10-Q 1 h27564e10vq.txt NORTHERN BORDER PIPELINE COMPANY - 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: 333-88577 NORTHERN BORDER PIPELINE COMPANY (Exact name of registrant as specified in its charter) Texas 74-2684967 ------------------------------------- ------------------------------------- (State or other jurisdiction of (I.R.S. Employer Identification 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) Not applicable ---------------------------------------------------- (Former name, former address and former fiscal year, if changed since last report) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 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 [ ] No [X] Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Not applicable. 1 NORTHERN BORDER PIPELINE COMPANY QUARTERLY REPORT ON FORM 10-Q TABLE OF CONTENTS

2 PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS NORTHERN BORDER PIPELINE COMPANY STATEMENT OF INCOME (UNAUDITED)

NORTHERN BORDER PIPELINE COMPANY STATEMENT OF COMPREHENSIVE INCOME (UNAUDITED)

The accompanying notes are an integral part of these financial statements. 3 NORTHERN BORDER PIPELINE COMPANY BALANCE SHEET (UNAUDITED)

The accompanying notes are an integral part of these financial statements. 4 NORTHERN BORDER PIPELINE COMPANY STATEMENT OF CASH FLOWS (UNAUDITED)

The accompanying notes are an integral part of these financial statements. 5 NORTHERN BORDER PIPELINE COMPANY STATEMENT OF CHANGES IN PARTNERS' EQUITY (UNAUDITED)

The accompanying notes are an integral part of these financial statements. 6 NORTHERN BORDER PIPELINE COMPANY NOTES TO FINANCIAL STATEMENTS 1. BASIS OF PRESENTATION In this report, references to "we," "us" or "our" collectively refer to Northern Border Pipeline Company. We have prepared the financial statements included herein without audit pursuant to the rules and regulations of the Securities and Exchange Commission. The 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 financial statements should be read in conjunction with the 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. 2. CREDIT FACILITIES We entered into a $175 million five-year credit agreement (2005 Pipeline Credit Agreement) with certain financial institutions in May 2005. The 2005 Pipeline Credit Agreement is to be used to refinance existing indebtedness, fund capital expenditures and for general business purposes. 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. The 2005 Pipeline Credit Agreement permits us to specify the portion of the borrowings to be covered by specific interest rate options and to specify the interest rate period. We are required to pay a fee on the principal commitment amount of $175 million. As of June 30, 2005, there were no amounts outstanding under the 2005 Pipeline Credit Agreement. Under the 2005 Pipeline Credit Agreement, we are required to comply with certain financial, operational and legal covenants. Among other things, we are required to 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. We are also required to maintain a ratio of indebtedness to EBITDA of no more than 4.50 to 1. Pursuant to the 2005 Pipeline Credit Agreement, 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 to 1 for two calendar quarters following the acquisition. Upon any breach of these covenants, amounts outstanding under the 2005 Pipeline Credit Agreement may become immediately due and payable. As of June 30, 2005, we were in compliance with these covenants. 3. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES We use financial instruments in the management of our interest rate 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. As of June 30, 2005, there were no outstanding interest rate swap agreements. 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 $0.4 million and $0.7 million, respectively, related to the terminated interest rate swap agreements as a reduction to interest expense from accumulated other comprehensive income. We expect to amortize approximately $0.4 million in each of the remaining quarters of 2005. 7 We record in long-term debt amounts received or paid related to terminated 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. During the three and six months ended June 30, 2005, we amortized approximately $0.5 million and $1.1 million, respectively, as a decrease to interest expense. We expect to amortize approximately $0.5 million in each of the remaining quarters of 2005. 4. 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. 5. RELATIONSHIPS WITH ENRON In June 2005, we executed term sheets with a third party for the sale of our unsecured claims for transportation contracts and associated guarantees held against Enron Corp. and Enron North America Corp. Proceeds from the sale are expected to be $11.1 million. In 2004, we adjusted our allowance for doubtful accounts to reflect an estimated recovery of $1.1 million for the claims. In the second quarter of 2005, we made an adjustment to our allowance for doubtful accounts of $0.6 million to reflect the agreements for the sale. As a result of the sale, we anticipate recognizing additional income of $9.4 million later in 2005. 6. 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. 7. SUBSEQUENT EVENTS We make distributions to our general partners approximately one month following the end of the quarter. The distributions for the second quarter of 2005 of approximately $39.4 million were paid August 1, 2005. 8 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 financial statements and notes included in Item 1 of this quarterly report on Form 10-Q. References to "we," "us" or "our" collectively refer to Northern Border Pipeline Company. EXECUTIVE SUMMARY OVERVIEW Northern Border Pipeline Company is a general partnership formed in 1978. Northern Border Partners, L.P. owns a 70% general partner interest in us and TC PipeLines, LP owns the remaining 30%. Both Northern Border Partners and TC PipeLines are publicly-traded partnerships. We are a leading transporter of natural gas imported from Canada into the United States. RECENT DEVELOPMENTS CONTRACTING - During the second quarter of 2005, we had available capacity on the Port of Morgan, Montana to Ventura, Iowa portion of the pipeline which remained uncontracted. We discounted transportation rates on a short-term basis to maximize overall revenue, and have since contracted all of our 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 our revenue for 2005 will be $15 million to $18 million lower than 2004 revenue which generally reflected contracting nearly all capacity at maximum rate levels. CREDIT AGREEMENT - In May 2005, we entered into a five-year $175 million revolving credit agreement. We terminated our existing $175 million credit facility in conjunction with the execution of the new agreement. Please read "Liquidity and Capital Resources - Debt and Credit Facilities" in this section for more information. BANKRUPTCY CLAIMS - In June 2005, we executed term sheets with a third party for the sale of our unsecured claims for transportation contracts and associated guarantees held against Enron Corp. and Enron North America Corp. Proceeds from the sale are expected to be $11.1 million. In 2004, we adjusted our allowance for doubtful accounts to reflect an estimated recovery of $1.1 million for the claims. In the second quarter of 2005, we made a favorable adjustment to our allowance for doubtful accounts of $0.6 million to reflect the agreements for the sale. As a result of the sale, we anticipate recognizing additional income of $9.4 million later in 2005. 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 our compressor stations will be taxed. We estimate that this additional tax will be approximately $1.5 million to $2.0 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 6 of the Notes to Financial Statements included in Item 1 of this quarterly report on Form 10-Q. 9 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: - the economic useful life of our assets used to determine depreciation and amortization; - the fair value used to determine possible asset impairment charges; - the fair value used to record derivative assets and liabilities; - the fair value of assets acquired; and - the amount of expense accruals. 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 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 Our accounting policies conform to SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Accordingly, certain 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, we reflected regulatory assets of $12.4 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 pipelines are determined by the Federal Energy Regulatory Commission's (FERC) ratemaking process. Revisions to the estimated economic useful lives of our assets would impact our depreciation and amortization expense in future periods. DERIVATIVE INSTRUMENTS We use derivative instruments to mitigate 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, there were no derivative financial instruments outstanding. REVENUE RECOGNITION We recognize revenues 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 pipeline, regardless of how much natural gas is actually transported. 10 RESULTS OF OPERATIONS OVERVIEW We transport natural gas along 1,249 miles of pipeline that extends from the United States-Canadian border near Port of Morgan, Montana to a terminus near North Hayden, Indiana for our customers. Our pipeline system connects with multiple pipelines providing shippers access to the various natural gas markets served by those pipelines. Operating revenue is derived from transportation contracts under our tariff regulated by the FERC. The tariff specifies 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 pipeline, 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. MARKET CONDITIONS As of December 31, 2004, approximately 88% of the natural gas we transported 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 the Chicago market area. Some of the significant factors that may impact our customer's desire to move natural gas on our interstate pipeline include: - the amount of Canadian natural gas available for export, which is impacted by Canadian supply and demand; - the ability to transport Canadian gas on other pipelines; - the amount of storage capacity for Canadian gas and demand for storage injection; - the availability of natural gas from other supply sources that could be transported to the Midwestern United States; - 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 - 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 Pipeline Transportation Capacity" in our annual report on Form 10-K for the year ended December 31, 2004. 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. 11 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 the 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 is 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 impacts the demand for our capacity. As previously disclosed, we had uncontracted capacity during the second quarter ended June 30, 2005, on our 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 projects currently underway include our Chicago III Expansion Project, a proposed expansion of our pipeline system into the Chicago market area. We have filed our application for a certificate of public convenience and necessity for the construction and operation of the facilities. We anticipate 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 million cubic feet per day of transportation capacity from Harper, Iowa to Chicago, Illinois. Please refer to "Management's Discussion and Analysis of Financial Condition and Results of Operations" in our annual report on Form 10-K for the year ended December 31, 2004, for more information about the Chicago III Expansion Project. REGULATORY DEVELOPMENTS RATE CASE - Under the terms of our 1999 rate case, we 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. Our 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. 12 OPERATING RESULTS Net income to partners decreased $12.5 million, or 30%, from $41.3 million for the second quarter ended June 30, 2004, to $28.8 million for the second quarter ended June 30, 2005. For the six months ended June 30, 2005, net income to partners decreased $13.7 million, or 16%, from $83.1 million in 2004 to $69.4 million in 2005. This reduction of net income was primarily due to the revenue impact from uncontracted and discounted capacity during 2005 on the Port of Morgan, Montana to Ventura, Iowa portion of the pipeline. Operating revenue decreased $11.7 million, or 14%, for the second quarter ended June 30, 2005, compared with the same quarter last year primarily due to $13.0 million decreased revenue associated with our uncontracted and discounted capacity, partially offset by $1.3 million increased short-term and other transportation service revenue. Operating revenue decreased $12.2 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 of 2005 items and one additional day of transportation revenue in the first quarter of 2004 due to leap year. Operations and maintenance expense decreased $0.5 million for the second quarter ended June 30, 2005, as compared with the prior year, as a result of the reduction of allowance for our doubtful accounts by approximately $0.6 million related to bankruptcy claims against Enron Corp. and Enron North America Corp. and a decrease in general and administrative expenses of $0.4 million. The second quarter ended June 30, 2004, includes a credit of approximately $1.2 million to true up corporate charges which was partially offset by $0.7 million of amortization expense for the renewal of a right-of-way easement. Operations and maintenance expense for the six months ended June 30, 2005, was flat compared with the same period in 2004. Taxes other than income increased $1.0 million for the quarter ended June 30, 2005, and $1.0 million for the six months ended June 30, 2005, compared with the same periods in 2004 reflecting tax adjustments made in the second quarter ended June 30, 2005, and 2004 to reflect actual tax amounts. Interest expense increased $0.7 million for the second quarter ended June 30, 2005, and increased $1.1 million for the six months ended June 30, 2005, compared with the same periods last year as a result of higher average interest rates partially offset by lower average debt outstanding. 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 facility 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. The timing and our ability to issue debt will depend on various factors, including: - the prevailing market conditions; - interest rates; - our financial condition; and - our credit rating. 13 DEBT AND CREDIT FACILITIES Our debt and credit facilities outstanding as of June 30, 2005, are as follows (in thousands):

(a) We are required to pay a facility fee of 0.0075% on the principal commitment amount of our credit agreement. On May 16, 2005, we entered into a five-year $175 million revolving credit agreement with several financial institutions. Under this agreement, we borrowed $29 million to pay the entire balance on our 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. We may select 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 as the interest rate on the loan. 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 4.50 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 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. As of June 30, 2005, we were in compliance with the covenants of our credit agreement. OPERATING ACTIVITIES Net cash provided by operating activities declined $7.9 million for the six months ended June 30, 2005, compared with the same period last year primarily as a result of lower operating revenues of $12.2 million and higher interest expense of $1.1 million for 2005. Offsetting this decrease were the following: - $0.8 million received for our bankruptcy claims against Enron and Enron North America; - $1.8 million received for miscellaneous receivables; and - $3.0 million decreased accounts payable reflected in 2004 related to the payment of 2002/2003 corporate charges. INVESTING ACTIVITIES Net cash used in investing activities increased $5.6 million for the six months ended June 30, 2005, compared with the same period in 2004. For 2005, $1.6 million is related to the Chicago III Expansion Project, a proposed expansion of the pipeline system into the Chicago market area. The remaining capital expenditures for 2005 are primarily related to renewals and replacements of existing facilities. For the six months ended June 30, 2004, total capital expenditures were $4.5 million, which were primarily related to renewals and replacements of existing facilities. Total capital expenditures for 2005 are estimated to be approximately $37 million, which includes approximately $12 million for the Chicago III Expansion Project. The remaining capital expenditures for 2005 are primarily related to renewals and replacements of existing facilities. Please refer to "Management's Discussion and Analysis of Financial Condition and Results of Operations" in our annual report on Form 10-K for the year ended December 31, 2004, for more information about the Chicago III Expansion Project. We currently anticipate funding our 2005 capital expenditures primarily with borrowings under our credit agreement and using operating cash flow. 14 FINANCING ACTIVITIES Net cash used in financing activities increased $1.4 million for the six months ended June 30, 2005, compared with the same period in 2004, primarily as a result of higher distributions paid to our partners. THE IMPACT OF ENRON'S CHAPTER 11 FILING ON OUR BUSINESS In June 2005, we executed term sheets with a third party for the sale of our unsecured claims for transportation contracts and associated guarantees held against Enron and Enron North America. Proceeds from the sale are expected to be $11.1 million. In 2004, we adjusted our allowance for doubtful accounts to reflect an estimated recovery of $1.1 million for the claims. In the second quarter of 2005, we made an adjustment to our allowance for doubtful accounts of $0.6 million to reflect the agreements for the sale. As a result of the sale, we anticipate recognizing additional income of $9.4 million later in 2005. 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 Plains Natural Gas Company, LLC, our operator. 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 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 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: - the impact of uncontracted capacity on Northern Border Pipeline being greater than expected; - 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; - performance of contractual obligations by the shippers; - political and regulatory developments that impact FERC proceedings involving interstate pipelines and the interstate pipelines' success in sustaining their positions in such proceedings; - the ability to recover costs in our rates; - 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; - regulatory actions and receipt of expected regulatory clearances; - actions by rating agencies; - the ability to control operating costs; - conditions in the capital markets and the ability to access the capital markets; and - acts of nature, sabotage, terrorism or other similar acts causing damage to our facilities. 15 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. We may utilize financial instruments to manage interest rate risk to reduce our exposure to 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 neither variable-rate debt nor interest rate swaps outstanding. For additional information about our derivative instruments, please refer to Note 3 of the Notes to Financial Statements included in Item 1 of this quarterly report. ITEM 4. CONTROLS AND PROCEDURES EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES As of the end of the period covered by this report, the officers of Northern Plains Natural Gas Company, LLC that are the equivalent of our principal executive officer and principal financial 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, our operator, to CrossCountry Energy, LLC. In November 2004, ONEOK, Inc. purchased Northern Plains. Transition services agreements were entered into to provide to Northern Plains 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 through Northern Plains. 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. 16 PART II OTHER INFORMATION 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 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 Officer. +32.1 Section 1350 Certification of Chief Executive Officer. +32.2 Section 1350 Certification of Chief Financial Officer. ----------------- +Filed herewith 17 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 PIPELINE COMPANY (A Texas General Partnership) By: Northern Plains Natural Gas Company, LLC, Operator Date: August 8, 2005 By: /s/ Jerry L. Peters ------------------------------------- Jerry L. Peters Vice President, Finance and Treasurer 18 EXHIBIT INDEX

------------------ + Filed herewith. 19

NORTHERN BORDER PIPELINE CO 10-Q