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 MARCH 31, 2006
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 of (I.R.S. Employer
incorporation or organization) Identification Number)
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13710 FNB PARKWAY
OMAHA, NEBRASKA 68154-5200
(Address of principal executive offices) (Zip code)
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(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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act). (Check one):
Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.
CLASS OUTSTANDING AT MAY 1, 2006
------------- --------------------------
Common units 46,397,214 units
Class B units 36,494,126 units
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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
March 31, 2006, and 2005.............................. 4
Consolidated Statement of Comprehensive Income -
Three Months Ended March 31, 2006, and 2005........... 5
Consolidated Balance Sheet - March 31, 2006, and
December 31, 2005..................................... 6
Consolidated Statement of Cash Flows - Three Months Ended
March 31, 2006, and 2005.............................. 7
Consolidated Statement of Changes in Partners' Equity -
Three Months Ended March 31, 2006..................... 8
Notes to Consolidated Financial Statements............... 9
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Executive Summary........................................ 15
Critical Accounting Estimates............................ 17
Results of Operations.................................... 18
Liquidity and Capital Resources.......................... 22
Recent Accounting Pronouncements......................... 25
Forward-Looking Statements............................... 25
Item 3. Quantitative and Qualitative Disclosures about Market Risk.. 26
Item 4. Controls and Procedures..................................... 28
PART II - OTHER INFORMATION
Item 1. Legal Proceedings........................................... 28
Item 1A. Risk Factors................................................ 29
Item 6. Exhibits.................................................... 33
Signature................................................... 35
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The statements in this quarterly report that are not historical information,
including statements concerning plans and objectives of management for future
operations, economic performance or related assumptions, 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. Forward-looking statements
may include words such as "anticipate," "estimate," "expect," "project,"
"intend," "plan," "believe," "should" and other words and terms of similar
meaning. Although we believe that our expectations regarding future events are
based on reasonable assumptions, we can give no assurance that our goals will be
achieved. Important factors that could cause actual results to differ materially
from those in the forward-looking statements are described in this quarterly
report under Item 1A, "Risk Factors," and under Item 1A, "Risk Factors," in our
annual report on Form 10-K for the year ended December 31, 2005.
GLOSSARY
The abbreviations, acronyms, and industry terminology used in this quarterly report are defined as follows:
Bbl........................... Barrels, equivalent to 42 United States gallons
Bbl/d......................... Barrels per day
Bear Paw Energy............... Bear Paw Energy, LLC
Bighorn Gas Gathering......... Bighorn Gas Gathering, L.L.C.
Black Mesa.................... Black Mesa Pipeline, Inc.
Crestone Energy............... Crestone Energy Ventures, L.L.C.
Exchange Act.................. Securities Exchange Act of 1934, as amended
FASB.......................... Financial Accounting Standards Board
FERC.......................... Federal Energy Regulatory Commission
Fort Union Gas Gathering...... Fort Union Gas Gathering, L.L.C.
GAAP.......................... Generally accepted accounting principles
Guardian Pipeline............. Guardian Pipeline, L.L.C.
Lost Creek Gathering.......... Lost Creek Gathering Company, L.L.C.
Midwestern Gas Transmission... Midwestern Gas Transmission Company
MMBtu......................... Million British thermal units
MMcf/d........................ Million cubic feet per day
NBP Services.................. NBP Services, LLC, a ONEOK subsidiary
Northern Border Pipeline...... Northern Border Pipeline Company
Northern Plains............... Northern Plains Natural Gas Company, LLC, a
ONEOK subsidiary
Northwest Border.............. Northwest Border Pipeline Company,
a ONEOK subsidiary
NYMEX......................... New York Mercantile Exchange
NYSE.......................... New York Stock Exchange
ONEOK......................... ONEOK, Inc.
Partnership................... Northern Border Partners, L.P., Northern Border
Intermediate Limited Partnership and its
subsidiaries
SEC........................... Securities and Exchange Commission
SFAS.......................... Statement of Financial Accounting Standards
TC PipeLines.................. TC PipeLines Intermediate Limited Partnership,
a subsidiary of TC PipeLines, LP
TransCanada................... TransCanada Corporation
Trunk gathering system........ Large diameter pipeline running through a
production area to which smaller individual
gathering systems are connected
U.S........................... United States
Viking Gas Transmission....... Viking Gas Transmission Company
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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
-------------------
2006 2005
-------- --------
(In thousands
except per unit
amounts)
Operating revenue $170,799 $160,379
-------- --------
Operating expenses:
Product purchases 44,021 32,465
Operations and maintenance 31,643 33,172
Depreciation and amortization 21,294 21,392
Taxes other than income 10,178 9,812
-------- --------
Operating expenses 107,136 96,841
-------- --------
Operating income 63,663 63,538
-------- --------
Interest expense 22,704 21,166
-------- --------
Other income (expense):
Equity earnings in unconsolidated
affiliates 6,163 4,477
Other income 950 741
Other expense (162) (223)
-------- --------
Other income, net 6,951 4,995
-------- --------
Minority interest in net income 11,206 12,189
-------- --------
Income from continuing operations before
income taxes 36,704 35,178
Income taxes 2,027 899
-------- --------
Income from continuing operations 34,677 34,279
Discontinued operations, net of tax 9 390
-------- --------
Net income to partners $ 34,686 $ 34,669
======== ========
Calculation of limited partners' interest in
net income:
Net income to partners $ 34,686 $ 34,669
Less: General partners' interest in net
income 3,822 2,683
-------- --------
Limited partners' interest in net income $ 30,864 $ 31,986
======== ========
Limited partners' per unit net income:
Income from continuing operations $ 0.67 $ 0.68
Discontinued operations, net of tax -- 0.01
-------- --------
Net income $ 0.67 $ 0.69
======== ========
Number of units used in computation 46,397 46,397
======== ========
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The accompanying notes are an integral part of these consolidated financial statements
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(UNAUDITED)
THREE MONTHS
ENDED MARCH 31,
-----------------
2006 2005
------- -------
(In thousands)
Net income to partners $34,686 $34,669
Other comprehensive income:
Changes associated with current period
hedging transactions 5,000 (2,725)
Changes associated with current period
foreign currency translation (4) (21)
------- -------
Total comprehensive income $39,682 $31,923
======= =======
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The accompanying notes are an integral part of these consolidated financial statements.
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET (UNAUDITED)
MARCH 31, DECEMBER 31,
2006 2005
---------- ------------
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 18,730 $ 43,090
Accounts receivable, net of allowance for doubtful accounts of
$18 at March 31, 2006, and December 31, 2005 64,832 82,848
Materials and supplies, at cost 7,543 7,273
Prepaid expenses and other 5,168 5,211
Derivative financial instruments 2,073 --
---------- ----------
Total current assets 98,346 138,422
---------- ----------
Property, plant and equipment:
Interstate natural gas pipeline 2,677,529 2,668,645
Natural gas gathering and processing 289,188 284,199
Other 51,878 47,876
---------- ----------
Total property, plant and equipment 3,018,595 3,000,720
Less: Accumulated provision for depreciation and amortization 1,102,751 1,082,210
---------- ----------
Property, plant and equipment, net 1,915,844 1,918,510
---------- ----------
Investments and other assets:
Investment in unconsolidated affiliates 288,402 290,756
Goodwill 152,782 152,782
Regulatory assets 18,621 14,153
Other 14,363 13,143
---------- ----------
Total investments and other assets 474,168 470,834
---------- ----------
Total assets $2,488,358 $2,527,766
========== ==========
LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
Current maturities of long-term debt $ 238,000 $ 233,194
Derivative financial instruments 1,264 4,571
Accounts payable 34,326 53,706
Accrued taxes other than income 31,819 33,081
Accrued interest 21,925 17,446
---------- ----------
Total current liabilities 327,334 341,998
---------- ----------
Long-term debt, net of current maturities 1,090,905 1,121,777
---------- ----------
Minority interests in partners' equity 275,196 274,510
---------- ----------
Reserves and deferred credits:
Deferred income taxes 12,502 10,311
Derivative financial instruments 5,058 2,362
Regulatory liabilities 2,681 2,591
Other 9,317 8,628
---------- ----------
Total reserves and deferred credits 29,558 23,892
---------- ----------
Commitments and contingencies (Note 7)
Partners' equity:
General partners 18,375 17,341
Common units: 46,397,214 units issued and outstanding at
March 31, 2006, and December 31, 2005 743,947 750,201
Accumulated other comprehensive income (loss) 3,043 (1,953)
---------- ----------
Total partners' equity 765,365 765,589
---------- ----------
Total liabilities and partners' equity $2,488,358 $2,527,766
========== ==========
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The accompanying notes are an integral part of these consolidated financial statements.
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)
THREE MONTHS ENDED
MARCH 31,
--------------------
2006 2005
--------- --------
(In thousands)
CASH FLOW FROM OPERATING ACTIVITIES
Net income to partners $ 34,686 $ 34,669
--------- --------
Adjustments to reconcile net income to partners to net cash
provided by operating activities:
Depreciation and amortization 21,386 21,482
Minority interests in net income 11,206 12,189
Reserves and deferred credits 689 (340)
Equity earnings in unconsolidated affiliates (6,163) (4,477)
Distributions received from unconsolidated affiliates 9,203 1,187
Changes in components of working capital 1,626 3,726
Non-cash losses (gains) from derivative financial instruments (21) 40
Other (2,398) (1,406)
--------- --------
Total adjustments 35,528 32,401
--------- --------
Net cash provided by operating activities 70,214 67,070
--------- --------
CASH FLOW FROM INVESTING ACTIVITIES
Investment in unconsolidated affiliates (605) (1,454)
Capital expenditures for property, plant and equipment (17,806) (9,846)
--------- --------
Net cash used in investing activities (18,411) (11,300)
--------- --------
CASH FLOW FROM FINANCING ACTIVITIES
Cash distributions:
General and limited partners (39,906) (39,906)
Minority interests (13,502) (16,229)
Equity contributions from minority interests 3,099 --
Issuance of long-term debt 258,000 13,000
Debt reacquisition costs (3,628) --
Long-term debt financing costs (179) --
Retirement of long-term debt (280,047) (9,302)
--------- --------
Net cash used in financing activities (76,163) (52,437)
--------- --------
Net change in cash and cash equivalents (24,360) 3,333
Cash and cash equivalents at beginning of period 43,090 33,980
--------- --------
Cash and cash equivalents at end of period $ 18,730 $ 37,313
========= ========
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amount capitalized $ 19,475 $ 16,294
========= ========
Cash paid for income taxes $ 143 $ 151
========= ========
Changes in components of working capital:
Accounts receivable $ 18,016 $ 3,663
Materials and supplies, prepaid expenses and other (228) 877
Accounts payable (19,379) (6,492)
Accrued taxes other than income (1,262) (401)
Accrued interest 4,479 6,079
--------- --------
Total $ 1,626 $ 3,726
========= ========
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The accompanying notes are an integral part of these consolidated financial statements.
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 (LOSS) EQUITY
-------- -------- ------------- ---------
(In thousands)
Partners' equity at December 31, 2005 $17,341 $750,201 $(1,953) $765,589
Net income to partners 3,822 30,864 -- 34,686
Changes associated with current
period hedging transactions -- -- 5,000 5,000
Changes associated with current
period foreign currency translation -- -- (4) (4)
Distribution to partners (2,788) (37,118) -- (39,906)
------- -------- ------- --------
Partners' equity at March 31, 2006 $18,375 $743,947 $ 3,043 $765,365
======= ======== ======= ========
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The accompanying notes are an integral part of these consolidated financial statements.
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 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) are condensed or omitted pursuant to such rules and regulations. However, we believe that the disclosures are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our annual report on Form 10-K for the year ended December 31, 2005.
The preparation of financial statements in conformity with U.S. GAAP requires management to make assumptions and use estimates that affect the reported amount of the assets, liabilities, revenue and expenses as well as the disclosure of contingent assets and liabilities during the reporting period. Actual results could differ from these estimates if the underlying assumptions are incorrect.
At March 31, 2006, we owned a 70% general partner interest in Northern Border Pipeline Company (see Note 9-Subsequent Events). Our significant wholly owned subsidiaries are: Crestone Energy Ventures, L.L.C.; Bear Paw Energy, LLC; Midwestern Gas Transmission Company; Viking Gas Transmission Company; and Black Mesa Pipeline, Inc. We also own a 49% common membership interest in Bighorn Gas Gathering, L.L.C.; a 37% interest in Fort Union Gas Gathering, L.L.C.; a 35% interest in Lost Creek Gathering Company, L.L.C.; and a 33-1/3% interest in Guardian Pipeline, L.L.C. (see Note 9-Subsequent Events).
Certain reclassifications were made to the 2005 financial statements to conform to the current year presentation.
2. CREDIT FACILITIES AND LONG-TERM DEBT
In March 2006, we entered into a five-year $750 million amended and restated revolving credit agreement (2006 Partnership Credit Agreement) with certain financial institutions and terminated our $500 million revolving credit agreement. The weighted average interest rate on amounts outstanding under these agreements during the first quarter of 2006 was 5.40%.
On March 31, 2006, Viking Gas Transmission redeemed its four series of senior notes outstanding. In connection with the redemption, Viking Gas Transmission paid a premium of $3.6 million. The net loss from the redemption, including unamortized debt costs associated with the debt, will be amortized to interest expense over the remaining life of the Viking Gas Transmission senior notes. At March 31, 2006, the unamortized loss on reacquired debt was $3.8 million and is included in regulatory assets on the consolidated balance sheet.
3. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
We utilize financial instruments to reduce our market risk exposure to interest rate and commodity price fluctuations and achieve a more predictable cash flow. We follow established policies and procedures to assess risk and approve, monitor and report our financial instrument activities. We do not use these instruments for trading purposes.
We record in accumulated other comprehensive income amounts related to terminated interest rate swap agreements for cash flow hedges and amortize these amounts to interest expense over the term of the hedged debt. During the three months ended March 31, 2006, we amortized approximately $0.4 million related to the terminated interest rate
swap agreements as a reduction to interest expense from accumulated other comprehensive income. We expect to amortize approximately $0.2 million in each of the remaining quarters of 2006.
Our outstanding interest rate swap agreements, with notional amounts totaling $150 million, expire in March 2011. Under these agreements, we make payments to counterparties at variable rates based on the London Interbank Offered Rate and receive payments based on a 7.10% fixed rate. As of March 31, 2006, the average effective interest rate on our interest rate swap agreements was 7.62%. Our interest rate swap agreements are designated as fair value hedges as they hedge the fluctuations in the market value of the senior notes issued by us in 2001. As of March 31, 2006, the accompanying consolidated balance sheet reflects long-term derivative financial liabilities of $5.1 million with a decrease in long-term debt related to our fair value hedges.
We record in long-term debt amounts received or paid related to terminated or amended interest rate swap agreements for fair value hedges and amortize these amounts to interest expense over the remaining life of the interest rate swap agreement. During the three months ended March 31, 2006, we amortized approximately $1.3 million as a reduction to interest expense and expect to amortize approximately $0.8 million in each of the remaining quarters of 2006.
Bear Paw Energy periodically enters into commodity derivative contracts and fixed-price physical contracts. Bear Paw Energy primarily utilizes price swaps, which are designated as cash flow hedges, to hedge its exposure to natural gas and natural gas liquids price volatility. During the three months ended March 31, 2006, Bear Paw Energy recognized gains of $0.8 million from the settlement of derivative contracts. As of March 31, 2006, the consolidated balance sheet reflected an unrealized loss of approximately $1.3 million in current derivative financial instrument liabilities and an unrealized gain of approximately $2.1 million in current derivative financial instrument assets. If prices remain at current levels, Bear Paw Energy expects to reclassify approximately $0.3 million, $0.2 million and $0.3 million from accumulated other comprehensive income as an increase to operating revenue in the second, third and fourth quarters of 2006, respectively. However, this increase would be offset with decreased operating revenue due to the lower prices assumed.
4. BUSINESS SEGMENT INFORMATION
Our business is divided into two reportable segments, defined as components of the enterprise about which financial information is available and evaluated regularly by our management and the Partnership Policy Committee. Our reportable segments are strategic business units that offer different services. Each segment is managed separately because each business requires a different marketing strategy. These segments are as follows: the Interstate Natural Gas Pipeline segment, which provides interstate natural gas transportation services, and the Natural Gas Gathering and Processing segment, which provides services for the gathering, treating, processing and compression of natural gas and the fractionation of natural gas liquids.
BUSINESS SEGMENT DATA
INTERSTATE NATURAL GAS
THREE MONTHS ENDED NATURAL GAS GATHERING AND
MARCH 31, 2006 PIPELINE PROCESSING OTHER (a) TOTAL
------------------ ----------- ------------- --------- --------
(In thousands)
Revenue from external customers $95,642 $73,513 $ 1,644 $170,799
Operating income (loss) 55,325 13,991 (5,653) 63,663
EBITDA 73,193 23,876 (5,303) 91,766
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THREE MONTHS ENDED MARCH 31, 2005 ------------------ Revenue from external customers $96,645 $57,573 $ 6,161 $160,379 Operating income (loss) 55,638 9,502 (1,602) 63,538 EBITDA 72,823 17,706 143 90,672 |
(a) Includes other items not allocable to segments. In 2005, our coal slurry operation was shown as a separate reportable segment. Our coal slurry transportation contract was terminated at December 31, 2005, therefore our coal slurry business is included in Other.
TOTAL ASSETS BY SEGMENT
MARCH 31, DECEMBER 31,
2006 2005
---------- ------------
(In thousands)
Interstate natural gas pipeline $1,873,387 $1,888,980
Natural gas gathering and processing 589,143 594,379
Other (a) 25,828 44,407
---------- ----------
Total assets $2,488,358 $2,527,766
========== ==========
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(a) Includes other items not allocable to segments.
We evaluate performance based on EBITDA (earnings before interest, taxes, depreciation and amortization and allowance for equity funds used during construction (AFUDC)). Management uses EBITDA to compare the financial performance of our segments and to internally manage those business segments. Management believes that EBITDA provides useful information to investors as a measure of comparability to peer companies. EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with U.S. GAAP. EBITDA calculations may vary from company to company; therefore our computation of EBITDA may not be comparable to a similarly titled measure of another company.
RECONCILIATION OF NET INCOME (LOSS) TO EBITDA
INTERSTATE NATURAL GAS
THREE MONTHS ENDED NATURAL GAS GATHERING AND
MARCH 31, 2006 PIPELINE PROCESSING OTHER (a) TOTAL
------------------ ----------- ------------- --------- -------
(In thousands)
Net income (loss) $31,920 $19,565 $(16,799) $34,686
Minority interest 11,206 -- -- 11,206
Interest expense, net 11,249 (2) 11,457 22,704
Depreciation and amortization 16,908 4,306 172 21,386
Income tax 2,157 7 (133) 2,031
AFUDC (247) -- -- (247)
------- ------- -------- -------
EBITDA $73,193 $23,876 $ (5,303) $91,766
======= ======= ======== =======
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THREE MONTHS ENDED
MARCH 31, 2005
------------------
Net income (loss) $32,149 $13,690 $(11,170) $34,669
Minority interest 12,189 -- -- 12,189
Interest expense, net 11,204 54 9,908 21,166
Depreciation and amortization 16,569 3,958 955 21,482
Income tax 730 4 450 1,184
AFUDC (18) -- -- (18)
------- ------- -------- -------
EBITDA $72,823 $17,706 $ 143 $90,672
======= ======= ======== =======
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(a) Includes other items not allocable to segments.
5. NET INCOME PER UNIT
Net income per unit is computed by dividing net income, after deduction of the general partners' allocation, by the weighted average number of outstanding common units. The general partners' allocation is equal to an amount based upon their collective 2% general partner interest, adjusted for incentive distributions. The incentive distribution allocated to the general partners totaled $3.1 million for the first quarter of 2006, which will be paid to the general partners during the second quarter. The amount of distribution to partners shown on the accompanying consolidated statement of changes in partners' equity included incentive distributions paid to the general partners in the first quarter of 2006 of approximately $2.0 million.
On April 18, 2006, we declared a cash distribution of $0.88 per unit ($3.52 per unit on an annualized basis) for the first quarter ended March 31, 2006. The distribution is payable on May 15, 2006, to unitholders of record on April 28, 2006.
6. RATES AND REGULATORY ISSUES
As required by the provisions of the settlement of Northern Border Pipeline's last rate case, on November 1, 2005, we filed a rate case with the Federal Energy Regulatory Commission (FERC). In December 2005, the FERC issued an order that identified issues that were raised in the proceeding, accepted the proposed rates but suspended their effectiveness until May 1, 2006, at which time the new rates will be collected subject to refund until final resolution of the rate case. Information about our regulatory proceedings is included in Note 6 of the Financial Statements in our annual report on Form 10-K for the year ended December 31, 2005.
7. COMMITMENTS AND CONTINGENCIES
BLACK MESA
On December 31, 2005, we shut down our coal slurry pipeline operation. The Mohave Generating Station co-owners, Navajo Nation, Hopi Tribe, Peabody Western Coal Company and other interested parties continue to negotiate water source and coal supply issues and Black Mesa is working to resolve coal slurry transportation issues so that operations may resume in the future. If there are successful resolutions of these issues and the project receives a favorable Environmental Impact Statement, Black Mesa will reconstruct the coal slurry pipeline in late 2008 and 2009 for an anticipated in service date during 2010.
If the pipeline is reconstructed, we anticipate Black Mesa's capital expenditures for the project will be in the range of $175 million to $200 million, supported by revenue from a new transportation contract. If the Mohave Generating Station is permanently closed, we expect to incur pipeline removal and remediation costs of approximately $1 million to $2 million, net of salvage, and a non-cash impairment charge of approximately $10 million related to the remaining undepreciated cost of the pipeline assets and goodwill.
We expect to incur approximately $2 million to $4 million of operations and maintenance expense in 2006 primarily related to employee standby costs. Negotiations continue with various parties that may result in recovery of some of these standby costs. We may be required to take an impairment charge in accordance with Statement of Financial Accounting Standards (SFAS) No. 142 and SFAS No. 144 prior to final resolution of the issues concerning the Mohave Generating Station even though the project may ultimately proceed.
LEGAL PROCEEDINGS
Various legal actions that have arisen in the ordinary course of business are pending. We believe that the resolution of these issues will not have a material adverse impact on our results of operations or financial position.
ENVIRONMENTAL LIABILITIES
We are subject to federal, state and local environmental laws and regulations. Also, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies could result in substantial costs and liabilities to us.
8. ACCOUNTING PRONOUNCEMENTS
In December 2004, the Financial Accounting Standards Board issued SFAS No. 123R, "Share-Based Payment," which requires companies to expense the fair value of share-based payments and includes changes related to the expense calculation for share-based payments. Northern Plains and NBP Services adopted SFAS No. 123R as of January 1, 2006, and will charge us for our proportionate share of the expense recorded by Northern Plains and NBP Services. The impact of adopting SFAS No. 123R does not have a material impact on our results of operations or financial position.
9. SUBSEQUENT EVENTS
ONEOK TRANSACTIONS
In April 2006, under the Contribution Agreement, we acquired all of ONEOK's gathering and processing and pipelines and storage assets for approximately 36.5 million Class B units. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. The assets will be recorded at historical cost rather than at fair value since these transactions were between affiliates under common control. ONEOK now owns approximately 37.0 million of our limited partner units, which when combined with its general partner interest, increases its total interest in us to 45.7%. Under the ONEOK Purchase and Sale Agreement, we purchased all of ONEOK's natural gas liquids assets for $1.35 billion in cash. We used $1.05 billion drawn under the Bridge Facility, coupled with the proceeds from the sale of the 20% partnership interest in Northern Border Pipeline Company, to finance the transaction.
DISPOSITION OF 20% INTEREST IN NORTHERN BORDER PIPELINE
In April 2006, under the Partnership Interest Purchase and Sale Agreement dated as of December 31, 2005, we completed the sale of a 20% partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million. We and TC PipeLines each now own a 50% interest in Northern Border Pipeline, with an affiliate of TransCanada becoming operator of the pipeline effective April 1, 2007. Beginning in the second quarter, we will no longer consolidate Northern Border Pipeline, effective as of January 1, 2006. Instead, our ownership of Northern Border Pipeline will be reported as investment in unconsolidated affiliates on our balance sheet. Our share of Northern Border Pipeline's operating results will be reported as equity earnings in unconsolidated affiliates on our statement of income.
BRIDGE FACILITY
On April 6, 2006, we entered into a $1.1 billion 364-day credit agreement with a syndicate of banks and borrowed $1.05 billion to complete the ONEOK Transactions. Until May 6, 2006, we can make one additional borrowing under the Bridge Facility of up to $50 million for purposes of making payments related to the ONEOK Transactions. Additionally, we must make mandatory prepayments with the net cash proceeds of any asset disposition in excess of $10 million, or from the net cash proceeds received from any issuance of equity or of debt having a term greater than one year. Amounts outstanding under the Bridge Facility must be repaid on or before April 5, 2007. The interest rate applied to amounts outstanding under the Bridge Facility may, at our option, be the lender's base rate or an adjusted London Interbank Offered Rate plus a spread that is based upon our long-term unsecured debt ratings.
Under the Bridge Facility, we are required to comply with certain financial, operational and legal covenants. Among other things, we are required to maintain a ratio of EBITDA (net income plus minority interests in net income, interest expense, income taxes and depreciation and amortization) to interest expense of greater than 3 to 1. We are also required to maintain a ratio of indebtedness to adjusted EBITDA (EBITDA adjusted for pro forma operating results of acquisitions made during the year) of no more than 4.75 to 1. If we consummate one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will be temporarily increased to 5.25 to 1. Upon any breach of these covenants, amounts outstanding under the Bridge Facility may become immediately due and payable.
ACQUISITION OF GUARDIAN PIPELINE INTERESTS
In April 2006, we executed a Purchase and Sale Agreement and acquired 66-2/3% interest in Guardian Pipeline not owned by us for approximately $77 million. We used borrowings from our credit facility to fund our acquisition of the additional interest in Guardian Pipeline. We will begin consolidating Guardian Pipeline in the second quarter, effective January 1, 2006, instead of being reflected as investment in unconsolidated affiliates on our balance sheet and equity earnings in unconsolidated affiliates on our statement of income.
ROCKY MOUNTAIN NATURAL GAS LIQUIDS PIPELINE JOINT VENTURE
In May 2006, we entered into an agreement with a subsidiary of Williams to form a joint venture called Overland Pass Pipeline Company, LLC. The joint-venture company will build a 750-mile natural gas liquids pipeline that will transport up to 110,000 barrels per day of unprocessed natural gas liquids from Opal, Wyoming to Conway, Kansas, one of the nation's primary natural gas liquids supply and storage hubs. Additional pump facilities would increase the capacity to 150,000 barrels per day. Initially, we will own 99% of the joint venture and Williams will own the remaining 1%. Williams will have the option to increase its ownership to 50% and become operator within two years of the pipeline becoming operational. As part of a long-term agreement, Williams will dedicate its natural gas liquids production from two of its gas processing plants in Wyoming to the joint-venture company. We will provide downstream fractionation and transportation services. The natural gas liquids pipeline project is estimated to cost approximately $450 million. We plan to invest approximately $160 million to expand our existing fractionation capabilities and capacity of our natural gas liquids distribution pipelines. Financing for both projects may include a combination of short- or long-term debt or equity. Pending all necessary approvals, the target in-service date for the natural gas liquids pipeline is early 2008.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and notes to consolidated financial statements included under Item 1.
In this report, references to "we," "us," "our" or the "Partnership" collectively refer to Northern Border Partners, L.P., our subsidiary, Northern Border Intermediate Limited Partnership, and its subsidiaries.
EXECUTIVE SUMMARY
OVERVIEW
Northern Border Partners is a publicly traded Delaware limited partnership that was formed in 1993. Our common units are listed on the NYSE under the trading symbol "NBP." For the first quarter ended March 31, 2006, our operations were conducted through the following two business segments:
- Interstate Natural Gas Pipeline, which provides natural gas transportation services; and
- Natural Gas Gathering and Processing, which gathers, processes and compresses natural gas, and fractionates natural gas liquids.
RECENT DEVELOPMENTS
The following is a summary of our significant developments since December 31, 2005:
Guardian Pipeline Revenue and Cost Study - In February 2006, the FERC issued an order accepting Guardian Pipeline's revenue and cost study that requested approval of a settlement agreement to re-establish the rates initially approved by the FERC and to reduce the depreciation rate from 3.33% to 2.0%, effective January 1, 2005.
Guardian Pipeline II Project - In February 2006, Guardian Pipeline announced that it signed precedent agreements with two major Wisconsin utility companies to expand its existing natural gas pipeline system in eastern Wisconsin. The proposed project will expand and extend the existing pipeline approximately 106 miles from its current terminus near Ixonia, Wisconsin to the Green Bay area, adding approximately 537 MMcf/d of capacity. Guardian Pipeline's capital costs for the project are estimated to range between $220 million and $240 million. Pending all necessary approvals, the target in-service date is November 2008.
Midwestern Gas Transmission Eastern Extension Project - In March 2006, Midwestern Gas Transmission accepted the certificate of public convenience and necessity issued by the FERC for its Eastern Extension Project. The Eastern Extension Project will add 31 miles of natural gas pipeline with approximately 120 MMcf/d of transportation capacity. It is estimated that the project will cost approximately $28 million. Due to the delay in obtaining the FERC certificate, the Eastern Extension Project's proposed in-service date of November 2006 will likely also be delayed.
Amended and Restated Credit Agreement - In March 2006, we entered into a $750 million amended and restated revolving credit agreement and terminated our existing $500 million revolving credit agreement.
Acquisition of ONEOK Assets - In April 2006, under the Contribution Agreement, we acquired all of ONEOK's gathering and processing and pipelines and storage assets for approximately 36.5 million Class B units. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. ONEOK now owns approximately 37.0 million of our limited partner units, which when combined with its general partner interest, increases its total interest in us to 45.7%. Under the ONEOK Purchase and Sale Agreement, we purchased all of ONEOK's natural gas liquids assets for $1.35 billion in cash. We used $1.05 billion drawn under our $1.1 billion, 364-day credit agreement coupled with the proceeds from the sale of the 20% partnership interest in Northern Border Pipeline Company to finance the transaction.
Our Audit Committee, which consists solely of independent members, determined that the ONEOK transactions were fair and reasonable to us and in the interests of our unitholders. The Audit Committee engaged independent legal counsel and an independent financial adviser to assist in its determination.
Disposition of 20% Interest in Northern Border Pipeline - In April 2006, we completed the sale of a 20% partnership interest in Northern Border Pipeline to TC PipeLines under the Partnership Interest Purchase and Sale Agreement dated as of December 31, 2005, for approximately $297 million. We and TC PipeLines each now own a 50% interest in Northern Border Pipeline. As a result of the sale, Northern Border Pipeline will no longer be consolidated in our financial statements. Instead, our interest in Northern Border Pipeline will be reflected as investment in unconsolidated affiliates on our balance sheet and equity earnings in unconsolidated affiliates on our statement of income, effective January 1, 2006.
As a result of the transaction, the General Partnership Agreement for Northern Border Pipeline was amended and restated, effective April 6, 2006. The major provisions adopted or changed included the following:
- The Management Committee of Northern Border Pipeline will consist of four members. Each partner will designate two members and TC PipeLines will designate one of its members as chairman.
- The Management Committee will designate the members of the Audit Committee, which will consist of three members. One member will be selected by the partner whose affiliate is the operator and two members will be selected by the other partner.
- Northern Plains will operate Northern Border Pipeline until April 1, 2007. Effective April 1, 2007, an affiliate of TransCanada will become the operator.
Our Audit Committee determined that the disposition of the 20% interest in Northern Border Pipeline was fair and reasonable to us and in the interests of our unitholders. The Audit Committee engaged independent legal counsel and an independent financial adviser to assist in its determination.
Purchase and Sale of General Partner Interest - In April 2006, under the Purchase and Sale Agreement between ONEOK and an affiliate of TransCanada, ONEOK acquired Northwest Border, an affiliate of TransCanada that held a 0.35% general partner interest in us. As a result, ONEOK owns our entire 2% general partner interest.
Change of Directors and Officers - In April 2006, concurrent with the completion of ONEOK's purchase of Northwest Border, Paul E. Miller resigned as a member of our Partnership Policy Committee and John W. Gibson was appointed by Northwest Border to replace him. In addition, several appointments of our principal officers were announced, effective April 7, 2006, which included:
- David Kyle, chairman and chief executive officer of ONEOK, was appointed our chairman and chief executive officer;
- John W. Gibson, formerly president of ONEOK Energy Companies, was appointed our president and chief operating officer;
- James C. Kneale, executive vice president, Finance and Administration and chief financial officer of ONEOK, was appointed our chief financial officer;
- Jerry L. Peters, formerly our chief financial officer, was appointed our senior vice president, chief accounting officer and treasurer;
- John R. Barker, senior vice president and general counsel of ONEOK, was appointed our executive vice president, general counsel and secretary;
- William R. Cordes, formerly our chief executive officer, was appointed president of Northern Border Pipeline; and
- Janet K. Place, was appointed our vice president, associate general counsel and assistant secretary, and general counsel of Northern Border Pipeline.
Bridge Facility - In April 2006, we entered into a $1.1 billion 364-day credit agreement with several financial institutions to complete the ONEOK Transactions. Amounts outstanding under the agreement must be repaid on or before April 5, 2007.
Increased Cash Distribution - In April 2006, we increased our cash distribution by $0.08 per unit to $0.88 per unit for the first quarter of 2006, payable on May 15, 2006, to unitholders of record as of April 28, 2006.
Northern Border Pipeline Chicago III Expansion Project - In April 2006, the Chicago III Expansion Project went into service as planned, adding 130 MMcf/d of transportation capacity on the eastern portion of the pipeline into the Chicago area.
Acquisition of Guardian Pipeline Interests - In April 2006, we executed a Purchase and Sale Agreement and acquired 66-2/3% interest in Guardian Pipeline not owned by us for approximately $77 million. As a result of the acquisition, Guardian Pipeline will be consolidated in our financial statements and reported in our Interstate Natural Gas Pipeline segment instead of reflected as investment in unconsolidated affiliates on our balance sheet and equity earnings in unconsolidated affiliates on our statement of income.
Rocky Mountain Natural Gas Liquids Pipeline Joint Venture - In May 2006, we entered into an agreement with a subsidiary of Williams to form a joint venture called Overland Pass Pipeline Company, LLC. The joint-venture company will build a 750-mile natural gas liquids pipeline that will transport up to 110,000 barrels per day of unprocessed natural gas liquids from Opal, Wyoming to Conway, Kansas, one of the nation's primary natural gas liquids supply and storage hubs. Additional pump facilities would increase the capacity to 150,000 barrels per day. Initially, we will own 99% of the joint venture and Williams will own the remaining 1%. Williams will have the option to increase its ownership to 50% and become operator within two years of the pipeline becoming operational. As part of a long-term agreement, Williams will dedicate its natural gas liquids production from two of its gas processing plants in Wyoming to the joint-venture company. We will provide downstream fractionation and transportation services. The natural gas liquids pipeline project is estimated to cost approximately $450 million. We plan to invest approximately $160 million to expand our existing fractionation capabilities and capacity of our natural gas liquids distribution pipelines. Financing for both projects may include a combination of short- or long-term debt or equity. Pending all necessary approvals, the target in-service date for the natural gas liquids pipeline is early 2008.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions, with respect to values or conditions which cannot be known with certainty, that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates are reasonable, actual results could differ from our estimates.
There has been no change to our critical accounting estimates during the first quarter ended March 31, 2006. Information about our critical accounting estimates is included under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Estimates," in our annual report on Form 10-K for the year ended December 31, 2005.
RESULTS OF OPERATIONS
SELECTED FINANCIAL AND OPERATING RESULTS BY SEGMENT
The following table summarizes financial and operating results by segment for the three months ended March 31, 2006, and 2005:
THREE MONTHS ENDED
MARCH 31,
-------------------
2006 2005
-------- --------
(In thousands,
except operating
data)
Operating revenue:
Interstate natural gas pipeline $ 95,642 $ 96,645
Natural gas gathering and processing 73,513 57,573
Other 1,644 6,161
-------- --------
Total operating revenue 170,799 160,379
-------- --------
Operating income (loss):
Interstate natural gas pipeline 55,325 55,638
Natural gas gathering and processing 13,991 9,502
Other (5,653) (1,602)
-------- --------
Total operating income 63,663 63,538
-------- --------
Income (loss) from continuing operations:
Interstate natural gas pipeline 31,920 32,149
Natural gas gathering and processing 19,565 13,690
Other (16,808) (11,560)
-------- --------
Total income from continuing operations 34,677 34,279
-------- --------
Discontinued operations, net of tax 9 390
-------- --------
Net income $ 34,686 $ 34,669
======== ========
Operating data by segment (1):
Interstate natural gas pipeline:
MMcf delivered 305,280 306,692
MMcf/d average throughput 3,468 3,501
Natural gas gathering and processing:
MMcf/d gathered 1,095 1,049
MMcf/d processed 65 60
|
(1) Operating data includes 100% of the volumes for joint venture investments as well as for wholly owned subsidiaries.
CONSOLIDATED OPERATING RESULTS
Operating revenue increased $10.4 million, or 6%, for the first quarter of 2006 compared with the same quarter of 2005 due to higher Natural Gas Gathering and Processing segment revenue which offset the slightly lower Interstate Natural Gas Pipeline segment revenue and the loss of coal slurry pipeline revenue resulting from the shut down of Black Mesa on December 31, 2005. The coal slurry pipeline results are not reported as a discontinued operation because we believe that the coal slurry pipeline operation is likely to resume in the future. Additional information about our coal slurry pipeline operation is included in this section under "Other" and Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations-Executive Summary," in our annual report on Form 10-K for the year ended December 31, 2005.
Operating income was flat for the first quarter of 2006 compared with the same quarter last year. The increased contribution of the Natural Gas Gathering and Processing segment was offset by due diligence, legal and other expenses related to the ONEOK and TransCanada transactions described in this section under "Recent Developments."
Income from continuing operations was also flat for the first quarter of 2006 compared with the same quarter last year. Increased interest and income tax expense were offset by higher equity earnings in unconsolidated affiliates.
INTERSTATE NATURAL GAS PIPELINE SEGMENT
OVERVIEW
The Interstate Natural Gas Pipeline segment transports natural gas primarily from the Western Canada Sedimentary Basin to the Midwestern U.S. At March 31, 2006, the Interstate Natural Gas Pipeline segment consisted of the following:
- 70% general partnership interest in Northern Border Pipeline;
- Midwestern Gas Transmission;
- Viking Gas Transmission; and
- 33-1/3% interest in Guardian Pipeline.
In April 2006, we completed the sale of a 20% partnership interest in Northern Border Pipeline to TC PipeLines. We and TC PipeLines each now own a 50% interest in Northern Border Pipeline. In addition, we acquired 66-2/3% interest in Guardian Pipeline not owned by us. Additional information about these transactions is included in this section under "Recent Developments."
KNOWN TRENDS AND UNCERTAINTIES
We continue to expect that Canadian natural gas export volumes in 2006 will remain near 2005 levels despite increased production in Canada as a result of the greater number of Canadian drilling rigs in operation. We also continue to expect U.S. demand for natural gas in 2006 to be similar to 2005 levels. Residential demand for natural gas fell below normal levels during the 2005-2006 heating season as a result of warm temperatures in January and relatively normal temperatures in February. However, the Energy Information Administration projects that increased industrial demand in 2006 will offset the reduced demand of residential users.
We continue to expect that Northern Border Pipeline revenue in 2006 will be comparable with 2005 revenue, although market conditions have changed. In April and May of 2005, we did not sell all of our firm transportation capacity on Northern Border Pipeline due to decreased demand for Canadian natural gas as a result of greater supply competition in the Midwestern U.S. and increased natural gas storage injections. When storage levels approached full capacity and summer temperatures were higher than normal during the third quarter of 2005, demand for the pipeline's transportation capacity increased. Natural gas storage levels in Western Canada were higher during the first quarter of 2006 compared with the first quarter of 2005 and the five-year average for the same period as a result of relatively warm winter temperatures. Increased natural gas throughput on the TransCanada pipeline system to Eastern markets, due in part to greater demand for Canadian natural gas supply as a result of lingering supply disruptions related to Hurricanes Katrina and Rita, is expected to slow storage injection activity in Western Canada during the second quarter of 2006. In addition, Western U.S. demand for Canadian natural gas is expected to modestly decline in 2006 compared with 2005 due to the return of normal snowpack in the region that will cause gas-fired electric generation to be displaced with hydroelectric generation.
OPERATING RESULTS
The Interstate Natural Gas Pipeline segment reported income from continuing operations of $31.9 million for the first quarter ended March 31, 2006, which was relatively flat compared with $32.1 million for the same quarter of 2005. A modest decline in Northern Border Pipeline revenue was offset by increased Midwestern Gas Transmission revenue.
Operating revenue decreased slightly for the first quarter ended March 31, 2006, compared with the same quarter of 2005. Northern Border Pipeline operating revenue decreased $3.0 million for the first quarter of 2006 compared with the same quarter last year primarily as a result of discounted transportation rates, transportation capacity that was sold for shorter transportation paths and some unsold firm transportation capacity in March 2006. Midwestern Gas Transmission partially offset this decrease primarily with additional revenue generated from the Southbound Expansion, which went into service in November 2005.
Operations and maintenance expense decreased $1.6 million for the first quarter ended March 31, 2006, compared with the same quarter of 2005. Viking Gas Transmission recorded an unfavorable gas imbalance adjustment of $1.4 million during the first quarter of 2005.
Equity earnings of unconsolidated affiliates represent earnings from our one-third interest in Guardian Pipeline.
Minority interests in net income represent the 30% minority interest in Northern Border Pipeline.
NATURAL GAS GATHERING AND PROCESSING SEGMENT
OVERVIEW
The Natural Gas Gathering and Processing segment gathers natural gas from producers' wells and central delivery points in three producing basins: the Williston Basin, which spans portions of Montana, North Dakota and the Canadian province of Saskatchewan, and the Powder River and Wind River Basins of Wyoming.
Our Williston Basin facilities compress and transport raw natural gas, primarily associated with oil production, through pipelines to our processing facilities where water and other contaminants are removed and valuable natural gas liquids are extracted. We separate the natural gas liquids into marketable components utilizing a distillation process known as fractionation and sell the components to refineries or local markets. We compress the remaining residue gas, consisting primarily of methane, and deliver it to interstate natural gas pipelines.
Our Powder River Basin facilities compress and transport coalbed methane gas primarily to the Bighorn Gas Gathering and Fort Union Gas Gathering trunk gathering systems for transport and delivery to interstate natural gas pipelines.
Our Wind River Basin facilities consist of an interest in a trunk gathering system that receives natural gas from pipeline interconnections with producer-owned gathering systems and processing plants. The natural gas is processed as necessary and delivered to interstate natural gas pipelines.
At March 31, 2006, the Natural Gas Gathering and Processing segment consisted of the following subsidiaries:
- Bear Paw Energy, with operations in the Williston and Powder River Basins; and
- Crestone Energy, which owns:
- 49% interest in Bighorn Gas Gathering, with operations in the Powder River Basin;
- 37% interest in Fort Union Gas Gathering, with operations in the Powder River Basin; and
- 35% interest in Lost Creek Gathering, with operations in the Wind River Basin.
KNOWN TRENDS AND UNCERTAINTIES
Relatively strong natural gas and crude oil prices continued to drive increased production in the Williston and Power River Basins during the first quarter of 2006. In the Williston Basin, we established a record number of well connections during the first quarter of 2006 as a result of increased drilling activity. Transportation and refining capacity constraints for crude oil only moderately impacted natural gas production in the Williston Basin as expected. Further development of the Big George coals, located in the center of the Powder River Basin, resulted in increased volumes during the first quarter of 2006 compared with the same quarter last year for our joint venture interests in Bighorn Gas Gathering and Fort Union Gas Gathering.
OPERATING RESULTS
The Natural Gas Gathering and Processing segment reported income from continuing operations of $19.6 million for the first quarter ended March 31, 2006, an increase of $5.9 million, or 43%, compared with $13.7 million for the same quarter of 2005 primarily as a result of the following:
- increased gathering and processing volumes in the Williston Basin; and
- higher commodity prices realized on equity natural gas and natural gas liquids derived from percentage-of-proceeds contracts.
Operating revenue increased $15.9 million, or 28%, for the first quarter ended March 31, 2006, compared with the same quarter of 2005 due to increased revenue from our Williston Basin operations, which is derived primarily from the sale of natural gas and natural gas liquids gathered and processed under percentage-of-proceeds contracts. This increase more than offset decreased gathered volumes for our wholly owned Powder River Basin operations.
Williston Basin inlet volumes increased 4 MMcf/d, or 7%, as a result of growth projects that were completed during the second and third quarters of 2005. Optimization projects completed during the fourth quarter of 2005 resulted in improved natural gas liquids recoveries. This, in turn, resulted in higher natural gas liquids sales volume of 32.6 million gallons for the first quarter of 2006, an increase of 3.7 million gallons, or 13%, compared with 28.9 million gallons for the same quarter last year.
Volumes at our wholly owned Powder River Basin operations declined 32 MMcf/d, or 15%, for the first quarter of 2006 compared with the same quarter of 2005 due to the diversion of 45 MMcf/d of low margin gathered gas by one producer to its own system during the second quarter of 2005. However, volumes remained relatively flat for the first quarter of 2006 compared with the fourth quarter of 2005. We anticipate an increase in our wholly owned Powder River volumes during the second quarter of 2006 as a result of several system expansions that are currently underway.
Better prices were realized on our sales of natural gas and natural gas liquids retained through percentage-of-proceeds contracts, which, in addition to higher processing volumes, contributed to the segment's increased operating revenue. The weighted average price of natural gas realized, net of the effects of hedging, was $8.01 per MMBtu for the first quarter of 2006 compared with $6.65 per MMBtu for the first quarter of 2005. The weighted average price of natural gas liquids realized, net of the effects of hedging, was $1.11 per gallon for the first quarter of 2006 compared with $0.88 per gallon for the first quarter of 2005.
Product purchases, which reflect the amounts we paid to producers for raw natural gas, increased $11.6 million for the first quarter ended March 31, 2006, compared with the same quarter of 2005. Product purchases represented 60% of operating revenue for the first quarter of 2006 compared with 56% of operating revenue for the same quarter of 2005 due to declining percentage-of-proceeds contract margins as a result of increased competition.
Equity earnings of unconsolidated affiliates increased $1.4 million for the first quarter ended March 31, 2006, compared with the same quarter of 2005, primarily due to increased volumes in the Powder River Basin, which were partially offset by decreased volumes in the Wind River Basin. In addition, since August 2005, we increased our interest in Fort Union Gas Gathering to 37% compared with 33.3% during the first quarter of 2005.
OTHER
On December 31, 2005, Black Mesa's transportation contract with the coal supplier of the Mohave Generating Station expired and our coal slurry pipeline operations were shut down as expected. Under a consent decree, the Mohave Generating Station must complete significant pollution control investments to operate in the future. In addition, issues surrounding the use of an alternative water source for the coal slurry pipeline must be resolved. Black Mesa is working to resolve coal slurry transportation issues and interested parties continue to negotiate water and coal supply issues so that operations may resume in the future. If these issued are resolved and the project receives a favorable Environmental Impact Statement, portions of the pipeline would be modified or reconstructed beginning in late 2008 and 2009, supported by revenue from a new transportation contract, for an anticipated in-service date during 2010.
Black Mesa reported an operating loss of $0.1 million for the first quarter ended March 31, 2006, compared with operating income of $0.9 million for the same quarter of 2005. We expect the impact associated with the shutdown will be a reduction of net income of approximately $6 million in 2006 compared with 2005, which includes approximately $2 million to $4 million of operations and maintenance expense we expect to incur related to standby costs. Negotiations continue with various parties that may result in the recovery of some of these standby costs.
LIQUIDITY AND CAPITAL RESOURCES
OVERVIEW
Our principal sources of liquidity include cash generated from operating activities and bank credit facilities. We fund our operating expenses, debt service and cash distributions to limited and general partners primarily with operating cash flow. Capital resources for acquisitions and maintenance and growth expenditures are funded by a variety of sources, including cash generated from operating activities, borrowings under bank credit facilities, issuance of senior unsecured notes or sale of additional limited partner interests. Our ability to access capital markets for debt and equity financing under reasonable terms depends on our financial condition, credit ratings and market conditions. We believe that our ability to obtain financing at reasonable rates and our history of consistent cash flow from operating activities provide a solid foundation to meet our future liquidity and capital resource requirements.
DEBT AND CREDIT FACILITIES
The following table summarizes our and Northern Border Pipeline's debt and credit facilities outstanding as of March 31, 2006:
PAYMENTS DUE BY PERIOD
----------------------
LESS THAN LONG-TERM
TOTAL ONE YEAR PORTION
---------- --------- ----------
(In thousands)
Northern Border Pipeline:
$175 million credit agreement due 2010, $ 7,000 $ 7,000 $ --
average 5.16% (a)
6.25% senior notes due 2007 150,000 -- 150,000
7.75% senior notes due 2009 200,000 -- 200,000
7.50% senior notes due 2021 250,000 -- 250,000
Northern Border Partners:
$750 million credit agreement due 2011,
average 7.75% (a) 231,000 231,000 --
8.875% senior notes due 2010 250,000 -- 250,000
7.10% senior notes due 2011 225,000 -- 225,000
---------- -------- ----------
Total $1,313,000 $238,000 $1,075,000
========== ======== ==========
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(a) Northern Border Partners 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.
REVOLVING CREDIT AGREEMENTS
In March 2006, we entered into a $750 million amended and restated revolving credit agreement with certain financial institutions and terminated our existing $500 million revolving credit agreement. The weighted average interest rate on amounts outstanding under these agreements during the first quarter of 2006 was 5.40%. At our option, the interest rate applied to the amounts outstanding under the credit agreement may be the lender's base rate or an adjusted London Interbank Offered Rate (LIBOR) plus a spread that is based on our long-term unsecured debt ratings. We are required to pay interest on the outstanding amounts periodically. The term of the agreement is five years, at which time we are required to pay off all outstanding amounts.
We are required to comply with certain financial, operational and legal covenants, including the maintenance of an EBITDA (net income plus minority interests in net income, interest expense, income taxes and depreciation and amortization) to interest expense ratio of greater than 3 to 1 and a debt to adjusted EBITDA (EBITDA adjusted for pro forma operating results of acquisitions made during the year) ratio of no more than 4.75 to 1. If we consummate one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of debt to adjusted EBITDA will be increased to 5.25 to 1 for two calendar quarters following the acquisition. If we breach any of these covenants, amounts outstanding may become due and payable immediately.
At March 31, 2006, we had outstanding borrowings of $231 million under our $750 million revolving credit agreement and were in compliance with its covenants. On April 6, 2006, we borrowed an additional $75 million to fund working capital related to certain of the businesses acquired pursuant to the ONEOK transactions described in this section under "Recent Developments." At May 4, 2006, we had outstanding borrowings of $306 million and a $15 million letter of credit under our agreement. We may from time to time draw on the amended and restated credit agreement to meet working capital requirements, which borrowings are intended to be repaid with cash generated from operations.
As of March 31, 2006, Northern Border Pipeline had outstanding borrowings of $7.0 million under its $175 million revolving credit agreement and was in compliance with its covenants. The weighted average interest rate related to the borrowings on Northern Border Pipeline's credit agreement was 5.16% at March 31, 2006.
BRIDGE FACILITY
In April 2006, we entered into, and borrowed $1.05 billion under a $1.1 billion, 364-day credit agreement with several financial institutions to complete the transactions with ONEOK described in this section under "Recent Developments." At our option, the interest rate applied to amounts outstanding under the bridge facility may be the lender's base rate or an adjusted LIBOR plus a spread that is based on our long-term unsecured debt ratings. We must make mandatory prepayments with the net cash proceeds of any asset disposition in excess of $10 million or from the net cash proceeds received from any issuance of equity or debt having a term greater than one year. Amounts outstanding under the agreement must be repaid on or before April 5, 2007.
We are required to comply with certain financial, operational and legal
covenants, including the maintenance of an EBITDA to interest expense ratio of
greater than 3 to 1 and a debt to adjusted EBITDA ratio of no more than 4.75 to
1. If we consummate one or more acquisitions in which the aggregate purchase
price is $25 million or more, the allowable ratio of debt to adjusted EBITDA
will be increased to 5.25 to 1 for two calendar quarters following the
acquisition. If we breach any of these covenants, amounts outstanding under the
bridge facility may become immediately due and payable.
DEBT SECURITIES
In March 2006, we redeemed all of the outstanding Viking Gas Transmission Series A, B, C and D senior notes, due in 2008 through 2014, at a premium of $3.6 million.
In April 2006, we acquired the remaining interest and now own 100% of Guardian Pipeline. As of May 4, 2006, Guardian Pipeline had approximately $155 million of senior notes outstanding; interest on the notes range from 7.61% to 8.27%, with an average rate of 7.85%.
We anticipate issuing fixed-rate senior notes to repay borrowings under our $1.1 billion, 364-day credit facility prior to the April 2007 termination date of the credit agreement.
EQUITY ISSUANCES
In April 2006, we amended our Partnership Agreement to provide for the issuance of Class B units and issued 36,494,126 Class B units to ONEOK in exchange for all of its gathering and processing and pipelines and storage assets in a transaction described in this section under "Recent Developments." The new class of equity securities is entitled to the same distribution rights as our outstanding common units, but has limited voting rights and will be subordinated to the common units with respect to the minimum quarterly distribution. The number of Class B units issued was determined by using the average closing price of our common units for the 20 trading days prior to the signing of the Contribution Agreement between ONEOK and us.
We will hold a special election for holders of common units as soon as practical, but within 12 months of issuing the Class B units, to approve the conversion of the Class B units into common units and certain amendments to our Partnership Agreement. The proposed amendments grant voting rights for common units held by our general partner if a vote is held to remove our general partner and require fair market value compensation for the general partner interest if the general partner is removed.
If the common unitholders do not approve the conversion and the amendments, the Class B unit distribution rights will increase to 115% of the distribution paid on the common units. If the conversion and the amendments are approved by the common unitholders, the Class B units will convert into common units on a one-for-one basis.
CASH FLOW FROM OPERATING, INVESTING AND FINANCING ACTIVITIES
OPERATING ACTIVITIES
Cash provided by operating activities was $70.2 million for the three months ended March 31, 2006, compared with $67.1 million for the same quarter of 2005. Cash provided by operating activities increased during the first quarter of 2006 primarily as a result of the following:
- increased cash receipts from our natural gas gathering and processing operations as a result of higher operating revenue during the quarter; and
- increased distributions received from unconsolidated affiliates of $8.0 million, $5.5 million of which we received from Lost Creek Gathering to true-up our throughput volume allocation.
The increased cash provided by operating activities during the first quarter of 2006 was partially offset by the following:
- reduced cash flow of $3.2 million related to the shutdown of our coal slurry operations on December 31, 2005; and
- increased interest expense of $3.2 million primarily due to higher interest rates.
INVESTING ACTIVITIES
Cash used in investing activities was $18.4 million for the three months ended March 31, 2006, compared with $11.3 million for the same quarter last year. The increased use of cash during the first quarter of 2006 was primarily due to higher growth capital expenditures of $8.3 million by the Interstate Natural Gas Pipeline segment, $6.7 million of which was related to the Northern Border Pipeline Chicago III Expansion Project and $2.4 million of which was related to the Midwestern Gas Transmission Eastern Extension Project. Lower Interstate Natural Gas Pipeline segment maintenance expenditures and investments in unconsolidated affiliates during the first quarter of 2006 compared with the same quarter last year partially offset the Interstate Natural Gas Pipeline segment's increased growth expenditures.
During the first quarter of 2006, we also used operating cash, borrowings from our credit facility and equity contributions from our minority interest holder to fund our investing activities.
FINANCING ACTIVITIES
Cash used in financing activities was $76.2 million for the three months ended March 31, 2006, compared with $52.4 million for the same quarter of 2005.
Distributions to minority interests during the first quarter ended March 31, 2006, decreased $2.7 million compared with the same quarter of 2005 primarily due to Northern Border Pipeline's lower net income in the fourth quarter of 2005. Northern Border Pipeline received equity contributions of $3.1 million from its minority interest holder during the first quarter of 2006 for its share of the equity funding related to the Chicago III Expansion Project.
The net change in our long-term borrowings was a repayment of $22.0 million for the first quarter of 2006 compared with net borrowings of $3.7 million for the same quarter last year. We borrowed $197 million to pay the outstanding balance of our existing $500 million revolving credit agreement and terminated that agreement. We borrowed an additional $33 million under our amended and restated revolving credit agreement and redeemed all of the outstanding Viking Gas Transmission Series A, B, C and D senior notes and paid a premium of $3.6 million.
COMMITMENTS AND CONTINGENCIES
CASH DISTRIBUTIONS
We distribute 100% of our available cash, which generally consists of all cash receipts less adjustments for cash disbursements and net change to reserves, to our general and limited partners. Our income is allocated to the general partners and limited partners according to their partnership percentages of 2% and 98%, respectively, after the effect of any incremental income allocations for incentive distributions to the general partners.
In April 2006, we increased our cash distribution by $0.08 per unit to $0.88 per unit for the first quarter of 2006, payable on May 15, 2006, to unitholders of record as of April 28, 2006.
LEGAL
Various legal actions that have arisen in the ordinary course of business are pending. We believe that the resolution of these issues will not have a material adverse impact on our results of operations or financial position.
ENVIRONMENTAL
Our operations are subject to extensive federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to the protection of the environment. Failure to comply with these laws and regulations can result in substantial penalties, enforcement actions and remedial liabilities. We believe that the resolution of various environmental issues that have arisen in the ordinary course of business will not materially impact our results of operations.
RECENT ACCOUNTING PRONOUNCEMENTS
In December 2004, the FASB issued SFAS No. 123R, "Share-Based Payments," which requires companies to expense the fair value of share-based payments and includes changes related to the expense calculation for share-based payments. Northern Plains and NBP Services adopted SFAS No. 123R as of January 1, 2006, and will charge us for our proportionate share of the expense recorded by Northern Plains and NBP Services. The impact of adopting SFAS No. 123R does not have a material impact on our results of operations or financial position.
FORWARD-LOOKING STATEMENTS
The statements in this quarterly report that are not historical information,
including statements concerning plans and objectives of management for future
operations, economic performance or related assumptions, are forward-looking
statements within the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Exchange Act. Forward-looking statements may include words
such as "anticipate," "estimate," "expect," "project," "intend," "plan,"
"believe," "should" and other words and terms of similar meaning. Although we
believe that our expectations regarding future events are based on reasonable
assumptions, we can give no assurance that our goals will be achieved. Important
factors that could cause actual results to differ materially from those in the
forward-looking statements include:
- the effects of weather and other natural phenomena on our operations, demand for our services and energy prices;
- competition from other U.S. and Canadian energy suppliers and transporters as well as alternative forms of energy;
- the timing and extent of changes in commodity prices for natural gas, natural gas liquids, electricity and crude oil;
- impact on drilling and production by factors beyond our control, including the demand for natural gas and refinery-grade crude oil; producers' desire and ability to obtain necessary permits; reserve performance; and capacity constraints on the pipelines that transport natural gas, crude oil and natural gas liquids from producing areas and our facilities;
- risks of trading and hedging activities as a result of changes in energy prices or the financial condition of our counterparties;
- the ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our FERC-regulated rates;
- the timely receipt of approval by the FERC for construction and operation of our interstate natural gas pipeline projects and required regulatory clearances; our ability to acquire all necessary rights-of-way and obtain agreements for interconnects in a timely manner, and our ability to promptly obtain all necessary materials and supplies required for construction;
- the impact of unsold and discounted capacity on Northern Border Pipeline being greater than expected;
- the ability to market pipeline capacity on favorable terms;
- orders by the FERC related to Northern Border Pipeline's November 2005 rate case which are significantly different than our assumptions;
- risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines which outpace new drilling;
- impact of a potential impairment charge if we are unable to renew our coal slurry pipeline contract;
- the effects of changes in governmental policies and regulatory actions, including changes with respect to income taxes, environmental compliance, authorized rates or recovery of gas costs;
- the results of administrative proceedings and litigation, regulatory actions and receipt of expected clearances involving regulatory authorities or any other local, state or federal regulatory body, including the FERC;
- actions by rating agencies concerning our credit ratings;
- the impact of unforeseen changes in interest rates, equity markets, inflation rates, economic recession and other external factors over which we have no control, including the effect on pension expense and funding resulting from changes in stock and bond market returns;
- our ability to access capital at competitive rates or on terms acceptable to us;
- demand for our services in the proximity of our facilities;
- the profitability of assets or businesses acquired by us;
- the risk that material weaknesses or significant deficiencies in our internal control over financial reporting could emerge or that minor problems could become significant;
- the impact and outcome of pending and future litigation;
- our ability to successfully integrate the operations of the assets acquired from ONEOK with our current operations;
- performance of contractual obligations by our customers;
- ability to control operating costs; and
- acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers' or shippers' facilities.
These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also have material adverse effects on our future results. These and other risks are described in greater detail in this quarterly report under Item 1A, "Risk Factors," and under Item 1A, "Risk Factors," in our annual report on Form 10-K for the year ended December 31, 2005. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
OVERVIEW
Our exposure to market risk discussed below includes forward-looking statements and represents an estimate of possible changes in future earnings that would occur assuming hypothetical future movements in interest rates or commodity prices. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur since actual gains and losses will differ from those estimated based on actual fluctuations in interest rates or commodity prices and the timing of transactions.
We are exposed to market risk due to interest rate and commodity price volatility. Market risk is the risk of loss arising from adverse changes in market rates and prices. We utilize financial instruments, including forwards, swaps, collars and futures, to manage the risks of certain identifiable or anticipated transactions and achieve a more predictable cash flow. Our risk management function follows established policies and procedures to monitor interest rates and natural gas and natural gas liquids marketing activities to ensure our hedging activities mitigate market risks. We do not use financial instruments for trading purposes.
INTEREST RATE RISK
We utilize both fixed- and variable-rate debt and are exposed to market risk due to the floating interest rates on our credit facilities. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk. As of March 31, 2006, we and Northern Border Pipeline had $388 million of variable-rate debt outstanding, $150 million of which we converted from fixed-rate to variable-rate debt through interest rate swap agreements. Primarily as a result of the transactions described in this section under "Recent Developments," our variable-rate debt outstanding increased to $1,506 million as of May 1, 2006, $150 million of which we converted from fixed-rate to variable-rate debt through interest rate swap agreements.
If interest rates increased 1% on our borrowings outstanding as of May 1, 2006, our annual consolidated interest expense would increase and our projected consolidated income before income taxes would decrease by approximately $15 million.
COMMODITY PRICE RISK
Our Interstate Natural Gas Pipeline segment and the recently acquired pipelines and storage assets are exposed to commodity price risk because our interstate and intrastate pipelines collect natural gas from their customers as part of their fee for services provided. When the amount of natural gas utilized in operations by these pipelines differs from the amount provided by their customers, the pipelines must buy or sell natural gas, or use natural gas from inventory, and are exposed to commodity price risk. We have not entered into any hedges with respect to our interstate and intrastate pipeline operations.
Our recently acquired natural gas liquids assets are exposed to commodity price risk primarily as a result of natural gas liquids in storage, spread risk associated with the relative values of the various components of the natural gas liquids stream and the relative value of natural gas liquids purchases at one location and sale at another location, known as basis risk. We have not entered into any hedges with respect to our natural gas liquids marketing activities.
Our Natural Gas Gathering and Processing segment receives a significant portion of its revenue from the sale of commodities in exchange for gathering and processing services and is exposed to market risk due to changes in natural gas and natural gas liquids prices. To minimize earnings volatility related to natural gas and natural gas liquids price fluctuations, we may enter into commodity financial instruments, including NYMEX contracts, fixed price swaps and collars, which are all designated as cash flow hedges.
As of March 31, 2006, we hedged a portion of our projected natural gas and natural gas liquids volumes for the remainder of 2006 as follows:
NINE MONTHS ENDED WEIGHTED
DECEMBER 31, 2006 AVERAGE HEDGE
HEDGED COMMODITY INSTRUMENT HEDGED VOLUME PRICE PER UNIT
---------------- ---------------- ----------------- ---------------
Natural Gas (in MMBtu/d) Collar 5,236 $6.15 - $11.00
Natural Gas (in MMBtu/d) Fixed Price Swap 7,000 $7.87
Natural Gas Liquids (in Bbl/d) Collar 818 $52.08 - $60.06
Natural Gas Liquids (in Bbl/d) Fixed Price Swap 1,354 $43.81
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Our commodity price market risk, excluding the effects of hedging, is estimated as a hypothetical decrease in the price of natural gas and natural gas liquids at March 31, 2006. We estimate that a $1.00 per MMBtu decrease in the weighted average price of natural gas would increase annual net income by approximately $11 million. We estimate that a $0.10 per gallon decrease in the weighted average price of natural gas liquids would decrease annual net income by approximately $30 million.
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 officer evaluated the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Based on their evaluation, they concluded that as of March 31, 2006, our disclosure controls and procedures were effective in ensuring that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There were no changes in our internal control over financial reporting that occurred during the first quarter ended March 31, 2006, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
In May 2006, Northern Border Pipeline is implementing system modifications to meet new transaction billing requirements in conjunction with its rate case. This activity will cause changes to Northern Border Pipeline's internal control over financial reporting during the second quarter of 2006.
During the fourth quarter of 2005, we began implementing a new contracting and billing system to support the Natural Gas Gathering and Processing segment. The new system will automate certain transactional processes, including scheduling, plant allocations and invoicing, that are currently handled manually. Implementation is scheduled to take place during the third quarter of 2006, at which time we will have changes to our internal control over financial reporting.
In April 2006, we entered into a services agreement with ONEOK and also acquired all of ONEOK's gas gathering and processing, natural gas liquids and pipeline and storage assets. In addition, ONEOK now owns 100% of our general partnership interest. As a result of these activities and the integration of the operations of the ONEOK acquired assets with our existing operations, there could be changes to our internal control over financial reporting.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
WILL PRICE, ET AL. V. GAS PIPELINES, ET AL. (F/K/A QUINQUE OPERATING COMPANY, ET AL. V. GAS PIPELINES, ET AL.), 26TH JUDICIAL DISTRICT, DISTRICT COURT OF STEVENS COUNTY, KANSAS, CIVIL DEPARTMENT, CASE NO. 99C30 (PRICE I).
Plaintiffs brought suit on May 28, 1999, against MidContinent Market Center, Inc., ONEOK Field Services Company, ONEOK WesTex Transmission, L.P., and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP), all of which were recently acquired by us, as well as approximately 225 other defendants. Plaintiffs sought class certification for their claims that the defendants had underpaid gas producers and royalty owners throughout the United States by intentionally understating both the volume and the heating content of purchased gas. After extensive briefing and a hearing, the court refused to certify the class sought by the plaintiffs. Plaintiffs then filed an amended petition limiting the purported class to gas producers and royalty owners in Kansas, Colorado and Wyoming and limiting the claim to under measurement of volumes. Oral argument on the plaintiffs' motion to certify this suit as a class action was conducted on April 1, 2005. The court has not yet ruled on the class certification issue.
WILL PRICE AND STIXON PETROLEUM, ET AL. V. GAS PIPELINES, ET AL., 26TH JUDICIAL DISTRICT, DISTRICT COURT OF STEVENS COUNTY, KANSAS, CIVIL DEPARTMENT, CASE NO. 03C232 (PRICE II).
This action was filed by the plaintiffs on May 12, 2003, after the court had denied class status in Price I. Plaintiffs claim that 21 groups of defendants, including MidContinent Market Center, Inc., ONEOK Field Services Company, ONEOK WesTex Transmission, L.P., and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP), all of which were recently acquired by us, intentionally underpaid gas producers and royalty owners by understating the heating content of purchased gas in Kansas, Colorado and Wyoming. Price II has been consolidated with Price I for the determination of whether either or both cases may properly be certified as class actions. Oral argument on the plaintiffs' motion to certify this suit as a class action was conducted on April 1, 2005. The court has not yet ruled on the class certification issue.
PRAXAIR, INC. V. ONEOK FIELD SERVICES COMPANY, ET AL., DISTRICT COURT OF ELLSWORTH COUNTY, KANSAS, CASE NO. 04-C-17.
Plaintiff is alleging that ONEOK Field Services Company and ONEOK Bushton Processing, Inc. wrongfully declared force majeure under its agreement with Plaintiff for delivery of helium. Plaintiff's initial petition filed in March 2004 claimed damages for breach of contract and breach of good faith and fair dealing in excess of $20 million. Discovery phase of the proceeding is still underway. In late March 2006, the plaintiff increased its damage claim to $41.5 million. Trial is scheduled to begin October 10, 2006.
ITEM 1A. RISK FACTORS
The following new or modified risk factors, most of which relate to the assets and businesses acquired from ONEOK, should be read in conjunction with the risk factors disclosed in our annual report on Form 10-K for the year ended December 31, 2005:
RISKS INHERENT IN OUR BUSINESS
THE VOLATILITY OF NATURAL GAS AND NATURAL GAS LIQUIDS PRICES COULD ADVERSELY AFFECT OUR CASH FLOW.
A significant portion of our natural gas gathering and processing revenue is derived from the sale of commodities we retain for our gathering and processing services. Additionally, certain of our gas gathering and processing assets recently acquired in Oklahoma and Kansas have "keep whole" processing contracts, under which we extract natural gas liquids and return to the producer volumes of merchantable natural gas containing the same amount of Btus that were removed as natural gas liquids. This type of contract exposes us to the keep whole spread, or gross processing spread, which is the relative difference in the prices of natural gas liquids and natural gas on a Btu basis. As a result, we are sensitive to natural gas and natural gas liquids price fluctuations. Natural gas and natural gas liquids prices have been and are likely to continue to be volatile in the future. The recent record high natural gas and natural gas liquids prices may not continue and could drop precipitously in a short period of time. The prices of natural gas and natural gas liquids are subject to wide fluctuations in response to a variety of factors beyond our control, including the following:
- relatively minor changes in the supply of, and demand for, domestic and foreign natural gas and natural gas liquids;
- market uncertainty;
- availability and cost of transportation capacity;
- the level of consumer product demand;
- political conditions in international natural gas-producing regions;
- weather conditions;
- domestic and foreign governmental regulations and taxes;
- the price and availability of alternative fuels;
- speculation in the commodity futures markets;
- overall domestic and global economic conditions;
- the price of natural gas and natural gas liquids imports; and
- the effect of worldwide energy conservation measures.
These external factors and the volatile nature of the energy markets make it difficult to reliably estimate future prices of natural gas and natural gas liquids. As natural gas and natural gas liquids prices decline, we are paid less for our commodities, thereby reducing our cash flow. In addition, production and related volumes could also decline.
WE DO NOT FULLY HEDGE AGAINST PRICE CHANGES IN COMMODITIES. THIS COULD RESULT IN DECREASED REVENUES AND INCREASED COSTS, THEREBY RESULTING IN LOWER MARGINS AND ADVERSELY AFFECTING OUR RESULTS OF OPERATIONS.
Our businesses are exposed to market risk and the impact of market fluctuations in natural gas, natural gas liquids, crude oil and power prices. Market risk refers to the risk of loss in cash flows and future earnings arising from adverse changes in commodity energy prices. Our primary exposure arises from natural gas liquids in storage utilized by our natural gas liquids operations and the difference between natural gas and natural gas liquids prices with respect to our keep whole processing agreements. To minimize the risk from market fluctuations in natural gas, natural gas liquids and crude oil prices, we use commodity derivative instruments such as futures contracts, swaps and options to manage the market risk of existing or anticipated purchases and sales of natural gas, natural gas liquids and crude oil. However, we do not fully hedge against commodity price changes and we therefore retain some exposure to market risk. We adhere to policies and procedures that limit our exposure to market risk from open positions and that monitor our market risk exposure.
IF THE LEVEL OF DRILLING AND PRODUCTION IN OKLAHOMA, KANSAS, THE PANHANDLE OF TEXAS AND THE WILLISTON, POWDER RIVER AND WIND RIVER BASINS SUBSTANTIALLY DECLINES, OUR GATHERING AND PROCESSING VOLUMES AND REVENUE COULD DECLINE.
Our ability to maintain or expand our natural gas gathering and processing business depends largely on the level of drilling and production in the areas where our gathering and processing facilities are located, which include Oklahoma, Kansas, the panhandle of Texas and the Williston, Powder River and Wind River Basins. Drilling and production are impacted by factors beyond our control, including:
- demand for natural gas and refinery-grade crude oil;
- producers' desire and ability to obtain necessary permits in a timely and economic manner;
- natural gas field characteristics and production performance;
- surface access and infrastructure issues; and
- capacity constraints on natural gas, crude oil and natural gas liquids pipelines that transport gas from the producing areas and our facilities.
In addition, drilling and production in the Powder River Basin are impacted by environmental regulations governing water discharge associated with coalbed methane production. If the level of drilling and production in these areas substantially declines, our gathering and processing volumes and revenue could be reduced.
PIPELINE INTEGRITY PROGRAMS AND REPAIRS MAY IMPOSE SIGNIFICANT COSTS AND LIABILITIES.
In December 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs for our interstate natural gas and natural gas liquids pipelines located near "high consequence areas," where a leak or rupture could do the most harm. The final rule requires operators to perform ongoing assessments of pipeline integrity; identify and characterize applicable threats to pipeline segments that could impact a high consequence area; improve data collection, integration and analysis; repair and remediate the pipeline as necessary; and implement preventive and mitigating actions. The final rule incorporates the requirements of the Pipeline Safety Improvement Act of 2002 and became effective in January 2004. The results of these testing programs could cause us to incur significant capital and operating expenditures in response to repair, remediation, preventative or mitigating actions that are determined to be necessary.
A DOWNGRADE OF OUR CREDIT RATING MAY REQUIRE US TO OFFER TO REPURCHASE OUR SENIOR NOTES OR IMPAIR OUR ABILITY TO ACCESS CAPITAL.
We could be required to offer to repurchase certain of our senior notes at par value, plus any associated penalties and premiums, if Moody's Investor Services or Standard & Poor's Rating Services rate our senior notes below investment grade. We may not have sufficient cash on hand to repurchase the senior notes at par value, which may cause us to borrow money under our credit facilities or seek alternative financing sources to finance the repurchase. We could also face difficulties accessing capital or our borrowing costs could increase, impacting our ability to obtain financing for acquisitions or capital expenditures and to refinance indebtedness, including refinancing the amount outstanding under our 364-day credit agreement used to purchase the assets from ONEOK.
WE MAY NOT BE ABLE TO SUCCESSFULLY INTEGRATE THE OPERATIONS OF THE ONEOK SUBSIDIARIES THAT WE ACQUIRED WITH OUR CURRENT OPERATIONS.
The integration of the operations of the ONEOK subsidiaries that we recently acquired with our current operations will be a complex, time-consuming and costly process. Failure to timely and successfully integrate the operations of the ONEOK subsidiaries may have a material adverse effect on our business, financial condition and results of operations. Integrating the ONEOK operations will present challenges to our management, including:
- operating a significantly larger combined company with operations in new geographic areas;
- managing relationships with new customers for whom we have not previously provided services;
- integrating personnel with diverse backgrounds and organizational cultures;
- experiencing operational interruptions or the loss of key employees, customers or suppliers;
- inefficiencies and complexities that may arise due to unfamiliarity with the new operations and the businesses associated with them, including with their markets;
- assimilating the operations, technologies, services and products of the acquired operations;
- incurring additional costs related to reorganization, severance, and relocation of employees;
- assessing the internal controls and procedures for the combined entity that we are required to maintain under the Sarbanes-Oxley Act of 2002; and
- consolidating other corporate and administrative functions.
We will also be exposed to risks that are commonly associated with transactions similar to this acquisition, such as unanticipated liabilities and costs, some of which may be material, and diversion of management's attention. As a result, the anticipated benefits of the acquisition may not be fully realized, if at all.
THE ISSUANCE OF CLASS B UNITS TO ONEOK IN CONNECTION WITH THE ACQUISITION OF CERTAIN OF ITS SUBSIDIARIES WILL DILUTE OUR CURRENT UNITHOLDERS' OWNERSHIP INTERESTS UPON THE CONVERSION OF THE CLASS B UNITS TO COMMON UNITS.
In connection with the acquisition of certain ONEOK subsidiaries, we issued approximately 36.5 million Class B units representing limited partner interests in us to ONEOK. The Class B units will convert to common units on a one-for-one basis at the holder's option upon the requisite approval of such conversion by our unitholders at a special meeting of unitholders, or automatically upon the requisite approval of both the conversion and certain amendments to our partnership agreement by our unitholders at a special meeting of unitholders. The conversion of the Class B units will have the following effects:
- our unitholders' proportionate ownership interest in us will decrease;
- the distributions on each common unit may decrease;
- the relative voting strength of each previously outstanding common unit may be diminished; and
- the market price of the common units may decline.
In addition, ONEOK may, from time to time, sell all or a portion of its common units. Sales of substantial amounts of their common units, or the anticipation of such sales, could lower the market price of our common units and may make it more difficult for us to sell our equity securities in the future at a time and price that we deem appropriate.
RISKS INHERENT IN AN INVESTMENT IN US
WE DO NOT OPERATE ALL OF OUR ASSETS NOR DO WE DIRECTLY EMPLOY ANY OF THE PERSONS RESPONSIBLE FOR PROVIDING US WITH ADMINISTRATIVE, OPERATING AND MANAGEMENT SERVICES. THIS RELIANCE ON OTHERS TO OPERATE OUR ASSETS AND TO PROVIDE OTHER SERVICES COULD ADVERSELY AFFECT OUR BUSINESS AND OPERATING RESULTS.
We rely on ONEOK, Northern Plains and NBP Services to provide us with administrative, operating and management services. We have a limited ability to control our operations or the associated costs of such operations. The success of these operations depends on a number of factors that are outside our control, including the competence and financial resources of the provider. ONEOK, Northern Plains and NBP Services may outsource some or all of these services to third parties, and a failure to perform by these third-party providers could lead to delays in or interruptions of these services. Should ONEOK, Northern Plains or NBP Services not perform their respective contractual obligations, we may have to contract elsewhere for these services, which may cost more than we are currently paying. In addition, we may not be able to obtain the same level or kind of service or retain or receive the services in a timely manner, which may impact our ability to perform under our transportation contracts and negatively affect our business and operating results. Our reliance on ONEOK, Northern Plains, NBP Services and the third-party providers with which they contract, together with our limited ability to control certain costs, could harm our business and results of operations.
THE PARTNERSHIP POLICY COMMITTEE, OUR GENERAL PARTNERS AND THEIR AFFILIATES HAVE CONFLICTS OF INTEREST AND LIMITED FIDUCIARY DUTIES, WHICH MAY PERMIT THEM TO FAVOR THEIR OWN INTERESTS.
ONEOK owns 100% of our general partner interests and a 43.7% limited partner interest in us. Although ONEOK, through the Partnership Policy Committee, has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the board of directors of ONEOK has a fiduciary duty to manage our general partners in a manner beneficial to ONEOK. Some members of our Partnership Policy Committee are also members of ONEOK's board of directors. Conflicts of interest may arise between our general partners and their affiliates and us and our unitholders. In resolving these conflicts, our general partners may favor their own interests and the interests of their respective affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:
- the Partnership Policy Committee and our general partners, which are owned by ONEOK, are allowed to take into account the interests of parties other than us in resolving conflicts of interest, which has the effect of limiting their fiduciary duty to our unitholders;
- the respective affiliates of our general partners may engage in competition with us;
- our partnership agreement limits the liability and reduces the fiduciary duties of the members of the Partnership Policy Committee and of our general partners and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;
- the Partnership Policy Committee determines the amount and timing of our cash reserves, asset purchases and sales, capital expenditures, borrowings and issuances of additional partnership securities, each of which can affect the amount of cash that is distributed to our unitholders;
- the Partnership Policy Committee approves the amount and timing of any capital expenditures and determines whether they are maintenance capital expenditures or growth capital expenditures, which can affect the amount of cash that is distributed to our unitholders;
- the Partnership Policy Committee may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions;
- the Partnership Policy Committee determines which costs incurred by them, our general partners and their respective affiliates are reimbursable by us;
- our partnership agreement does not restrict the members of the Partnership Policy Committee from causing us to pay them, our general partners or their respective affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
- our general partners may exercise their limited right to call and purchase common units if they and their respective affiliates own more than 80% of the common units; and
- the Partnership Policy Committee decides whether to retain separate counsel, accountants or others to perform services for us.
OUR GENERAL PARTNERS AND THEIR AFFILIATES MAY COMPETE DIRECTLY WITH US AND HAVE NO OBLIGATION TO PRESENT BUSINESS OPPORTUNITIES TO US.
ONEOK and their affiliates are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. ONEOK may acquire, construct or dispose of additional midstream or other assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets. In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to ONEOK and its affiliates. As a result, neither ONEOK nor any of its affiliates has any obligation to present business opportunities to us.
ITEM 6. EXHIBITS
The following exhibits are filed as part of this quarterly report on Form 10-Q:
#2.1 Contribution Agreement by and among ONEOK, Inc., Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership dated February 14, 2006 (incorporated by reference to Exhibit 2.1 to Northern Border Partners, L.P.'s Form 10-K filed on March 7, 2006 (File No. 1-12202)).
#2.2 First Amendment to Contribution Agreement by and among ONEOK, Inc., Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership dated April 6, 2006 (incorporated by reference to Exhibit 2.2 to Northern Border Partners, L.P.'s Form 8-K filed on April 12, 2006 (File No. 1-12202)).
#2.3 Purchase and Sale Agreement by and between ONEOK, Inc. and Northern Border Partners, L.P. dated February 14, 2006 (incorporated by reference to Exhibit 2.2 to Northern Border Partners, L.P.'s Form 10-K filed on March 7, 2006 (File No. 1-12202)).
#2.4 First Amendment to Purchase and Sale Agreement by and between ONEOK, Inc. and Northern Border Partners, L.P. dated April 6, 2006 (incorporated by reference to Exhibit 2.4 to Northern Border Partners, L.P.'s Form 8-K filed on April 12, 2006 (File No. 1-12202)).
#2.5 Partnership Interest Purchase and Sale Agreement by and between Northern Border Intermediate Limited Partnership and TC Pipeline Intermediate Limited Partnership dated as of December 31, 2005 (incorporated by reference to Exhibit 2.3 to Northern Border Partners, L.P.'s Form 10-K filed on March 7, 2006 (File No. 1-12202)).
#2.6 Purchase and Sale Agreement by and among Wisconsin Energy Corporation and WPS Investments, LLC and Northern Border Intermediate Limited Partnership dated as of March 30, 2006 (incorporated by reference to Exhibit 2.1 to Northern Border Partners, L.P. Form 8-K filed March 30, 2006 (File No. 1-2202)).
3.1 Amended and Restated Agreement of Limited Partnership of Northern Border Partners, L.P. dated October 1, 1993 (incorporated by reference to Exhibit 3.2 to Northern Border Partners, L.P.'s Form 10-K for the year ended December 31, 2004 (File No. 1-12202)).
3.2 Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Northern Border Partners, L.P. dated April 6, 2006.
4.1 Form of Class B unit certificate (incorporated by reference to Exhibit 4.1 to Northern Border Partners, L.P.'s Form 8-K filed on April 12, 2006 (File No. 1-12202)).
10.1 364-Day Credit Agreement dated April 6, 2006, by and among Northern Border Partners, L.P., the several banks and other financial institutions and lenders from time to time party hereto, SunTrust Bank, as Administrative Agent, Citicorp North America, Inc., as Syndication Agent and Bank of Montreal (doing business as Harris Nesbitt), UBS Loan Finance LLC, and Wachovia Bank, National Association, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Northern Border Partners, L.P.'s Form 8-K filed on April 12, 2006 (File No. 1-12202)).
10.2 First Amended and Restated General Partnership Agreement of Northern Border Pipeline Company dated April 6, 2006 by and between Northern Border Intermediate Limited Partnership and TC Pipelines Intermediate Limited Partnership (incorporated by reference to Exhibit 3.1 to Northern Border Pipeline Company's Form 8-K filed April 12, 2006 (File No. 333-87753)).
10.3 Services Agreement dated April 6, 2006, by and among ONEOK, Inc., Northern Plains Natural Gas Company, LLC, NBP Services, LLC, Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership (incorporated by reference to Exhibit 10.3 to Northern Border Partners, L.P.'s Form 8-K filed on April 12, 2006 (File No. 1-12202)).
10.4 Consent and Amendment to Operating Agreement dated April 6, 2006, by and between Northern Border Pipeline Company and Northern Plains Natural Gas Company, LLC (incorporated by reference to Exhibit 10.2 to Northern Border Pipeline Company's Form 8-K filed April 12, 2006 (File No. 333-87753)).
10.5 Operating Agreement dated April 6, 2006, by and between Northern Border Pipeline Company and TransCan Northwest Border Ltd. (incorporated by reference to Exhibit 10.3 to Northern Border Pipeline Company's Form 8-K filed April 12, 2006 (File No. 333-87753)).
10.6 Amended and Restated Revolving Credit Agreement dated March 30, 2006, among Northern Border Partners, L.P., the lenders from time to time party thereto; SunTrust Bank, as administrative agent; Wachovia Bank, National Association, as Syndication Agent; Harris Nesbit Financing, Inc., Barclays Bank PLC and Citibank, N.A., as Co-Documentation Agents. (incorporated by reference to Exhibit 10.1 to Northern Border Partners, L.P. Form 8-K filed March 31, 2006 (File No. 1-2202)).
10.7 The First Amendment to Revolving Credit Agreement dated March 29, 2006, among Northern Border Pipeline Company, the lenders from time to time party thereto; Wachovia Bank, National Association, as Administrative Agent; SunTrust Bank, as syndication agent; and Harris Nesbit Financing, Inc., Barclays Bank PLC, and Citibank, N.A., as co-documentation agents (incorporated by reference to Exhibit 10.1 to Northern Border Pipeline Company's Form 8-K filed April 4, 2006 (File No. 333-87753)).
+31.1 Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
+31.2 Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
+32.1 Section 1350 Certification of Chief Executive Officer.
+32.2 Section 1350 Certification of Chief Financial Officer.
The total amount of securities of the Partnership authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the Partnership and its subsidiaries on a consolidated basis. The Partnership agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to the Securities and Exchange Commission.
# Northern Border Partners agrees to furnish supplementally to the SEC, upon request, any schedules and exhibits to this agreement, as set forth in the Table of Contents of the agreement, that have not been filed herewith pursuant to Item 601(b)(2) of Regulation S-K.
+ Filed herewith
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: May 4, 2006 By: /s/ Jim Kneale
------------------------------------
Jim Kneale
Chief Financial Officer
(Signing on behalf of the Registrant
and as Chief Financial Officer)
|
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION OF EXHIBIT
----------- ----------------------
#2.1 Contribution Agreement by and among ONEOK, Inc., Northern Border
Partners, L.P. and Northern Border Intermediate Limited
Partnership dated February 14, 2006 (incorporated by reference to
Exhibit 2.1 to Northern Border Partners, L.P.'s Form 10-K filed on
March 7, 2006 (File No. 1-12202)).
#2.2 First Amendment to Contribution Agreement by and among ONEOK,
Inc., Northern Border Partners, L.P. and Northern Border
Intermediate Limited Partnership dated April 6, 2006 (incorporated
by reference to Exhibit 2.2 to Northern Border Partners, L.P.'s
Form 8-K filed on April 12, 2006 (File No. 1-12202)).
#2.3 Purchase and Sale Agreement by and between ONEOK, Inc. and
Northern Border Partners, L.P. dated February 14, 2006
(incorporated by reference to Exhibit 2.2 to Northern Border
Partners, L.P.'s Form 10-K filed on March 7, 2006 (File No.
1-12202)).
#2.4 First Amendment to Purchase and Sale Agreement by and between
ONEOK, Inc. and Northern Border Partners, L.P. dated April 6, 2006
(incorporated by reference to Exhibit 2.4 to Northern Border
Partners, L.P.'s Form 8-K filed on April 12, 2006 (File No.
1-12202)).
#2.5 Partnership Interest Purchase and Sale Agreement by and between
Northern Border Intermediate Limited Partnership and TC Pipeline
Intermediate Limited Partnership dated as of December 31, 2005
(incorporated by reference to Exhibit 2.3 to Northern Border
Partners, L.P.'s Form 10-K filed on March 7, 2006 (File No.
1-12202)).
#2.6 Purchase and Sale Agreement by and among Wisconsin Energy
Corporation and WPS Investments, LLC and Northern Border
Intermediate Limited Partnership dated as of March 30, 2006
(incorporated by reference to Exhibit 2.1 to Northern Border
Partners, L.P. Form 8-K filed March 30, 2006 (File No. 1-2202)).
3.1 Amended and Restated Agreement of Limited Partnership of Northern
Border Partners, L.P. dated October 1, 1993 (incorporated by
reference to Exhibit 3.2 to Northern Border Partners, L.P.'s Form
10-K for the year ended December 31, 2004 (File No. 1-12202)).
3.2 Amendment No. 1 to Amended and Restated Agreement of Limited
Partnership of Northern Border Partners, L.P. dated April 6, 2006.
4.1 Form of Class B unit certificate (incorporated by reference to
Exhibit 4.1 to Northern Border Partners, L.P.'s Form 8-K filed on
April 12, 2006 (File No. 1-12202)).
10.1 364-Day Credit Agreement dated April 6, 2006, by and among
Northern Border Partners, L.P., the several banks and other
financial institutions and lenders from time to time party hereto,
SunTrust Bank, as Administrative Agent, Citicorp North America,
Inc., as Syndication Agent and Bank of Montreal (doing business as
Harris Nesbitt), UBS Loan Finance LLC, and Wachovia Bank, National
Association, as Co-Documentation Agents (incorporated by reference
to Exhibit 10.1 to Northern Border Partners, L.P.'s Form 8-K filed
on April 12, 2006 (File No. 1-12202)).
10.2 First Amended and Restated General Partnership Agreement of
Northern Border Pipeline Company dated April 6, 2006 by and
between Northern Border Intermediate Limited Partnership and TC
Pipelines Intermediate Limited Partnership (incorporated by
reference to Exhibit 3.1 to Northern Border Pipeline Company's
Form 8-K filed April 12, 2006 (File No. 333-87753)).
10.3 Services Agreement dated April 6, 2006, by and among ONEOK, Inc.,
Northern Plains Natural Gas Company, LLC, NBP Services, LLC,
Northern Border Partners, L.P. and Northern Border Intermediate
Limited Partnership (incorporated by reference to Exhibit 10.3 to
Northern Border Partners, L.P.'s Form 8-K filed on April 12, 2006
(File No. 1-12202)).
10.4 Consent and Amendment to Operating Agreement dated April 6, 2006,
by and between Northern Border Pipeline Company and Northern
Plains Natural Gas Company, LLC (incorporated by reference to
Exhibit 10.2 to Northern Border Pipeline Company's Form 8-K filed
April 12, 2006 (File No. 333-87753)).
|
10.5 Operating Agreement dated April 6, 2006, by and between Northern
Border Pipeline Company and TransCan Northwest Border Ltd.
(incorporated by reference to Exhibit 10.3 to Northern Border
Pipeline Company's Form 8-K filed April 12, 2006 (File No.
333-87753)).
10.6 Amended and Restated Revolving Credit Agreement dated March 30,
2006, among Northern Border Partners, L.P., the lenders from time
to time party thereto; SunTrust Bank, as administrative agent;
Wachovia Bank, National Association, as Syndication Agent; Harris
Nesbit Financing, Inc., Barclays Bank PLC and Citibank, N.A., as
Co-Documentation Agents. (incorporated by reference to Exhibit
10.1 to Northern Border Partners, L.P. Form 8-K filed March 31,
2006 (File No. 1-2202)).
10.7 The First Amendment to Revolving Credit Agreement dated March 29,
2006, among Northern Border Pipeline Company, the lenders from
time to time party thereto; Wachovia Bank, National Association,
as Administrative Agent; SunTrust Bank, as syndication agent; and
Harris Nesbit Financing, Inc., Barclays Bank PLC, and Citibank,
N.A., as co-documentation agents (incorporated by reference to
Exhibit 10.1 to Northern Border Pipeline Company's Form 8-K filed
April 4, 2006 (File No. 333-87753)).
+31.1 Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
+31.2 Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
+32.1 Section 1350 Certification of Chief Executive Officer.
+32.2 Section 1350 Certification of Chief Financial Officer.
|
# Northern Border Partners agrees to furnish supplementally to the SEC, upon request, any schedules and exhibits to this agreement, as set forth in the Table of Contents of the agreement, that have not been filed herewith pursuant to Item 601(b)(2) of Regulation S-K.
+ Filed herewith
EXHIBIT 3.2
AMENDMENT NO. 1 TO AMENDED AND RESTATED
AGREEMENT OF LIMITED PARTNERSHIP OF
NORTHERN BORDER PARTNERS, L.P.
This Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Northern Border Partners, L.P. (this "Amendment"), dated as of April 6, 2006, is entered into and effectuated by Northern Plains Natural Gas Company, LLC, a Delaware limited liability company ("Northern Plains"), Northwest Border Pipeline Company, a Delaware corporation ("Northwest Border"), and Pan Border Gas Company, LLC, a Delaware limited liability company ("Pan Border" and, together with Northern Plains and Northwest Border, the "General Partners"), as the General Partners, pursuant to authority granted in Section 4.2 and Section 15.1 of the Amended and Restated Agreement of Limited Partnership of Northern Border Partners, L.P., dated as of October 1, 1993 (the "Partnership Agreement"). Capitalized terms used but not defined herein are used as defined in the Partnership Agreement.
RECITALS:
WHEREAS, Section 4.2(a) of the Partnership Agreement provides that the Partnership Policy Committee, without the approval of any Limited Partners, may issue additional Partnership Securities, or classes or series thereof, for any Partnership purpose, at any time or from time to time, and may issue such Partnership Securities for such consideration and on such terms and conditions as shall be established by the Partnership Policy Committee in its sole discretion;
WHEREAS, Section 4.2(b) of the Partnership Agreement provides that the
Partnership Securities authorized to be issued by the Partnership pursuant to
Section 4.2(a) may be issued in one more classes, or one or more series of any
such classes, with such designations, preferences and relative, participating,
optional or other special rights, powers and duties (which may be senior to
existing classes and series of Partnership Securities (except as provided in
Section 4.2(c)) as shall be fixed by the Partnership Policy Committee;
WHEREAS, Section 15.1(f) of the Partnership Agreement provides that the Partnership Policy Committee, without the approval of any Limited Partner or Assignee (subject to the terms of Section 4.2 of the Partnership Agreement), may amend any provision of the Partnership Agreement necessary or appropriate in connection with the authorization for issuance of any class or series of Partnership Securities pursuant to Section 4.2 of the Partnership Agreement;
WHEREAS, the Partnership has entered into a definitive agreement, dated as of February 14, 2006, between the Partnership and ONEOK, Inc., an Oklahoma corporation ("ONEOK") (the "Contribution Agreement");
WHEREAS, as part consideration for the contribution of the Shares to the Partnership, the Contribution Agreement obligates the Partnership to issue limited partner interests to be designated as Class B Units having the terms set forth in this Agreement;
WHEREAS, the Partnership Policy Committee, in consultation with the Audit Committee, has determined that the issuance of the Class B Units provided for in this Amendment is permitted by Section 4.2 of the Partnership Agreement; and
WHEREAS, Section 15.1(d)(i) of the Partnership Agreement provides that the Partnership Policy Committee, without the approval of any Limited Partner or Assignee, may amend any provision of the Partnership Agreement to reflect a change that the Partnership Policy Committee determines, in its sole discretion, does not adversely affect the Limited Partners in any material respect;
NOW, THEREFORE, it is hereby agreed as follows:
A. Amendment. The Partnership Agreement is hereby amended as follows:
1) Section 1.1 is hereby amended to add the following definitions:
"Class B Subordination Period" means the period
commencing upon issuance of the Class B Units and ending
on the earlier of (a) the Conversion Approval Date or
(b) the Conversion Approval Termination Date.
"Class B Unit" means a Unit representing a fractional part of the Partnership Interests of all Limited Partners and Assignees and having the rights and obligations specified with respect to Class B Units in this Agreement. Except as otherwise provided in this Agreement, the term "Class B Unit" does not refer to a Common Unit prior to the conversion of the Class B Unit into a Common Unit pursuant to the terms hereof.
"Class B Unit Arrearage" means, with respect to
any Class B Unit, and as to any calendar quarter within
the Class B Subordination Period, the excess, if any, of
(a) the Minimum Quarterly Distribution with respect to
such Class B Unit (including any applicable increased
amounts distributable with respect to the Minimum
Quarterly Distribution following the Class B
Distribution Increase Date, the Section 4.11(b)
Distribution Increase Date or the GP Removal Date) over
(b) the sum of all Available Cash distributed with
respect to such Class B Unit in respect of such quarter
pursuant to Section 4.10(b)(ii)(A) (and Section
4.10(b)(ii)(A)(1) following the Class B Distribution
Increase Date and/or GP Removal Date, as applicable).
"Cumulative Class B Unit Arrearage" means, with
respect to any Class B Unit, and as of the end of any
calendar quarter (or on the expiration of the Class B
Subordination Period), the excess, if any, of (a) the
sum resulting from adding together the Class B Unit
Arrearage as to such Class B Unit for each of the
quarters within the Class B Subordination Period over
(b) the sum resulting from adding together (i) any
distributions theretofore made pursuant to Section
4.10(b)(ii)(B) (and Section 4.10(b)(ii)(A)(2) following
the Class B Distribution Increase Date and/or GP
Removal Date, as applicable) with respect to such Class B Unit (including any distributions to be made in respect of the last of such quarters) and (ii) any Cumulative Common Unit Arrearage then existing upon conversion of a Class B Unit into a Common Unit pursuant to the terms hereof or the occurrence of a Termination Capital Transaction.
2) Section 1.1 is hereby amended to:
a) add the following sentence to the end of the definition of "Common Unit":
"Except as otherwise provided in this Agreement, the term "Common Unit" does not refer to a Class B Unit prior to the conversion of the Class B Unit into a Common Unit pursuant to the terms hereof."
b) add the phrase "or within the Class B Subordination Period" after the phrase "and as to any calendar quarter within the Subordination Period" in the definition of "Common Unit Arrearage."
c) add the phrase "or within the Class B Subordination Period" after the phrase "for each of the quarters within the Subordination Period ending on or before the last day of such quarter" in clause (a) of the definition of "Cumulative Common Unit Arrearage."
d) add the following proviso to the end of the definition of "Outstanding":
"; provided, further, that, except as provided in Sections 4.11(a), 4.11(b), 4.12(a) and 4.12(b), none of the Class B Units shall be deemed to be Outstanding for purposes of determining if any Class B Units are entitled to distributions of Available Cash unless such Class B Units shall have been reflected on the Partnership's books and records as outstanding during such calendar quarter and on the Record Date for the determination of any distribution of Available Cash;"
e) [Intentionally Omitted]
3) Article IV is hereby amended to add new Sections 4.10 - 4.13 creating a new class of Units as follows:
SECTION 4.10 ESTABLISHMENT OF CLASS B UNITS.
a) General. The Partnership Policy Committee hereby designates and creates a class of Units to be designed as "Class B Units" and consisting of a total of 36,494,126 Class B Units, and fixes the designations, preferences and relative, participating, optional or other special rights, power and duties of holders of the Class B Units as set forth in this Section 4.10.
b) Rights Associated with Class B Units. During the period
commencing upon issuance of the Class B Units and ending
upon the conversion of the Class B Units as set forth in
Section 4.10(f) hereof, unless amended pursuant to
Section 4.11 or Section 4.12 hereof:
i) subject to the provisions of Section
5.1(d)(iii)(A), and unless clauses (ii), (iii), or
(iv) below require a different allocation pursuant
to Section 5.1(c)(i) or otherwise, all items of
Partnership income, gain, loss, deduction and
credit shall be allocated to the Class B Units to
the same extent as such items would be so
allocated if such Class B Units were Common Units
that were then Outstanding;
ii) Notwithstanding anything to the contrary in
Section 5.4, with respect to distributions made in
accordance with Section 5.4 for calendar quarters
ending on or prior to the expiration of the Class
B Subordination Period, the Class B Units shall be
deemed Units, but not Common Units, for such
purposes and, in addition, the holders of Class B
Units shall have the right to share in Partnership
quarterly cash distributions in accordance with
Section 5.4 hereof (such distribution to be
prorated for the quarter in which the Class B
Units are issued), provided that following any
distribution pursuant to Section 5.4(c) and prior
to any distribution pursuant to Section 5.4(d),
Available Cash shall be distributed as follows:
(A) 99% to the holders of Class B Units and 1% to the General Partners, in accordance with their relative General Partner Percentage Interests, until there has been distributed in respect of each Class B Unit Outstanding as of the last day of such quarter an amount equal to the Minimum Quarterly Distribution; and
(B) then, 99% to the holders of Class B Units and 1% to the General Partners, in accordance with their relative General Partner Percentage Interests, until there has been distributed in respect of each Class B
Unit Outstanding as of the last day of such quarter an amount equal to the Cumulative Class B Unit Arrearage, if any, existing with respect to such quarter.
iii) The holders of Class B Units shall have the right to share in Partnership quarterly cash distributions for quarters ending after the expiration of the Class B Subordination Period in accordance with Section 5.4 hereof as if such holders of Class B Units held Common Units and, in addition, notwithstanding anything to the contrary set forth in Section 5.4, if a Cumulative Class B Unit Arrearage exists on the date of the expiration of the Class B Subordination Period, prior to any distribution pursuant to Section 5.4(d), irrespective of whether any such Class B Units are then Outstanding, Available Cash shall be distributed in accordance with Section 4.10(b)(ii)(B) hereof to each holder of record of the applicable Class B Units as of the expiration of the Class B Subordination Period. This distribution shall not be deemed a distribution on a Common Unit, but the satisfaction of prior entitlements of the holders of Class B Units as of the expiration of the Class B Subordination Period. For the taxable year in which such distribution is made, if not previously allocated, each Person receiving such cash distribution shall be allocated items of gross income in an amount equal to such distribution as provided in Section 5.1(d)(iii)(A).
iv) Notwithstanding anything to the contrary in
Section 5.1(c)(i), during the Class B
Subordination Period the Class B Units shall be
treated as Common Units then Outstanding for
purposes of Section 5.1(c)(i), and, in addition,
following any allocation made pursuant to Section
5.1(c)(i)(B) and before an allocation is made
pursuant to Section 5.1(c)(i)(C), any remaining
Net Termination Gain shall be allocated 99% to the
holders of the Class B Units and 1% to the General
Partners, in accordance with their relative
General Partner Percentage Interests, until each
such holder of a Class B Unit has been allocated
Net Termination Gain equal to any then existing
Cumulative Class B Unit Arrearage with respect to
such Class B Unit.
c) Voting Rights. Unless amended pursuant to Section 4.11 or Section 4.12 hereof, (i) during the Class B Subordination Period, the Class B Units are non-voting (and solely for all purposes of calculating votes and determining the presence of a quorum under this Agreement, none of the Class B Units shall be deemed Outstanding), except that the Class B Units shall be entitled to vote
as a separate class on any matter that adversely affects the rights or preferences of the Class B Units in relation to other classes of Partnership Interests or as required by law. The approval of a majority of the Class B Units shall be required to approve any matter for which the holders of the Class B Units are entitled to vote as a separate class, and (ii) upon expiration of the Class B Subordination Period, the Class B Units will have such voting rights pursuant to the Partnership Agreement as such Class B Units would have if they were Common Units that were then Outstanding except that, with respect to the Conversion Approval or Amendment Approval, none of the Class B Units shall be deemed Outstanding as of the record date for such vote or be entitled to vote. Each Class B Unit will be entitled to the number of votes equal to the number of Common Units into which a Class B Unit is convertible at the time of the record date for the vote or written consent on the matter.
d) Certificates. The Class B Units will be evidenced by certificates in such form as the Partnership Policy Committee may approve and, subject to the satisfaction of any applicable legal and regulatory requirements, may be assigned or transferred in a manner identical to the assignment and transfer of other Units. The Certificates will include the restrictive legend set forth in Section 2.17 of the Contribution Agreement.
e) Registrar and Transfer Agent. Northern Plains will act as registrar and transfer agent of the Class B Units.
f) Conversion. Except as provided in this Section 4.10(f), the Class B Units are not convertible into Common Units.
i) Optional Conversion. The Partnership shall, as promptly as practicable following the issuance of any Class B Units, take such actions as may be necessary or appropriate to submit to a vote or consent of its securityholders the approval of a change in the terms of the Class B Units to provide that each Class B Unit shall be convertible from time to time, at the option of the holders thereof, into one Common Unit (subject to appropriate adjustment in the event of any split-up, combination or similar event affecting the Common Units that occurs prior to the conversion of the Class B Units), effective upon approval of the issuance of additional Common Units in accordance with the following sentence (the "Conversion Approval"). The vote or consent required for such approval will be the requisite vote required under the rules or staff interpretations of the National Securities Exchange on which the Common Units are listed or admitted for trading for the listing or addition to
trading of the Common Units that would be issued upon such conversion, excluding those Units held by ONEOK and its affiliates. Upon receipt of the required vote or consent (the date of such approval, the "Conversion Approval Date"), the terms of the Class B Units will be changed, automatically and without further action, so that each Class B Unit may be converted, at the option of the holder thereof, into one Common Unit (subject to appropriate adjustment in the event of any split-up, combination or similar event affecting the Common Units that occurs prior to the conversion of the Class B Units).
ii) Automatic Conversion. The Partnership shall, as promptly as practicable following the issuance of any Class B Units, take such actions as may be necessary or appropriate to submit to a vote or consent of holders of at least 66 2/3% of the Outstanding Units (excluding those Units held by ONEOK and its Affiliates) and otherwise as required by Section 15.2 of the Partnership Agreement, the amendments to the Partnership Agreement described on Annex A (the approval of such amendment, the "Amendment Approval," and the date of obtaining the Amendment Approval, the "Amendment Approval Date"). Subject to Section 4.12, each Class B Unit shall automatically convert into one Common Unit (subject to appropriate adjustment in the event of any split-up, combination or similar event affecting the Common Units that occurs prior to the conversion of the Class B Units) upon receipt of:
(A) Conversion Approval as set forth above in paragraph (i); and
(B) Amendment Approval as set forth above in this paragraph (ii);
and immediately thereafter, none of the Class B Units shall be outstanding.
iii) Quarterly Cash Distributions. Each Common Unit into which a Class B Unit has been converted as provided in this Section 4.10(f) shall have the right to share in any Partnership quarterly cash distributions made in respect of a Common Unit in accordance with Section 5.4 hereof (including, without limitation and not withstanding anything to the contrary contained in the Partnership Agreement, the right to any distributions of amounts in
respect of Cumulative Common Unit Arrearages in respect of a Common Unit).
SECTION 4.11 AMENDMENT OF TERMS OF CLASS B UNITS IF SECURITYHOLDER APPROVAL IS NOT OBTAINED.
a) If:
i) the Conversion Approval has not been obtained by the date that is 12 months following the Closing (as defined under the Contribution Agreement); and
ii) the Amendment Approval has not been obtained by the date that is 12 months following the Closing;
then, unless the provisions of Section 4.12 shall already be in effect, effective as of the next succeeding day (the "Class B Distribution Increase Date") until amended by the provisions of Section 4.12, Sections 4.10(b) and 4.10(c) hereof will be deemed to be amended in their entirety, automatically and without further action, as follows:
"b) Rights Associated with Class B Units. Prior to the
conversion of all of the Class B Units pursuant to
Section 4.10(f) above:
i) subject to the provisions of Section 5.1(d)(iii)(A) and paragraphs (ii) and (iii) below, all items of Partnership income, gain, loss, deduction and credit shall be allocated to the Class B Units to the same extent such items would be allocated if such Class B Units were Common Units then Outstanding, and the allocations to Class B Units shall have the same order of priority relative to allocations on the Common Units;
ii)(A) notwithstanding anything to the contrary in
Section 5.4, the Class B Units shall be
deemed Units, but not Common Units, for
purposes of Section 5.4 and the Class B
Units shall have the right to share in
Partnership quarterly cash distributions in
accordance with Section 5.4 hereof based on
115% of the amount of any Partnership
distribution that would be made to each
Common Unit so that the amount of any
Partnership distribution to each Class B
Unit will equal 115% of the amount of such
distribution to each Common Unit (such
additional 15% pro rated for the quarter in
which the Class B Distribution Increase Date
occurs), provided, however, that following
any distribution pursuant to Section 5.4(c)
and prior to any distribution pursuant to
Section 5.4(d), Available Cash shall be
distributed as follows:
(1) 99% to the holders of Class B Units and 1% to the General Partners, in accordance with their relative General Partner Percentage Interests, until there has been distributed in respect of each Class B Unit Outstanding as of the last day of such quarter an amount equal to 115% of the Minimum Quarterly Distribution; and
(2) then, 99% to the holders of Class B Units and 1% to the General Partners, in accordance with their relative General Partner Percentage Interests, until there has been distributed in respect of each Class B Unit Outstanding as of the last day of such quarter an amount equal to the Cumulative Class B Unit Arrearage, if any, existing with respect to such quarter.
(B) notwithstanding anything to the contrary contained in Section 5.4, if a Cumulative Class B Unit Arrearage exists on the date of the expiration of the Class B Subordination Period, prior to any distribution pursuant to Section 5.4(d), irrespective of whether any such Class B Units are then Outstanding, Available Cash shall be distributed 99% to the holders of record of the applicable Class B Units as of the expiration of the Class B Subordination Period and 1% to the General Partners, in accordance with their relative General Partner Percentage Interests, until there has been distributed in respect of each Class B Unit an amount equal to the Cumulative Class B Unit Arrearage, if any, existing with respect to such quarter. This distribution shall not be deemed a distribution on a Common Unit, but the satisfaction of prior entitlements of the holders of Class B Units as of the expiration of the Class B Subordination Period. For the taxable year in which such distribution is made, if not previously allocated, each Person receiving such cash distribution shall be allocated items of gross income in an amount equal to such distribution as provided in Section 5.1(d)(iii)(A); and
iii) the Class B Units shall have rights upon dissolution and liquidation of the Partnership, including the right to share in any liquidating distributions, that are based on 115% of the liquidating distributions that would be made to the Common Units so that the amount of any liquidating distribution to each Class B Unit will equal 115% of the amount of such distribution to each Common Unit, and, in addition, following any allocation made pursuant to Section 5.1(c)(i)(B) and before an allocation is made pursuant to Section 5.1(c)(i)(C), any remaining Net Termination Gain shall be allocated 99% to
the holders of the Class B Units and 1% to the General Partners, in accordance with their relative General Partner Percentage Interests, until each such holder of a Class B Unit has been allocated Net Termination Gain equal to any then existing Cumulative Class B Unit Arrearage with respect to such Class B Unit, and accordingly, notwithstanding anything to the contrary in this Agreement, prior to any distribution under Section 14.3, the Capital Account of each Partner shall be adjusted to give effect to the foregoing liquidation rights.
c) Voting Rights. The Class B Units will have such voting rights pursuant to the Partnership Agreement as such Class B Units would have if they were Common Units that were then Outstanding except that, with respect to the Conversion Approval or Amendment Approval, none of the Class B Units shall be deemed Outstanding as of the record date for such vote or be entitled to vote. Each Class B Unit will be entitled to the number of votes equal to the number of Common Units into which a Class B Unit is convertible at the time of the record date for the vote or written consent on the matter."
(b If:
i) the Conversion Approval has been obtained by the date that is 12 months following the Closing (as defined under the Contribution Agreement); and
ii) the Amendment Approval has not been obtained by the date that is 12 months following the Closing;
then, unless the provisions of Section 4.12 shall already be in effect, effective as of the next succeeding day (the "Section 4.11(b) Distribution Increase Date") until amended by the provisions of Section 4.12, Sections 4.10(b) and 4.10(c) hereof will be deemed to be amended in their entirety, automatically and without further action, as follows:
"b) Rights Associated with Class B Units. Prior to the conversion of all of the Class B Units pursuant to Section 4.10(f) above:
i) subject to the provisions of Section
5.1(d)(iii)(A) and paragraphs (ii) and
(iii) below, all items of Partnership
income, gain, loss, deduction and credit
shall be allocated to the Class B Units to
the same extent such items would be
allocated if such Class B Units were
Common Units then Outstanding, and the
allocations to Class B Units shall have
the same order of priority relative to
allocations on the Common Units;
ii) (A) the Class B Units shall have the right to share in Partnership quarterly cash distributions based on 115% of the amount of any Partnership distribution that would be made to each Common Unit so that the amount of any Partnership distribution to each Class B Unit will equal 115% of the amount of such distribution to each Common Unit (such additional 15% pro rated for the quarter in which the Class B Distribution Increase Date occurs), and the right of holders of Class B Units to receive distributions shall have the same order of priority relative to distributions on the Common Units; and
(B) notwithstanding anything to the contrary contained in Section 5.4, if a Cumulative Class B Unit Arrearage existed on the date of the expiration of the Class B Subordination Period, prior to any distribution pursuant to Section 5.4(d), irrespective of whether any such Class B Units are then Outstanding, Available Cash shall be distributed 99% to the holders of record of the applicable Class B Units as of the expiration of the Class B Subordination Period and 1% to the General Partners, in accordance with their relative General Partner Percentage Interests, until there has been distributed in respect of each Class B Unit an amount equal to the Cumulative Class B Unit Arrearage, if any, existing with respect to such quarter. This distribution shall not be deemed a distribution on a Common Unit, but the satisfaction of prior entitlements of the holders of Class B Units as of the expiration of the Class B Subordination Period. For the taxable year in which such distribution is made, if not previously allocated, each Person receiving such cash distribution shall be allocated items of gross income in an amount equal to such distribution as provided in Section 5.1(d)(iii)(A); and
iii) the Class B Units shall have rights upon
dissolution and liquidation of the
Partnership, including the right to share
in any liquidating distributions, that are
based on 115% of the liquidating
distributions that would be made to the
Common Units so that the amount of any
liquidating distribution to each Class B
Unit will equal 115% of the amount of such
distribution to each Common Unit, and, in
addition, following any allocation made
pursuant to Section 5.1(c)(i)(B) and
before an allocation is made pursuant to
Section 5.1(c)(i)(C), any remaining Net
Termination Gain shall be allocated 99% to
the holders of the Class B Units and 1% to
the General Partners, in accordance with
their relative General Partner Percentage
Interests, until each such holder of a
Class B Unit
has been allocated Net Termination Gain equal to any then existing Cumulative Class B Unit Arrearage with respect to such Class B Unit, and accordingly, notwithstanding anything to the contrary in this Agreement, prior to any distribution under Section 14.3, the Capital Account of each Partner shall be adjusted to give effect to the foregoing liquidation rights.
c) Voting Rights. The Class B Units will have such voting rights pursuant to the Partnership Agreement as such Class B Units would have if they were Common Units that were then Outstanding except that, with respect to the Conversion Approval or Amendment Approval, none of the Class B Units shall be deemed Outstanding as of the record date for such vote or be entitled to vote. Each Class B Unit will be entitled to the number of votes equal to the number of Common Units into which a Class B Unit is convertible."
c) If a Class B Distribution Increase Date or Section
4.11(b) Distribution Increase Date has occurred and the
Partnership's securityholders thereafter either (1)
obtain the Conversion Approval and the Amendment
Approval, or (2) any of the Class B Units are converted
into Common Units pursuant to Section 4.10(f)(i), then,
unless the provisions of Section 4.12 shall already be
in effect, (i) with respect to the matters described in
sub-clause (1) above, as of the later of the Conversion
Approval Date and the Amendment Approval Date, all Class
B Units shall automatically, and without further action
of the holder(s) thereof, be converted into Common Units
in accordance with Section 4.10(f)(ii), and (ii) with
respect to matters described in sub-clauses (1) and (2)
above for the quarter in which such conversion occurs,
concurrently with the distribution made in accordance
with Article V of the Partnership Agreement of Available
Cash, with respect to the quarter in which the
conversion of the Class B Units is effected, a
distribution shall be paid to each holder of record of
the applicable Class B Units as of the effective date of
such conversion, with the amount of such distribution
for each such Class B Unit to be equal to the product of
(a) 15% of the amount to be distributed in respect of
such quarter to each Common Unit times (it being agreed
that each such Common Unit issued upon conversion shall
be entitled to the full distribution payable to the
holder of a Common Unit) and (b) a fraction, of which
(A) the numerator is the number of days in such quarter
up to but excluding the date of such conversion, and (B)
the denominator is the total number of days in such
quarter (the foregoing amount being referred to as an
"Excess Payment"). For the taxable year in which an
Excess Payment is made, each holder of a Class B Unit
shall be allocated items of gross income with respect to
such taxable year in an amount equal to the Excess
Payment distributed to it as provided in Section
5.1(d)(iii)(A).
SECTION 4.12 AMENDMENT OF TERMS OF CLASS B UNITS UPON REMOVAL OF THE GENERAL PARTNER.
a) If prior to the conversion of all Class B Units, a resolution of the Limited Partners holding the requisite majority of Outstanding Units is passed approving the removal of any Affiliate of ONEOK as the general partner of the Partnership (a "GP Removal Event") and the Conversion Approval has not been obtained, then notwithstanding Section 4.11, automatically and without further action and, effective as of the next succeeding day (the "GP Removal Date"), Section 4.10(f)(ii) shall be deemed to be deleted in its entirety, automatically and without further action, and Sections 4.10(b) and 4.10(c) hereof will be deemed to be amended in their entirety, automatically and without further action, as follows:
"b) Rights Associated with Class B Units. Prior to the conversion of the Class B Units as set forth in Section 4.10(f) hereof:
i) subject to the provisions of Section 5.1(d)(iii)(A) and paragraphs (ii) and (iii) below, all of items Partnership income, gain, loss, deduction and credit shall be allocated to the Class B Units to the same extent as such items would be allocated if such Class B Units were Common Units then Outstanding, and the allocations to Class B Units shall have the same order of priority relative to allocations on the Common Units; and
ii) (A) notwithstanding anything to the contrary in
Section 5.4, the Class B Units shall be deemed
Units, but not Common Units, for purposes of Section
5.4 and the Class B Units shall have the right to
share in Partnership quarterly cash distributions in
accordance with Section 5.4 hereof based on 125% of
the amount of any Partnership distribution that
would be made to each Common Unit so that the amount
of any Partnership distribution to each Class B Unit
will equal 125% of the amount of such distribution
to each Common Unit (such additional 25% pro rated
for the quarter in which the GP Removal Date
occurs), provided, however, that following any
distribution pursuant to Section 5.4(c) and prior to
any distribution pursuant to Section 5.4(d),
Available Cash shall be distributed as follows:
(1) 99% to the holders of Class B Units and 1% to the General Partners, in accordance with their relative General Partner Percentage Interests, until there has been distributed in respect of each Class B Unit Outstanding as of the last day of such quarter an amount equal to 125% of the Minimum Quarterly Distribution; and
(2) then, 99% to the holders of Class B Units and 1% to the General Partners, in accordance with their relative General Partner Percentage Interests, until there has been
distributed in respect of each Class B Unit Outstanding as of the last day of such quarter an amount equal to the Cumulative Class B Unit Arrearage, if any, existing with respect to such quarter.
(B)notwithstanding anything to the contrary in Section 5.4, if a Cumulative Class B Unit Arrearage exists on the date of the expiration of the Class B Subordination Period, prior to any distribution pursuant to Section 5.4(d), irrespective of whether any such Class B Units are then Outstanding, Available Cash shall be distributed 99% to the holders of record of the applicable Class B Units as of the expiration of the Class B Subordination Period and 1% to the General Partners, in accordance with their relative General Partner Percentage Interests, until there has been distributed in respect of each Class B Unit an amount equal to the Cumulative Class B Unit Arrearage, if any, existing with respect to such quarter. This distribution shall not be deemed a distribution on a Common Unit, but the satisfaction of prior entitlements of the holders of Class B Units as of the expiration of the Class B Subordination Period. For the taxable year in which such distribution is made, if not previously allocated, each Person receiving such cash distribution shall be allocated items of gross income in an amount equal to such distribution as provided in Section 5.1(d)(iii)(A); and
iii) the Class B Units shall have rights upon dissolution and liquidation of the Partnership, including the right to share in any liquidating distributions, that are based on 125% of the liquidating distributions that would be made to the Common Units so that the amount of any liquidating distribution to each Class B Unit will equal 125% of the amount of such distribution to each Common Unit, and, in addition, following any allocation made pursuant to Section 5.1(c)(i)(B) and before an allocation is made pursuant to Section 5.1(c)(i)(C), any remaining Net Termination Gain shall be allocated 99% to the holders of the Class B Units and 1% to the General Partners, in accordance with their relative General Partner Percentage Interests, until each such holder of a Class B Unit has been allocated Net Termination Gain equal to any then existing Cumulative Class B Unit Arrearage with respect to such Class B Unit, and accordingly, notwithstanding anything to the contrary in this Agreement, prior to any distribution under Section 14.3, the Capital Account of each Partner shall be adjusted to give effect to the foregoing liquidation rights.
c) Voting Rights. The Class B Units will have such voting rights pursuant to the Partnership Agreement as such Class B Units would have if they were Common Units that were then Outstanding except that, (i) for the purposes of the definition of "Outstanding" such Class B Units shall be deemed to be "Units," but not "Common Units," for all purposes thereof and (ii) with respect to the Conversion Approval (if not already obtained), none of the Class B Units shall be deemed Outstanding as of the record date for such vote or be entitled to vote . Each Class B Unit will be entitled to one vote on each matter with respect to which such Class B Unit is entitled to be voted."
b) If, the Conversion Approval has been obtained and a GP Removal Event occurs, then notwithstanding Section 4.11, automatically and without further action and, effective as of the GP Removal Date, Section 4.10(f)(ii) shall be deemed to be deleted in its entirety, automatically and without further action, and Sections 4.10(b) and 4.10(c) hereof will be deemed to be amended in their entirety, automatically and without further action, as follows:
"b) Rights Associated with Class B Units. Prior to the conversion of the Class B Units as set forth in Section 4.10(f) hereof:
i) subject to the provisions of Section 5.1(d)(iii)(A) and paragraphs (ii) and (iii) below, all of items Partnership income, gain, loss, deduction and credit shall be allocated to the Class B Units to the same extent as such items would be allocated if such Class B Units were Common Units then Outstanding, and the allocations to Class B Units shall have the same order of priority relative to allocations on the Common Units; and
ii)(A) the Class B Units shall have the right to share in Partnership quarterly cash distributions based on 125% of the amount of any Partnership distribution that would be made to each Common Unit so that the amount of any Partnership distribution to each Class B Unit will equal 125% of the amount of such distribution to each Common Unit (such additional 25% pro rated for the quarter in which the GP Removal Date occurs), and the right of holders of Class B Units to receive distributions shall have the same order of priority relative to distributions on the Common Units; and,
(B)notwithstanding anything to the contrary in
Section 5.4, if a Cumulative Class B Unit Arrearage
existed on the date of the expiration of the Class B
Subordination Period, prior to any distribution
pursuant to Section 5.4(d), irrespective of whether
any such Class B Units are then Outstanding,
Available Cash shall be distributed 99% to the
holders of record of the applicable Class B Units as of the expiration of the Class B Subordination Period and 1% to the General Partners, in accordance with their relative General Partner Percentage Interests, until there has been distributed in respect of each Class B Unit an amount equal to the Cumulative Class B Unit Arrearage, if any, existing with respect to such quarter. This distribution shall not be deemed a distribution on a Common Unit, but the satisfaction of prior entitlements of the holders of Class B Units as of the expiration of the Class B Subordination Period. For the taxable year in which such distribution is made, if not previously allocated, each Person receiving such cash distribution shall be allocated items of gross income in an amount equal to such distribution as provided in Section 5.1(d)(iii)(A); and
iii) the Class B Units shall have rights upon dissolution and liquidation of the Partnership, including the right to share in any liquidating distributions, that are based on 125% of the liquidating distributions that would be made to the Common Units so that the amount of any liquidating distribution to each Class B Unit will equal 125% of the amount of such distribution to each Common Unit, and, in addition, following any allocation made pursuant to Section 5.1(c)(i)(B) and before an allocation is made pursuant to Section 5.1(c)(i)(C), any remaining Net Termination Gain shall be allocated 99% to the holders of the Class B Units and 1% to the General Partners, in accordance with their relative General Partner Percentage Interests, until each such holder of a Class B Unit has been allocated Net Termination Gain equal to any then existing Cumulative Class B Unit Arrearage with respect to such Class B Unit, and accordingly, notwithstanding anything to the contrary in this Agreement, prior to any distribution under Section 14.3, the Capital Account of each Partner shall be adjusted to give effect to the foregoing liquidation rights.
c) Voting Rights. The Class B Units will have such voting rights pursuant to the Partnership Agreement as such Class B Units would have if they were Common Units that were then Outstanding except that, for the purposes of the definition of "Outstanding" such Class B Units shall be deemed to be "Units", but not "Common Units" for all purposes thereof. Each Class B Unit will be entitled to one vote on each matter with respect to which such Class B Unit is entitled to be voted."
c) If a GP Removal Event has occurred and any of the Class B Units are converted into Common Units pursuant to Section 4.10(f)(i), then, for the quarter in which such conversion occurs, concurrently with the distribution made in
accordance with Article V of the Partnership Agreement of Available Cash, with respect to the quarter in which the conversion of the Class B Units is effected, a distribution shall be paid to each holder of record of the applicable Class B Units as of the effective date of such conversion, with the amount of such distribution for each such Class B Unit to be equal to the product of (a) 25% of the amount to be distributed in respect of such quarter to each Common Unit times (it being agreed that each such Common Unit issued upon conversion shall be entitled to the full dividend payable to the holder of a Common Unit) (b) a fraction, of which (i) the numerator is the number of days in such quarter up to but excluding the date of such conversion, and (ii) the denominator is the total number of days in such quarter (the foregoing amount being referred to as an "Excess Payment"). For the taxable year in which an Excess Payment is made, each holder of a Class B Unit shall be allocated items of gross income with respect to such taxable year in an amount equal to the Excess Payment distributed to it as provided in Section 5.1(d)(iii)(A).
SECTION 4.13 CHANGE OF NEW YORK STOCK EXCHANGE RULES OR INTERPRETATIONS.
If at any time (i) the rules of the National Securities Exchange on which the Common Units are listed or admitted to trading or the staff interpretations of such rules are changed, or (ii) facts and circumstances arise so that the Conversion Approval is no longer required as a condition to the listing of the Common Units that would be issued upon any conversion of any Class B Units into Common Units as provided in Section 4.10(f)(i) hereof as determined by the Partnership Policy Committee (the date that the Partnership Policy Committee makes such determination, the "Conversion Approval Termination Date") and the Amendment Approval has been obtained, then, unless the provisions of Section 4.12 shall already be in effect, the terms of such Class B Units will be changed so that each such Class B Unit is converted (without further action or any vote of any securityholders of the Partnership) into one Common Unit (subject to appropriate adjustment in the event of any split-up, combination or similar event affecting the Common Units).
B. Agreement in Effect. Except as hereby amended, the Partnership Agreement shall remain in full force and effect.
C. Applicable Law. This Amendment shall be construed in accordance with and governed by the laws of the State of Delaware.
D. Invalidity of Provisions. If any provision of this Amendment is or becomes invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein shall not be effected thereby.
E. Counterparts. This Amendment may be executed in counterparts, all of which together shall constitute an agreement binding on all parties thereto, notwithstanding that all such parties are not signatories to the original or the same counterpart.
General Partners:
Northern Plains Natural Gas Company, LLC
/s/ Jerry L. Peters -------------------------------------------------- Name: Jerry L. Peters Title: Vice President, Finance and Treasurer |
Northwest Border Pipeline Company
/s/ David L. Kyle -------------------------------------------------- Name: David L. Kyle Title: Chairman of the Policy Committee |
Pan Border Gas Company, LLC
/s/ Jerry L. Peters -------------------------------------------------- Name: Jerry L. Peters Title: Vice President, Finance and Treasurer |
Limited Partners:
All Limited Partners now and hereafter admitted as limited partner of the Partnership, pursuant to Powers of Attorney now and hereafter executed in favor of, and granted and delivered to, the Members of the Partnership Policy Committee.
Chairman of the Partnership Policy Committee, as attorney-in-fact for all Limited Partners pursuant to the Powers of Attorney granted in Section 1.4
ANNEX A
1. THE FOLLOWING DEFINITIONS SHALL BE DELETED IN THEIR ENTIRETY FROM ARTICLE II:
"GROSS GENERAL PARTNER PERCENTAGE INTEREST"; AND
"HYPOTHETICAL EQUITY VALUE".
2. SECTION 13.2 SHALL BE AMENDED TO READ IN ITS ENTIRETY AS FOLLOWS:
"Section 13.2 Removal of the General Partner.
The General Partner may be removed if such removal is approved by
the Unitholders holding at least 66 2/3% of the Outstanding Units
(including for purposes of such determination Units held by the General
Partner and its Affiliates) voting as a single class. Any such action by
such holders for removal of the General Partner must also provide for the
election of a successor General Partner by the Unitholders holding a
majority of the outstanding Common Units voting as a class (including for
purposes of such determination Units held by the General Partner and its
Affiliates). Such removal shall be effective immediately following the
admission of a successor General Partner. The removal of the General
Partner shall also automatically constitute the removal of the General
Partner as general partner or managing member, to the extent applicable,
of the Intermediate Partnership and any other Group Members of which the
General Partner is a general partner or managing member. If a Person is
elected as a successor General Partner in accordance with the terms of
this Section 13.2, such Person shall, upon admission pursuant to Article
XII, automatically become a successor general partner or managing member,
to the extent applicable, of the Intermediate Partnership and any other
Group Members of which the General Partner is a general partner of a
managing member. The right of the holders of Outstanding Units to remove
the General Partner shall not exist or be exercised unless the Partnership
has received an opinion opining as to the matters covered by a Withdrawal
Opinion of Counsel. Any successor General Partner elected in accordance
with the terms of this Section 13.2 shall be subject to the provisions of
Section 12.3."
3. THE SECOND PARAGRAPH OF SECTION 13.3(a) SHALL BE AMENDED TO READ IN ITS ENTIRETY AS FOLLOWS:
"For purposes of this Section 13.3(a), the fair market value of the Departing Partner's Combined Interest shall be determined by agreement between the Departing Partner and its successor or, failing agreement within 30 days after the effective date of such Departing Partner's departure, by an independent investment banking firm or other independent expert selected by the Departing Partner and its successor, which, in turn, may rely on other experts, and the determination of which shall be conclusive as to such matter. If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the effective date of such departure, then the Departing Partner shall designate an independent investment banking firm or other independent expert, the Departing Partner's successor shall designate an independent investment banking firm or other independent expert, which third independent investment banking firm or other independent expert
shall determine the fair market value of the Combined Interest of the Departing Partner. In making its determination, such third independent investment banking firm or other independent expert may consider the then current trading price of Units on any National Securities Exchange on which Units are then listed or admitted to trading, the value of the Partnership's assets, the rights and obligations of the Departing Partner and other factors it may deem relevant."
4. SECTION 13.3(b) SHALL BE AMENDED TO READ IN ITS ENTIRETY AS FOLLOWS:
(b) If the Combined Interest of a Departing Partner is not acquired by one or more of the remaining General Partners pursuant to Section 11.7(b) or by a successor in the manner set forth in Section 13.3(a), the Departing Partner shall become a Limited Partner and the Combined Interest shall be converted into Common Units based on the fair market value of such Combined Interest as calculated pursuant to Section 13.3(a) and the Current Market Price of the Common Units as of the effective date of the departure of such Departing Partner. Any successor General Partner shall indemnify the Departing Partner as to all debts and liabilities of the Partnership arising on or after the date on which the Departing Partner becomes a Limited Partner. For purposes of this Agreement, conversion of a General Partner's Partnership Interest as a general partner in the Partnership to Common Units will be characterized as if such General Partner contributed its Partnership Interest to the Partnership in exchange for the newly-issued Common Units.
EXHIBIT 31.1
CERTIFICATION
I, David L. Kyle, 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: May 4, 2006 /s/ David L. Kyle
----------------------------------------
David L. Kyle
Chief Executive Officer
|
EXHIBIT 31.2
CERTIFICATION
I, Jim Kneale, 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: May 4, 2006 /s/ Jim Kneale
----------------------------------------
Jim Kneale
Chief Financial Officer
|
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 March 31, 2006 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), David L. Kyle, 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: May 4, 2006 /s/ David L. Kyle
----------------------------------------
David L. Kyle
Chief Executive Officer
|
This certification is made solely for the purpose of 18 U.S.C. Section 1350, and not for any other purpose.
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 March 31, 2006 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), Jim Kneale, as Chief Financial 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: May 4, 2006 /s/ Jim Kneale
----------------------------------------
Jim Kneale
Chief Financial Officer
|
This certification is made solely for the purpose of 18 U.S.C. Section 1350, and not for any other purpose.