu change in natural gas price will have an approximate $0.2 million impact to revenue, and each $0.01 per gallon change in natural gas liquids price will have an approximate $0.2 million impact to revenue for 2005. We analyze our sensitivity based on hypothetical commodity prices on our projected gathering and processing volumes for the remainder of 2005. This analysis may be impacted by changes in our projected throughput volumes. We hedged approximately 23% of our commodity price-sensitive revenue for 2006 as of the end of the second quarter ended June 30, 2005. Considering the effects of hedging, each $0.10 per mmBtu change in natural gas price will have an approximate $0.3 million impact to revenue for 2006, and each $0.01 per gallon change in natural gas liquids price will have an approximate $0.4 million impact to revenue for 2006. 27 ITEM 4. CONTROLS AND PROCEDURES EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES As of the end of the period covered by this report, our chief executive officer and chief financial and accounting officer have evaluated the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended. Based on their evaluation, they have concluded that as of June 30, 2005, 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 Securities Exchange Act of 1934, as amended, is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission's rules and forms. CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING There were no changes in our internal control over financial reporting during the quarter ended June 30, 2005, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. In March 2004, Enron transferred its ownership interests in Northern Plains and NBP Services to CrossCountry Energy, LLC. In November 2004, ONEOK purchased Northern Plains and NBP Services. Transition services agreements were entered into to provide to Northern Plains and NBP Services on an interim, transitional basis, various services, including but not limited to (i) information technology services, (ii) accounting system usage rights and administrative support and (iii) payroll, employee benefits and administrative services. In turn, these services are provided to us and our subsidiaries through Northern Plains and NBP Services. During the second quarter of 2005, the transition of these services to ONEOK or us was completed and in the review process it was determined that there were no material changes to our internal controls over financial reporting. PART II OTHER INFORMATION ITEM 5. OTHER INFORMATION On July 1, 2005, ONEOK announced the appointment of Pierce H. Norton as senior vice president of ONEOK's gathering and processing segment. Mr. Norton remains president of Bear Paw Energy, a subsidiary of the Partnership and vice president and general manager for midstream businesses for NBP Services, LLC, having been appointed to these positions in 2003. ITEM 6. EXHIBITS The following exhibits are filed as part of this quarterly report on Form 10-Q: 10.1 Revolving Credit Agreement, dated as of May 16, 2005, 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, and SunTrust Capital Markets, Inc and Wachovia Capital Markets, LLC, as co-lead arrangers and book managers (incorporated by reference to Exhibit 10.1 to the Partnership's current report on Form 8-K (File No. 1-12202) filed on May 20, 2005). +10.2 First Amendment to Revolving Credit Agreement, effective June 13, 2005, 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. 10.3 Revolving Credit Agreement, dated as of May 16, 2005, 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, Harris Nesbit Financing, Inc., Barclays Bank PLC and Citibank, N.A., as co-documentation agents, and Wachovia Capital Markets, LLC and SunTrust Capital Markets, Inc., as co-lead arrangers and book managers (incorporated by reference to Exhibit 10.1 to Northern Border Pipeline Company's current report on Form 8-K (File No. 333-88577) filed on May 20, 2005).
28 +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 and Accounting Officer. +32.1 Section 1350 Certification of Chief Executive Officer. +32.2 Section 1350 Certification of Chief Financial and Accounting Officer.
- --------- +Filed herewith 29 SIGNATURE 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: August 8, 2005 By: /s/ Jerry L. Peters -------------------------------------- Jerry L. Peters Chief Financial and Accounting Officer 30 EXHIBIT INDEX
Exhibit No. Description - ----------- ----------- 10.1 Revolving Credit Agreement, dated as of May 16, 2005, 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, and SunTrust Capital Markets, Inc and Wachovia Capital Markets, LLC, as co-lead arrangers and book managers (incorporated by reference to Exhibit 10.1 to the Partnership's current report on Form 8-K (File No. 1-12202) filed on May 20, 2005). +10.2 First Amendment effective June 13, 2005 to Revolving Credit Agreement dated as of May 16, 2005, among Northern Border Partners, L.P., and the lenders named therein, 10.3 Revolving Credit Agreement, dated as of May 16, 2005, 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, Harris Nesbit Financing, Inc., Barclays Bank PLC and Citibank, N.A., as co-documentation agents, and Wachovia Capital Markets, LLC and SunTrust Capital Markets, Inc., as co-lead arrangers and book managers (incorporated by reference to Exhibit 10.1 to Northern Border Pipeline Company's current report on Form 8-K (File No. 333-88577) filed on May 20, 2005). +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 and Accounting Officer. +32.1 Section 1350 Certification of Chief Executive Officer. +32.2 Section 1350 Certification of Chief Financial and Accounting Officer.
- ------------------ + Filed herewith. 31 EX-10.2 2 h27464exv10w2.txt FIRST AMENDMENT TO REVOLVING CREDIT AGREEMENT EXHIBIT 10.2 FIRST AMENDMENT TO REVOLVING CREDIT AGREEMENT THIS FIRST AMENDMENT TO REVOLVING CREDIT AGREEMENT (this "Amendment") dated effective June 13, 2005, is entered into by and among NORTHERN BORDER PARTNERS, L.P., a Delaware limited partnership (the "Borrower"), the several banks and other financial institutions and lenders from time to time party hereto (the "Lenders"), SUNTRUST BANK, in its capacity as administrative agent for the Lenders (the "Administrative Agent"), as issuing bank (the "Issuing Bank") and as swingline lender (the "Swingline Lender"), WACHOVIA BANK, NATIONAL ASSOCIATION, as syndication agent (the "Syndication Agent") and HARRIS NESBIT FINANCING, INC., BARCLAYS BANK PLC, and CITIBANK, N.A., as co-documentation agents (the "Co-documentation Agents"). All capitalized terms used in this Amendment and not otherwise defined herein have the meanings ascribed to such terms in the Credit Agreement (as defined below). PRELIMINARY STATEMENT The Borrower, the Administrative Agent, the Issuing Bank, the Swingline Lender, the Syndication Agent, the Co-Documentation Agents, and the Lenders are parties to that certain Revolving Credit Agreement dated as of May 16, 2005 (the "Credit Agreement"), under the terms of which such Lenders have committed to make Revolving Loans and issue Letters of Credit in an aggregate amount not to exceed $500,000,000. The Borrower has requested that the Lenders amend the Credit Agreement as set forth herein. The Lenders are agreeable to such request, upon the conditions set forth herein. NOW THEREFORE, in consideration of the premises and other good and valuable consideration, the receipt and adequacy of which are hereby acknowledged by the parties hereto, the Borrower, the Guarantor, the Administrative Agent, the Issuing Bank, the Swingline Lender, the Syndication Agent, the Co-Documentation Agents and the Lenders hereby agree as follows: Section 1. Amendments to Credit Agreement. (a) Sub-Section 7.1(h) of the Credit Agreement is hereby deleted in its entirety, and replaced as follows: "(h) the guaranty by Intermediate Partnership of the Borrower's Indebtedness;" Section 2. No Obligation. Notwithstanding this Amendment, the Lenders shall have no further obligation to extend, renew or modify the Credit Agreement as amended by this Amendment and no further obligation of any kind in excess of those expressly set forth herein shall be inferred from this Amendment. Section 3. Ratification. The Borrower and the Guarantor hereby ratify each of their respective obligations under the Credit Agreement, the Guaranty and the Loan Documents to which they are a party, and agree and acknowledge that the Credit Agreement, the Guaranty and each of the Loan Documents shall continue in full force and effect as amended and modified by this Amendment. Nothing in this Amendment extinguishes, novates or releases any right, claim, lien, security interest or entitlement of any of the Lenders created by or contained in any of such documents nor is the Borrower or the Guarantor released from any covenant, warranty or obligation created by or contained therein except as expressly provided herein. The Guarantor has reviewed this Amendment and, as deemed necessary by the Guarantor, received legal advice regarding its content. The Guarantor consents to the execution of this Amendment by the Borrower. The Guarantor is executing this Amendment below to agree and confirm that its obligations under the Guaranty Agreement remains in full force and effect unaffected by this Amendment. The Guarantor understands and agrees that it remains fully primarily liable for the "Guaranteed Obligations" (as defined in the Guaranty). Section 4. Representations True; No Default. The Borrower and the Guarantor represent and warrant to the Administrative Agent and the Lenders that: (a) this Amendment has been duly authorized, executed and delivered on behalf of the Borrower. The Credit Agreement as amended hereby and the Notes, together with each other Loan Document to which the Borrower is a party, constitute valid and legally binding agreements of the Borrower enforceable in accordance with their terms; (b) the execution, delivery and performance by the Borrower of this Amendment (i) does not require any consent or approval of, registration or filing with, or any action by, any Governmental Authority, except those as have been obtained or made and are in full force and effect, (ii) will not violate any Requirements of Law applicable to the Borrower or any of its Subsidiaries or any judgment, order or ruling of any Governmental Authority, (iii) will not violate or result in a default under any indenture, agreement or other instrument binding on the Borrower or any of its Subsidiaries or any of its assets or give rise to a right thereunder to require any payment to be made by the Borrower or any of its Subsidiaries, in each case other than violations, defaults or rights which could not reasonably expected to result in a Material Adverse Effect, and (iv) will not result in the creation or imposition of any Lien on any asset of the Borrower or any of its Subsidiaries, except Liens (if any) created under the Loan Documents. (c) the representations and warranties of the Borrower contained in Article IV of the Credit Agreement are true and correct in all material respects on and as of the date hereof as though made on and as of the date hereof, except to the extent such representations and warranties relate solely to an earlier date; and (d) after giving effect to this Amendment, there has not occurred and is continuing an Event of Default or any event which with notice or lapse of time would become an Event of Default. Section 5. Effectiveness. This Amendment shall become effective when, and only when, the Borrower, the Guarantor and the Required Lenders shall have executed a counterpart of this Amendment and the Administrative Agent shall have received delivery of same. The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of the Lenders -2- under the Credit Agreement, nor constitute a waiver of any provision of the Credit Agreement. This Amendment shall constitute a Loan Document for all purposes of the Credit Agreement. Section 6. Expenses. The Borrower agrees to pay on demand all costs and expenses, if any (including, without limitation, reasonable counsel fees and expenses), in connection with the negotiation, preparation and enforcement (whether through negotiations, legal proceedings or otherwise) of this Amendment, including, without limitation, reasonable counsel fees and expenses in connection with the enforcement of rights under this Section. Section 7. Miscellaneous Provisions. (a) From and after the execution and delivery of this Amendment, the Credit Agreement shall be deemed to be amended and modified as herein provided, but except as so amended and modified the Credit Agreement, the Notes and all other Loan Documents shall continue in full force and effect. (b) The Credit Agreement and this Amendment shall be read and construed as one and the same instrument. (c) Any reference in any Loan Document to the Credit Agreement shall be a reference to the Credit Agreement as amended by this Amendment. (d) This Amendment shall be construed in accordance with and governed by the laws of the State of New York and of the United States of America. (e) This Amendment may be signed in any number of counterparts and by different parties in separate counterparts, each of which shall be deemed an original but all of which together shall constitute one and the same instrument. Delivery of an executed counterpart of this Amendment by facsimile transmission or by electronic mail in pdf form shall be as effective as delivery of a manually executed counterpart hereof. (f) The headings herein shall be accorded no significance in interpreting this Amendment. Section 8. Binding Effect. The Amendment shall be binding upon and inure to the benefit of the Borrower, the Administrative Agent, the Issuing Bank, the Swingline Lender, the Co-Documentation Agents and the Lenders and the successors and assigns of such parties. The Borrower shall not have the right to assign its rights hereunder or any interest herein. Section 9. Final Agreement of the Parties. This Amendment, the Notes, the Credit Agreement and the other Loan Documents represent the final agreement between the parties and may not be contradicted by evidence of prior, contemporaneous or subsequent oral agreements of the parties. There are no unwritten oral agreements between the parties. [SIGNATURE PAGES FOLLOW] -3- IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed by their respective authorized officers as of the day and year first above written. NORTHERN BORDER PARTNERS, L.P. By: /s/ Jerry L. Peters -------------------------- Name: Jerry L. Peters Title: Chief Financial and Accounting Officer SUNTRUST BANK AS ADMINISTRATIVE AGENT, AS ISSUING BANK, AS SWINGLINE LENDER AND AS A LENDER By /s/ David Edge --------------------------- Name: David Edge Title: Managing Director [Signature Page to the First Amendment to Revolving Credit Agreement] WACHOVIA BANK, NATIONAL ASSOCIATION AS SYNDICATION AGENT AND AS A LENDER By /s/ Shannan Townsend --------------------------------- Name: Shannan Townsend Title: Director [Signature Page to the First Amendment to Revolving Credit Agreement] HARRIS NESBITT FINANCING, INC., as a Lender By: /s/ Cahal B. Carmody -------------------------------- Name: Cahal B. Carmody Title: Vice President [Signature Page to the First Amendment to Revolving Credit Agreement] BARCLAYS BANK PLC, as a Lender By: /s/ Nicholas Bell -------------------------------- Name: Nicholas Bell Title: Director [Signature Page to the First Amendment to Revolving Credit Agreement] CITIBANK, N.A., as a Lender By: /s/ Amy K. Pincu ------------------------------------ Name: Amy K. Pincu Title: Attorney-in-fact [Signature Page to the First Amendment to Revolving Credit Agreement] UBS LOAN FINANCE LLC, as a Lender By: /s/ Wilfred V. Saint ------------------------------------ Name: Wilfred V. Saint Title: Director Banking Products Services, US By: /s/ Joselin Fernandes ------------------------------------ Name: Joselin Fernandes Title: Associate Director Banking Products Services, US [Signature Page to the First Amendment to Revolving Credit Agreement] ROYAL BANK OF CANADA, as a Lender By: /s/ David A. McCluskey ------------------------------------ Name: David A. McCluskey Title: Authorized Signatory [Signature Page to the First Amendment to Revolving Credit Agreement] THE ROYAL BANK OF SCOTLAND PLC, as a Lender By: /s/ Keith Johnson ------------------------------------ Name: Keith Johnson Title: Senior Vice President [Signature Page to the First Amendment to Revolving Credit Agreement] BANK OF AMERICA, as a Lender By: /s/ Jeffery H. Rathkamp ------------------------------------ Name: Jeffery H. Rathkamp Title: Director [Signature Page to the First Amendment to Revolving Credit Agreement] BAYERISCHE HYPO-UND VEREINSBANK, AG, NEW YORK BRANCH, as a Lender By: /s/ Yoram Dankner ------------------------------------ Name: Yoram Dankner Title: Managing Director By: /s/ Shannon Batchman ------------------------------------ Name: Shannon Batchman Title: Director [Signature Page to the First Amendment to Revolving Credit Agreement] COMERICA BANK, as a Lender By: /s/ Peter L Sefzik ------------------------------------ Name: Peter L. Sefzik Title: Vice President [Signature Page to the First Amendment to Revolving Credit Agreement] MIZUHO CORPORATE BANK, LTD., as a Lender By: ____________________________________ Name: Title: [Signature Page to the First Amendment to Revolving Credit Agreement] U.S. BANK NATIONAL ASSOCIATION, as a Lender By: /s/ Mark E. Thompson ------------------------------------ Name: Mark E. Thompson Title: Vice President [Signature Page to the First Amendment to Revolving Credit Agreement] WELLS FARGO BANK, N.A., as a Lender By: /s/ Tim Green ------------------------------------ Name: Tim Green Title: Portfolio Manager [Signature Page to the First Amendment to Revolving Credit Agreement] Acknowledged and Agreed, this 13th day of June, 2005 NORTHERN BORDER INTERMEDIATE LIMITED PARTNERSHIP By: /s/ Jerry L. Peters --------------------------------------------- Name: Jerry L. Peters Title: Chief Financial and Accounting Officer [Signature Page to the First Amendment to Revolving Credit Agreement] EX-31.1 3 h27464exv31w1.txt CERTIFICATION OF CEO TO RULE 13A-14A/15D-14A EXHIBIT 31.1 CERTIFICATION I, William R. Cordes, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Northern Border Partners, L.P.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: August 8, 2005 /s/ William R. Cordes ----------------------------- William R. Cordes Chief Executive Officer EX-31.2 4 h27464exv31w2.txt CERTIFICATION OF CFAO TO RULE 13A-14A/15D-14A EXHIBIT 31.2 CERTIFICATION I, Jerry L. Peters, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Northern Border Partners, L.P.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles ; c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: August 8, 2005 /s/ Jerry L. Peters --------------------------------------- Jerry L. Peters Chief Financial and Accounting Officer EX-32.1 5 h27464exv32w1.txt CERTIFICATION OF CEO PURSUANT TO SECTION 1350 EXHIBIT 32.1 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the quarterly report on Form 10-Q of Northern Border Partners, L.P. (the "Partnership") for the quarter ended June 30, 2005 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), William R. Cordes, as Chief Executive Officer of the Partnership, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of section 13(a) or section 15(d), as applicable, of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership. Dated: August 8, 2005 /s/ William R. Cordes ------------------------------------- William R. Cordes Chief Executive Officer This certification is made solely for the purpose of 18 U.S.C. Section 1350, and not for any other purpose. EX-32.2 6 h27464exv32w2.txt CERTIFICATION OF CFAO PURSUANT TO SECTION 1350 EXHIBIT 32.2 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the quarterly report on Form 10-Q of Northern Border Partners, L.P. (the "Partnership") for the quarter ended June 30, 2005 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), Jerry L. Peters, as Chief Financial and Accounting Officer of the Partnership, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of section 13(a) or section 15(d), as applicable, of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership. Dated: August 8, 2005 /s/ Jerry L. Peters -------------------------------------- Jerry L. Peters Chief Financial and Accounting Officer This certification is made solely for the purpose of 18 U.S.C. Section 1350, and not for any other purpose. -----END PRIVACY-ENHANCED MESSAGE-----