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 SEPTEMBER 30, 2005
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______ to ________.
Commission File Number: 1-12202
NORTHERN BORDER PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
DELAWARE 93-1120873
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
13710 FNB PARKWAY
OMAHA, NEBRASKA 68154-5200
(Address of principal executive offices) (Zip code)
(402) 492-7300
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [X] No [ ]
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
The number of common units outstanding as of November 1, 2005, was 46,397,214.
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 and Nine Months Ended September 30, 2005 and 2004... 3
Consolidated Statement of Comprehensive Income -
Three and Nine Months Ended September 30, 2005 and 2004... 4
Consolidated Balance Sheet -
September 30, 2005 and December 31, 2004.................. 5
Consolidated Statement of Cash Flows -
Nine Months Ended September 30, 2005 and 2004............. 6
Consolidated Statement of Changes in Partners' Equity -
Nine Months Ended September 30, 2005...................... 7
Notes to Consolidated Financial Statements................... 8-14
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 15-29
Item 3. Quantitative and Qualitative Disclosures About Market Risk... 30
Item 4. Controls and Procedures...................................... 30
PART II - OTHER INFORMATION
Item 1. Legal Proceedings............................................ 31
Item 6. Exhibits..................................................... 31
Signature.................................................... 32
2
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------- -------------------
2005 2004 2005 2004
-------- -------- -------- --------
(In thousands except per unit amounts)
Operating revenue $183,023 $147,355 $492,819 $433,604
-------- -------- -------- --------
Operating expenses:
Product purchases 45,325 26,084 113,256 70,965
Operations and maintenance 32,234 28,226 95,448 86,623
Depreciation and amortization 20,401 21,319 63,249 64,143
Taxes other than income 10,215 9,633 29,016 27,424
-------- -------- -------- --------
Operating expenses 108,175 85,262 300,969 249,155
-------- -------- -------- --------
Operating income 74,848 62,093 191,850 184,449
-------- -------- -------- --------
Interest expense 22,096 19,263 64,634 56,365
-------- -------- -------- --------
Other income (expense):
Equity earnings in unconsolidated
affiliates 10,381 3,914 19,276 13,879
Other income 1,182 1,017 3,005 2,866
Other expense 263 (809) (194) (1,415)
-------- -------- -------- --------
Other income, net 11,826 4,122 22,087 15,330
-------- -------- -------- --------
Minority interest in net income 13,853 11,274 34,671 36,190
-------- -------- -------- --------
Income from continuing operations before
income taxes 50,725 35,678 114,632 107,224
Income taxes 1,887 1,278 3,783 4,100
-------- -------- -------- --------
Income from continuing operations 48,838 34,400 110,849 103,124
Discontinued operations, net of tax (478) 312 270 1,468
-------- -------- -------- --------
Net income to partners $ 48,360 $ 34,712 $111,119 $104,592
======== ======== ======== ========
Calculation of limited partners' interest in
net income:
Net income to partners $ 48,360 $ 34,712 $111,119 $104,592
Less: General partners' interest in net
income 2,957 2,685 8,192 8,062
-------- -------- -------- --------
Limited partners' interest in net income $ 45,403 $ 32,027 $102,927 $ 96,530
======== ======== ======== ========
Limited partners' per unit net income:
Income from continuing operations $ 0.99 $ 0.68 $ 2.21 $ 2.05
Discontinued operations, net of tax (0.01) 0.01 0.01 0.03
-------- -------- -------- --------
Net income $ 0.98 $ 0.69 $ 2.22 $ 2.08
======== ======== ======== ========
Number of units used in computation 46,397 46,397 46,397 46,397
======== ======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
3
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ -------------------
2005 2004 2005 2004
-------- ------- -------- --------
(In thousands)
Net income to partners $ 48,360 $34,712 $111,119 $104,592
Other comprehensive income:
Changes associated with current period hedging transactions (15,581) 446 (20,789) 1,636
Changes associated with current period foreign
currency translation 164 477 (281) (256)
-------- ------- -------- --------
Total comprehensive income $ 32,943 $35,635 $ 90,049 $105,972
======== ======= ======== ========
The accompanying notes are an integral part of
these consolidated financial statements.
4
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(UNAUDITED)
SEPTEMBER 30, DECEMBER 31,
2005 2004
------------- ------------
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 31,574 $ 33,980
Accounts receivable, net of allowance for doubtful accounts of
$1,623 and $9,175 at September 30, 2005, and December 31, 2004, respectively 73,946 70,007
Materials and supplies, at cost 6,469 5,654
Prepaid expenses and other 6,533 5,650
Derivative financial instruments -- 1,996
---------- ----------
Total current assets 118,522 117,287
---------- ----------
Property, plant and equipment:
Property, plant and equipment 2,984,234 2,943,599
Less: Accumulated provision for depreciation and amortization 1,064,184 1,002,041
---------- ----------
Property, plant and equipment, net 1,920,050 1,941,558
---------- ----------
Investments and other assets:
Investment in unconsolidated affiliates 287,680 273,202
Goodwill 152,782 152,782
Derivative financial instruments 335 2,555
Regulatory assets 13,370 12,308
Other 13,518 14,998
---------- ----------
Total investments and other assets 467,685 455,845
---------- ----------
Total assets $2,506,257 $2,514,690
========== ==========
LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
Current maturities of long-term debt $ 2,869 $ 5,126
Accounts payable 40,991 36,997
Accrued taxes other than income 33,865 32,563
Accrued interest 22,037 16,530
Derivative financial instruments 15,760 --
---------- ----------
Total current liabilities 115,522 91,216
---------- ----------
Long-term debt, net of current maturities 1,328,938 1,325,232
---------- ----------
Minority interests in partners' equity 280,705 290,142
---------- ----------
Reserves and deferred credits:
Deferred income taxes 9,466 7,186
Derivative financial instruments 1,381 840
Regulatory liabilities 2,501 2,232
Other 8,079 8,508
---------- ----------
Total reserves and deferred credits 21,427 18,766
---------- ----------
Commitments and contingencies (Note 6)
Partners' equity:
General partners 15,431 15,603
Common units: 46,397,214 units issued and outstanding at September
30, 2005, and December 31, 2004 756,123 764,550
Accumulated other comprehensive income (11,889) 9,181
---------- ----------
Total partners' equity 759,665 789,334
---------- ----------
Total liabilities and partners' equity $2,506,257 $2,514,690
========== ==========
The accompanying notes are an integral part of
these consolidated financial statements.
5
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(UNAUDITED)
NINE MONTHS ENDED
SEPTEMBER 30,
---------------------
2005 2004
--------- ---------
(In thousands)
CASH FLOW FROM OPERATING ACTIVITIES
Net income to partners $ 111,119 $ 104,592
--------- ---------
Adjustments to reconcile net income to partners to net cash
provided by operating activities:
Depreciation and amortization 63,302 64,753
Minority interests in net income 34,671 36,190
Reserves and deferred credits (426) (1,755)
Equity earnings in unconsolidated affiliates (19,276) (13,879)
Distributions received from unconsolidated affiliates 12,087 9,155
Changes in components of working capital 5,578 2,522
Other (4,418) (9,616)
--------- ---------
Total adjustments 91,518 87,370
--------- ---------
Net cash provided by operating activities 202,637 191,962
--------- ---------
CASH FLOW FROM INVESTING ACTIVITIES
Sale of gathering and processing assets -- 1,655
Investment in unconsolidated affiliates (6,884) --
Capital expenditures for property, plant and equipment (39,526) (17,933)
--------- ---------
Net cash used in investing activities (46,410) (16,278)
--------- ---------
CASH FLOW FROM FINANCING ACTIVITIES
Cash distributions:
General and limited partners (119,718) (119,718)
Minority interests (43,775) (46,799)
Equity contributions from minority interests -- 39,000
Issuance of long-term debt 114,000 100,000
Long-term debt financing costs (1,382) --
Retirement of long-term debt (104,973) (143,783)
Payments upon termination of derivatives (2,785) --
--------- ---------
Net cash used in financing activities (158,633) (171,300)
--------- ---------
Net change in cash and cash equivalents (2,406) 4,384
Cash and cash equivalents at beginning of period 33,980 35,895
--------- ---------
Cash and cash equivalents at end of period $ 31,574 $ 40,279
========= =========
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amount capitalized $ 64,615 $ 53,323
========= =========
Changes in components of working capital:
Accounts receivable $ (3,938) $ (4,260)
Materials and supplies, prepaid expenses and other (1,698) 975
Accounts payable 4,405 2,220
Accrued taxes other than income 1,303 (1,346)
Accrued interest 5,506 4,933
--------- ---------
Total $ 5,578 $ 2,522
========= =========
The accompanying notes are an integral part of
these consolidated financial statements.
6
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY
(UNAUDITED)
ACCUMULATED
OTHER
GENERAL COMPREHENSIVE TOTAL PARTNERS'
PARTNERS COMMON UNITS INCOME EQUITY
-------- ------------ ------------- ---------------
(In thousands)
Balance at December 31, 2004 $15,603 $ 764,550 $ 9,181 $ 789,334
Net income to partners 8,192 102,927 -- 111,119
Changes associated with current period
hedging transactions -- -- (20,789) (20,789)
Changes associated with current period
foreign currency translation -- -- (281) (281)
Distribution to partners (8,364) (111,354) -- (119,718)
------- --------- -------- ---------
Balance at September 30, 2005 $15,431 $ 756,123 $(11,889) $ 759,665
======= ========= ======== =========
The accompanying notes are an integral part of these consolidated
financial statements.
7
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
In this report, references to "we," "us," "our" or the "Partnership"
collectively refer to Northern Border Partners, L.P. and our subsidiary,
Northern Border Intermediate Limited Partnership and its subsidiaries.
We 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, 2004.
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.
Certain reclassifications were made to the 2004 financial statements to conform
to the current year presentation.
We own a 70% general partner interest in Northern Border Pipeline Company. Our
wholly-owned subsidiaries are: Crestone Energy Ventures, L.L.C.; Bear Paw
Energy, LLC; Border Midstream Services, Ltd.; Midwestern Gas Transmission
Company; Viking Gas Transmission Company; and Black Mesa Pipeline, Inc. We also
own a 49% common membership interest 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, L.L.C.; and a 33-1/3% interest in Guardian Pipeline, L.L.C.
In July 2005, we negotiated a settlement agreement with our partner in Bighorn
Gas Gathering related to provisions of the joint venture agreement that provided
for cash flow incentives based on well connections to the gathering system.
These incentives were provided to us through our ownership of preferred A shares
in Bighorn Gas Gathering. In August 2005, as a result of the settlement, we
recognized $5.4 million of equity earnings through our ownership of the
preferred A shares due to us for 2004 and 2005. The settlement agreement
cancelled and effectively redeemed Bighorn Gas Gathering's outstanding preferred
A and B shares and eliminated future incentives and its capital accounts were
adjusted accordingly. The preferred B shares were held by our partner in Bighorn
Gas Gathering.
In August 2005, Crestone Energy Ventures acquired, for $5.1 million, an
additional 3.7% interest in Fort Union Gas Gathering, L.L.C. bringing its total
interest to 37%.
2. CREDIT FACILITIES
The Partnership and Northern Border Pipeline entered into revolving credit
facilities, which are to be used for capital expenditures, acquisitions, general
business purposes and refinancing existing indebtedness. Northern Border
Pipeline entered into a $175 million five-year credit agreement (2005 Pipeline
Credit Agreement) with certain financial institutions in May 2005. We entered
into a $500 million five-year credit agreement (2005 Partnership Credit
Agreement) with certain financial institutions in May 2005. Both of the
revolving credit facilities permit the Partnership and Northern Border Pipeline
to choose the lender's base rate or the London Interbank Offered Rate (LIBOR)
plus a spread that is based on each of our long-term unsecured debt ratings as
the interest rate on our outstanding borrowings, specify the portion of the
borrowings to be covered by specific interest rate options and to specify the
interest rate period. Both the Partnership and Northern Border Pipeline are
required to pay a fee on the principal commitment amounts. As of September 30,
2005, there was $204 million outstanding under the 2005 Partnership Credit
Agreement and no amounts outstanding under the 2005 Pipeline Credit Agreement.
8
Each of the 2005 Partnership and Pipeline Credit Agreements require the
Partnership and Northern Border Pipeline to comply with certain financial,
operational and legal covenants. The agreements require, among other things,
that the Partnership and Northern Border Pipeline maintain ratios of EBITDA (net
income plus minority interests in net income, interest expense, income taxes and
depreciation and amortization) to interest expense of greater than 3 to 1. The
agreements also require the maintenance of ratios of indebtedness to adjusted
EBITDA (EBITDA adjusted for pro forma operating results of acquisitions made
during the year) of no more than 4.75 to 1 for the Partnership and 4.50 to 1 for
Northern Border Pipeline. Pursuant to the credit agreements, if one or more
acquisitions are consummated in which the aggregate purchase price is $25
million or more, the allowable ratios of indebtedness to adjusted EBITDA is
increased to 5.25 to 1 for the Partnership and 5 to 1 for Northern Border
Pipeline for two calendar quarters following the acquisition. Upon any breach of
these covenants, amounts outstanding under the 2005 Partnership and Pipeline
Credit Agreements may become due and payable immediately. As of September 30,
2005, the Partnership and Northern Border Pipeline were in compliance with these
covenants.
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.
On December 9, 2004, we entered into forward-starting interest rate swap
agreements with a total notional amount of $100 million in anticipation of a
ten-year senior note issuance. These swap agreements expired in late May and
early June of 2005, which resulted in the Partnership paying $2.7 million to
counterparties. In June 2005, we entered into a Treasury lock interest rate
agreement with a total notional amount of $200 million in anticipation of a
ten-year senior note issuance. In July 2005, the Partnership paid $0.1 million
to the counterparty at expiration of the Treasury lock interest rate agreement.
We record in accumulated other comprehensive income amounts related to
terminated interest rate swap agreements for cash flow hedges and amortize these
amounts to interest expense over the term of the hedged debt. During the three
and nine months ended September 30, 2005, we amortized approximately $0.5
million and $1.5 million, respectively, related to the terminated interest rate
swap agreements as a reduction to interest expense from accumulated other
comprehensive income. We expect to amortize approximately $0.5 million in the
fourth quarter of 2005.
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 September 30, 2005, the
average effective interest rate on our interest rate swap agreements was 6.56%.
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 September 30, 2005, the accompanying consolidated balance sheet
reflects long-term derivative financial assets of $0.3 million and long-term
derivative financial liabilities of $1.4 million with a decrease in long-term
debt related to our fair value hedges.
We record in long-term debt amounts received or paid related to terminated or
amended interest rate swap agreements for fair value hedges and amortize these
amounts to interest expense over the remaining life of the interest rate swap
agreement. During the three and nine months ended September 30, 2005, we
amortized approximately $1.3 million and $3.9 million, respectively, as a
reduction to interest expense and expect to amortize approximately $1.3 million
in the fourth quarter of 2005.
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 and nine months ended
September 30, 2005, Bear Paw Energy recognized losses of $1.8 million and $0.5
million, respectively, from the settlement of derivative contracts. As of
September 30, 2005, the consolidated balance sheet reflected an unrealized loss
of approximately $15.8 million in current derivative financial instrument
liabilities with a corresponding offset to accumulated other comprehensive
income. If prices remain at current levels, Bear Paw Energy expects to
reclassify approximately $5.8
9
million from accumulated other comprehensive income as a decrease to operating
revenue in the fourth quarter of 2005. However, this decrease would be offset
with increased operating revenue due to the higher prices assumed.
4. BUSINESS SEGMENT INFORMATION
Our business is divided into three reportable segments, defined as components of
the enterprise, about which financial information is available and evaluated
regularly by our management and the Partnership Policy Committee. Our reportable
segments are strategic business units that offer different services. Each
segment is managed separately because each business requires a different
marketing strategy. These segments are as follows: the Interstate Natural Gas
Pipeline segment, which provides natural gas transportation services; the
Natural Gas Gathering and Processing segment, which provides services for the
gathering, treating, processing and compression of natural gas and the
fractionation of natural gas liquids; and the Coal Slurry Pipeline segment,
which transports crushed coal suspended in water.
BUSINESS SEGMENT DATA
NATURAL GAS
INTERSTATE GATHERING
NATURAL GAS AND COAL SLURRY
THREE MONTHS ENDED SEPTEMBER 30, 2005 PIPELINE PROCESSING PIPELINE OTHER (A) TOTAL
- ------------------------------------- ----------- ----------- ----------- --------- --------
(In thousands)
Revenue from external customers $103,190 $ 73,508 $ 6,325 $ -- $183,023
Operating income (loss) 61,147 12,241 2,548 (1,088) 74,848
EBITDA 79,623 26,118 2,021 (910) 106,852
THREE MONTHS ENDED SEPTEMBER 30, 2004
- -------------------------------------
Revenue from external customers $ 95,007 $ 46,807 $ 5,541 $ -- $147,355
Operating income (loss) 53,532 10,779 1,063 (3,281) 62,093
EBITDA 70,488 18,042 1,941 (2,339) 88,132
NINE MONTHS ENDED SEPTEMBER 30, 2005
- -------------------------------------
Revenue from external customers $282,376 $192,120 $18,323 $ -- $492,819
Operating income (loss) 160,700 32,584 4,726 (6,160) 191,850
EBITDA 213,680 62,957 6,101 (4,729) 278,009
NINE MONTHS ENDED SEPTEMBER 30, 2004
- -------------------------------------
Revenue from external customers $287,150 $130,133 $16,321 $ -- $433,604
Operating income (loss) 168,773 19,940 2,779 (7,043) 184,449
EBITDA 220,357 44,131 5,799 (3,793) 266,494
(a) Includes other items not allocable to segments.
10
TOTAL ASSETS BY SEGMENT
SEPTEMBER 30, DECEMBER 31,
2005 2004
------------- ------------
(In thousands)
Interstate natural gas pipeline $1,877,620 $1,904,689
Natural gas gathering and processing 590,751 570,101
Coal slurry pipeline 16,734 18,268
Other (a) 21,152 21,632
---------- ----------
Total assets $2,506,257 $2,514,690
========== ==========
(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.
11
RECONCILIATION OF NET INCOME(LOSS) TO EBITDA
NATURAL GAS
INTERSTATE GATHERING
NATURAL GAS AND COAL SLURRY
THREE MONTHS ENDED SEPTEMBER 30, 2005 PIPELINE PROCESSING PIPELINE OTHER (A) TOTAL
- ------------------------------------- ----------- ----------- ----------- --------- --------
(In thousands)
Net income (loss) $ 36,703 $22,116 $1,741 $(12,200) $ 48,360
Minority interest 13,853 -- -- -- 13,853
Interest expense, net 11,275 115 -- 10,706 22,096
Depreciation and amortization 16,844 3,879 (520) 76 20,279
Income tax 1,081 8 800 508 2,397
AFUDC (133) -- -- -- (133)
-------- ------- ------ -------- --------
EBITDA $ 79,623 $26,118 $2,021 $ (910) $106,852
======== ======= ====== ======== ========
THREE MONTHS ENDED SEPTEMBER 30, 2004
- -------------------------------------
Net income (loss) $ 30,639 $14,219 $ 900 $(11,046) $ 34,712
Minority interest 11,274 -- -- -- 11,274
Interest expense, net 10,688 85 -- 8,490 19,263
Depreciation and amortization 16,826 3,731 858 119 21,534
Income tax 1,088 7 183 98 1,376
AFUDC (27) -- -- -- (27)
-------- ------- ------ -------- --------
EBITDA $ 70,488 $18,042 $1,941 $ (2,339) $ 88,132
======== ======= ====== ======== ========
NINE MONTHS ENDED SEPTEMBER 30, 2005
- ------------------------------------
Net income (loss) $ 92,900 $50,916 $3,595 $(36,292) $111,119
Minority interest 34,671 -- -- -- 34,671
Interest expense, net 33,707 209 -- 30,718 64,634
Depreciation and amortization 50,011 11,815 1,400 76 63,302
Income tax 2,660 17 1,106 769 4,552
AFUDC (269) -- -- -- (269)
-------- ------- ------ -------- --------
EBITDA $213,680 $62,957 $6,101 $ (4,729) $278,009
======== ======= ====== ======== ========
NINE MONTHS ENDED SEPTEMBER 30, 2004
- ------------------------------------
Net income (loss) $ 98,084 $32,694 $2,439 $(28,625) $104,592
Minority interest 36,190 -- -- -- 36,190
Interest expense, net 32,132 299 11 23,923 56,365
Depreciation and amortization 50,310 11,118 2,994 331 64,753
Income tax 3,725 20 355 578 4,678
AFUDC (84) -- -- -- (84)
-------- ------- ------ -------- --------
EBITDA $220,357 $44,131 $5,799 $ (3,793) $266,494
======== ======= ====== ======== ========
(a) Includes other items not allocable to segments.
12
5. NET INCOME PER UNIT
Net income per unit is computed by dividing net income, after deduction of the
general partners' allocation, by the weighted average number of outstanding
common units. The general partners' allocation is equal to an amount based upon
their collective 2% general partner interest adjusted for incentive
distributions. The distribution to partners amount shown on the accompanying
consolidated statement of changes in partners' equity included incentive
distributions to the general partners of approximately $6.0 million.
On October 20, 2005, the Partnership declared a cash distribution of $0.80 per
unit ($3.20 per unit on an annualized basis) for the third quarter ended
September 30, 2005. The distribution is payable on November 14, 2005, to
unitholders of record on October 31, 2005.
6. COMMITMENTS AND CONTINGENCIES
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.
Dunavan Superfund Site - On July 25, 2005, the United States Environmental
Protection Agency (U.S. EPA) notified Midwestern Gas Transmission Company, our
wholly-owned subsidiary, and several other non-affiliated parties, of possible
liability pursuant to the Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA) and requested information related to the Dunavan Oil Site
located in Oakwood, Illinois. Currently, the U.S. EPA has classified Midwestern
Gas Transmission as a de minimis party. Because of the number of potentially
responsible parties involved, cost sharing arrangements with other potentially
responsible parties and the difficulty in determining remediation costs, it is
difficult to determine the liability for remediation. We do not believe costs
related to resolving this matter will have a material impact on our results of
operations or financial position.
7. SALE OF BANKRUPTCY CLAIMS
In June 2005, we executed term sheets with a third party for the sale of our
bankruptcy claims for contracts and associated guarantees held against Enron
Corp. and Enron North America Corp. Proceeds from the sale of the claims are
expected to be $14.6 million, of which $14.0 million have been received. In
2004, we adjusted our allowance for doubtful accounts to reflect an estimated
recovery of $3.4 million ($3.0 million, net to the Partnership) for the claims.
In the second quarter of 2005, we made an adjustment to our allowance for
doubtful accounts of $1.8 million ($1.6 million, net to the Partnership) to
reflect the agreements for the sale. In the third quarter of 2005, Northern
Border Pipeline recognized revenue of $9.4 million ($6.6 million, net to the
Partnership) as a result of the sale.
8. ACCOUNTING PRONOUNCEMENTS
In December 2004, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 123R, "Share-Based
Payment" (Statement 123R) which requires companies to expense the fair value of
share-based payments and includes changes related to the expense calculation for
share-based payments. We are currently assessing the impact of adopting
Statement 123R but do not expect its adoption to have a material impact on our
results of operations or financial position.
In March 2005, the FASB issued Interpretation (FIN) 47, "Accounting for
Conditional Asset Retirement Obligations - an interpretation of FASB Statement
(SFAS) No. 143." The statement clarifies the term "conditional asset retirement
obligation," as used in SFAS No. 143, and the circumstances under which an
entity would have sufficient information to reasonably estimate the fair value
of an asset retirement obligation. The effective date of this
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interpretation is no later than the end of the fiscal year ending after December
15, 2005. The effect of adopting FIN 47 is not expected to be material to our
results of operations or financial position.
In June 2005, the Federal Energy Regulatory Commission (FERC) issued guidance
describing how FERC-regulated companies should account for costs associated with
implementing the pipeline integrity management requirements of the U.S.
Department of Transportation's Office of Pipeline Safety. Under the guidance,
costs to 1) prepare a plan to implement the program, 2) identify high
consequence areas, 3) develop and maintain a record keeping system and 4)
inspect, test and report on the condition of affected pipeline segments to
determine the need for repairs or replacements, are required to be expensed.
Costs of modifying pipelines to permit in-line inspections, certain costs
associated with developing or enhancing computer software and costs associated
with remedial and mitigation actions to correct an identified condition can be
capitalized. The guidance is effective January 1, 2006, to be applied
prospectively. The effect of adopting this order is not expected to be material
to our results of operations or financial position.
9. BLACK MESA PIPELINE
We expect Black Mesa Pipeline to be temporarily shut down upon expiration of our
coal slurry transportation contract on December 31, 2005. The Mohave Generating
Station co-owners, the Hopi Tribe, the Navajo Nation, Peabody Western Coal
Company and other interested parties continue to negotiate water and coal supply
issues. Black Mesa is working to resolve coal slurry transportation issues so
that operations may resume in the future. If there are successful resolutions of
all of these issues and the project receives a favorable Environmental Impact
Statement, we believe our coal slurry pipeline will be modified and
reconstructed in late 2008 and 2009. We anticipate that the capital expenditures
for the Black Mesa refurbishment project will be in the range of $175 million to
$200 million, which will be supported by revenue from a new transportation
contract. We expect to incur temporary shut down and stand by costs of
approximately $2 million in the fourth quarter of 2005 and approximately $4
million to $6 million in 2006. If these issues are not resolved and the Mohave
Generating Station is permanently closed, we expect to incur pipeline removal
and remediation costs of approximately $2 million to $4 million, net of salvage,
and to take a non-cash impairment charge of approximately $12 million related to
goodwill and the remaining undepreciated cost of the pipeline. The costs
associated with permanent shut down are pre-tax and do not consider tax
implications. Depending on how negotiations progress and in accordance with
accounting rules, an impairment charge may be required prior to final resolution
of the issuee concerning Mohave Generating Station even though the project may
ultimately proceed.
14
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 in Item 1 of this quarterly report on Form 10-Q.
References to "we," "us," "our" or the "Partnership" collectively refer to
Northern Border Partners, L.P., our subsidiary, Northern Border Intermediate
Limited Partnership and its subsidiaries.
EXECUTIVE SUMMARY
OVERVIEW
Northern Border Partners, L.P. is a publicly-traded Delaware limited partnership
listed on the New York Stock Exchange under the trading symbol NBP. Formed in
1993, our purpose is to acquire, own and manage pipeline and other midstream
energy assets. We are a leading transporter of natural gas imported from Canada
into the United States.
We conduct our operations through three business segments. Our business segments
and the proportionate share of identifiable assets as of September 30, 2005,
are:
- the interstate natural gas pipeline segment, which provides natural
gas transportation services and accounts for 75% of our identifiable
assets;
- the natural gas gathering and processing segment, which gathers,
treats, processes and compresses natural gas as well as fractionates
natural gas liquids and accounts for 24% of our identifiable assets;
and
- the coal slurry pipeline segment, which transports crushed coal
suspended in water and accounts for 1% of our identifiable assets.
RECENT DEVELOPMENTS
Bankruptcy Claims - In June 2005, Northern Border Pipeline, Crestone Gathering
Services, a wholly-owned subsidiary of Crestone Energy Ventures, and Bear Paw
Energy executed term sheets with a third party for the sale of their bankruptcy
claims held against Enron Corp. and Enron North America Corp. Proceeds from the
sale of the claims are expected to be $14.6 million, of which $14.0 million have
been received. In the third quarter of 2005, Northern Border Pipeline recognized
revenue of $9.4 million ($6.6 million, net to the Partnership) as a result of
the sale.
Bighorn Gas Gathering Preferred A Settlement - In July 2005, we negotiated a
settlement agreement with our partner in Bighorn Gas Gathering related to
provisions of the joint venture agreement that provided for cash flow incentives
based on well connections to the gathering system. These incentives were
provided to us through our ownership of preferred A shares in Bighorn Gas
Gathering. In August 2005, as a result of the settlement, we recognized $5.4
million of equity earnings through our ownership of the preferred A shares due
to us for 2004 and 2005. The settlement agreement cancelled and effectively
redeemed Bighorn Gas Gathering's outstanding preferred A and B shares and
eliminated future incentives and its capital accounts were adjusted accordingly.
The preferred B shares were held by our partner in Bighorn Gas Gathering.
Interest in Fort Union Gas Gathering - In August 2005, Crestone Energy Ventures
acquired, for $5.1 million, an additional 3.7% interest in Fort Union Gas
Gathering bringing its total interest to 37%.
Northern Border Pipeline Chicago III Expansion Project - In September 2005,
Northern Border Pipeline accepted the Federal Energy Regulatory Commission's
(FERC) certificate of public convenience and necessity for the Chicago III
Expansion Project. This project will add 130 million cubic feet per day (MMcf/d)
of transportation capacity from Harper, Iowa to Chicago, Illinois and is fully
subscribed by four shippers under long-term firm service transportation
agreements with terms ranging from five and one-half to ten years. Construction
is estimated to cost approximately $21 million and the target in-service date is
April 2006.
Midwestern Gas Transmission Eastern Extension Project - In October 2005, the
FERC issued its Environmental Assessment concluding that the approval of the
Eastern Extension Project, with appropriate mitigating measures, would not
constitute a major federal action significantly affecting the quality of the
environment. Midwestern Gas
15
Transmission anticipates the issuance of a certificate of public convenience and
necessity by the FERC for the Eastern Extension Project during the fourth
quarter of 2005. The Eastern Extension Project will add 31 miles of pipeline
with 120,000 dekatherms per day of transportation capacity from Portland,
Tennessee to planned interconnections with Columbia Gulf Transmission Company
and East Tennessee Pipeline Company. The project is anticipated to cost
approximately $28 million. The target in-service date is November 2006.
Northern Border Pipeline Contracting - For the third quarter of 2005, all of the
summer design transportation capacity on Northern Border Pipeline's Port of
Morgan, Montana to Ventura, Iowa portion of the pipeline was sold. For October
2005, 63 MMcf/d of summer design transportation capacity was not sold. As of
October 31, 2005, 88 MMcf/d of summer design capacity remained available for
contracting for November and December 2005.
Guardian Pipeline Revenue and Cost Study - In October 2005, Guardian Pipeline
filed a revenue and cost study as well as a settlement agreement to re-establish
the rates initially approved by the FERC. Guardian Pipeline expects to have an
order regarding the settlement early in 2006.
Northern Border Pipeline Rate Case - On November 1, 2005, as required by the
provisions of the settlement of its last rate case, Northern Border Pipeline
filed a rate case with the FERC. The rate case filing proposes an increase to
Northern Border Pipeline's rates; a change to its rate design approach with a
supply zone and market area utilizing a fixed rate per dekatherm and a
dekatherm-mile rate, respectively; a compressor usage surcharge primarily to
recover costs related to powering electric compressors; and the implementation
of a short-term, firm-service rate structure on a prospective basis. Northern
Border Pipeline has proposed an increase in overall revenue of 7.8%. The filing
also incorporates an overall cost of capital of 10.56% base on a rate of return
on equity of 14.20%, an increase in the depreciation rate for transmission plant
from 2.25% to 2.84%, the institution of a negative salvage rate of 0.59% and a
decrease in the billing determinants. Also included in the filing is the
continuation of the inclusion of income taxes in the calculation of the rates.
RECENT ACCOUNTING PRONOUNCEMENTS
The Financial Accounting Standards Board (FASB) recently issued Statement of
Financial Accounting Standards No. 123R, "Share-Based Payment" and
Interpretation 47, "Accounting for Conditional Asset Retirement Obligations - an
interpretation of FASB Statement No. 143." In addition, the FERC issued guidance
related to accounting for pipeline integrity costs. We do not expect the
adoption of these pronouncements to be material to our results of operations or
financial position. For more information about these recent accounting
pronouncements, please refer to Note 8 of the Notes to Consolidated Financial
Statements.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of our financial statements in accordance with U.S. generally
accepted accounting principles requires us 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. Any effects on our financial position or
results of operations resulting from revisions to these estimates are recorded
in the period during which the facts that gave rise to the revision become
known. Key estimates used by management include:
- the economic useful life of our assets used to determine depreciation
and amortization;
- the fair value used to determine possible asset impairment charges;
- the fair value used to record derivative assets and liabilities;
- the fair value of assets acquired; and
- the amount of expense accruals.
There have been no significant changes in our critical accounting policies since
December 31, 2004. For more information about these policies, please refer to
Note 2 of the Notes to Consolidated Financial Statements - Summary of
Significant Accounting Policies in our annual report on Form 10-K for the year
ended December 31, 2004. Our most significant accounting policies are:
16
REGULATORY ASSETS AND LIABILITIES
The interstate natural gas pipeline segment's accounting policies conform to
SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."
Accordingly, certain assets that result from the ratemaking process are
reflected on the balance sheet as regulatory assets. We consider factors such as
regulatory changes and the impact of competition to determine the probability of
future recovery of these assets. If we determine future recovery is no longer
probable, we would be required to write off the regulatory asset at that time.
As of September 30, 2005, the interstate natural gas pipeline segment reflected
regulatory assets of $13.4 million that we expect to recover from our customers
over varying time periods up to 44 years.
Our regulatory liabilities are related to the incremental costs of removal upon
retirement of an asset and represent revenue collected for asset removal costs
that we expect to incur in the future. These are costs incurred in the normal
course of business and are not related to asset retirement obligations. As of
September 30, 2005, the interstate natural gas pipeline segment reflected
regulatory liabilities of $2.5 million.
ESTIMATED USEFUL LIVES OF PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION METHODS
Our long-lived assets are recorded at original cost. We estimate the economic
useful lives of our assets based on historical experience and make adjustments
when changes in planned use, technological advances or other factors show that a
different life is more appropriate. The depreciation rates for our regulated
interstate natural gas pipelines are determined by the FERC's ratemaking
process. Revisions to the estimated economic useful lives of our assets would
impact our depreciation and amortization expense in future periods.
RECOVERABILITY OF LONG-LIVED ASSETS
We review our long-lived assets for impairment according to SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets," when events or
changes in circumstances indicate that the value of our assets on the balance
sheet may not be recoverable. We compare our asset's book value to its expected
future net cash flow to determine recoverability. If an asset is considered to
be impaired, an impairment charge equal to the difference between the fair value
of the asset and its book value would be recognized.
GOODWILL
We account for goodwill according to SFAS No. 142, "Goodwill and Other
Intangible Assets." We have selected the fourth quarter to perform our annual
testing for goodwill impairment.
DERIVATIVE INSTRUMENTS
We use derivative instruments to mitigate commodity price exposure from our
natural gas gathering and processing segment and interest rate risk related to
our financing activities. We record our derivatives at fair value in accordance
with SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities." The fair value of a derivative instrument is determined by the
present value of its future cash flows based on market prices from third party
sources. The accounting treatment for changes in a derivative's fair value
depends on whether it is designated and qualifies as part of a hedge
relationship. If specific hedge criteria are met, the derivative's gains and
losses may offset the hedged item's related results in the income statement. As
of September 30, 2005, the consolidated balance sheet included assets from
derivative financial instruments of $0.3 million and liabilities from derivative
financial instruments of $17.1 million.
REVENUE RECOGNITION
We recognize interstate natural gas pipeline segment revenue according to each
transportation contract for transportation service that is provided to our
customers. Customers with firm service transportation agreements pay a
reservation fee for capacity on our pipelines known as a demand charge
regardless if the shipper actually utilizes its reserved capacity. Firm service
transportation customers also pay a fee based on the volume of natural gas
transported. Customers with interruptible service transportation agreements may
utilize available capacity on our pipelines; however, service is subject to
interruption if capacity is required for customers with firm transportation
agreements. Interruptible service customers are assessed a fee based only on the
volume of natural gas transported.
We recognize natural gas gathering and processing segment operating revenue when
gas is processed in or transported through our facilities. Cash payments
received from producers prior to providing gathering services are deferred and
recognized as revenue based on the depletion of the natural gas reserves
associated with the gathering system.
17
Coal slurry pipeline segment revenue is recognized based on contracted demand
payments, actual tons of coal transported and direct reimbursement of certain
other expenses.
RESULTS OF OPERATIONS
SELECTED FINANCIAL AND OPERATING RESULTS
The following table summarizes financial and operating results by segment for
the three and nine months ended September 30, 2005, and 2004:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------- -------------------
2005 2004 2005 2004
-------- -------- -------- --------
(In thousands, except operating data)
Operating revenue:
Interstate natural gas pipeline $103,190 $ 95,007 $282,376 $287,150
Natural gas gathering and processing 73,508 46,807 192,120 130,133
Coal slurry pipeline 6,325 5,541 18,323 16,321
-------- -------- -------- --------
Total operating revenue 183,023 147,355 492,819 433,604
-------- -------- -------- --------
Operating income (loss):
Interstate natural gas pipeline 61,147 53,532 160,700 168,773
Natural gas gathering and processing 12,241 10,779 32,584 19,940
Coal slurry pipeline 2,548 1,063 4,726 2,779
Other (1,088) (3,281) (6,160) (7,043)
-------- -------- -------- --------
Total operating income 74,848 62,093 191,850 184,449
-------- -------- -------- --------
Income (loss) from continuing operations:
Interstate natural gas pipeline 36,703 30,639 92,900 98,084
Natural gas gathering and processing 22,116 14,219 50,916 32,694
Coal slurry pipeline 1,741 900 3,595 2,439
Other (11,722) (11,358) (36,562) (30,093)
-------- -------- -------- --------
Total income from continuing operations 48,838 34,400 110,849 103,124
-------- -------- -------- --------
Discontinued operations, net of tax (478) 312 270 1,468
-------- -------- -------- --------
Net income $ 48,360 $ 34,712 $111,119 $104,592
======== ======== ======== ========
Operating data by segment (1):
Interstate natural gas pipeline:
MMcf delivered 293,079 271,929 859,943 847,505
MMcf/d average throughput 3,264 3,029 3,216 3,167
Natural gas gathering and processing:
MMcf/d gathered 1,037 1,041 1,032 1,013
MMcf/d processed 67 56 64 54
Coal slurry pipeline:
Thousands of tons shipped 1,150 1,217 3,534 3,346
(1) Operating data includes 100% of the volumes for joint venture investments
as well as for wholly-owned subsidiaries.
18
CONSOLIDATED OPERATING RESULTS
Income from continuing operations was $48.8 million or $0.99 per unit for the
third quarter ended September 30, 2005, an increase of $14.4 million, or 42%,
compared with $34.4 million or $0.68 per unit for the same quarter last year.
The increase was primarily due to revenue from the sale of Northern Border
Pipeline's bankruptcy claims held against Enron and Enron North America,
increased revenue from our gathering and processing segment as a result of
increased commodity prices and volumes processed and recognition of our Bighorn
preferred A settlement.
For the nine months ended September 30, 2005, income from continuing operations
was $110.8 million or $2.21 per unit, an increase of $7.7 million, or 7%,
compared with $103.1 million or $2.05 per unit for the same period last year.
The increase was primarily due to the recognition of several non-recurring
income items during the 2005 period and improved gathering and processing
segment results offset by the revenue impact of Northern Border Pipeline's
uncontracted and discounted capacity and increased interest expense primarily
related to higher average interest rates.
INTERSTATE NATURAL GAS PIPELINE SEGMENT
OVERVIEW
The interstate natural gas pipeline segment transports natural gas for its
customers and is made up of the following subsidiaries:
- a 70% general partnership interest in Northern Border Pipeline
Company;
- Midwestern Gas Transmission Company; and
- Viking Gas Transmission Company, which includes a 33-1/3% interest in
Guardian Pipeline, L.L.C.
Operating revenue is derived from transportation contracts under tariffs that
are regulated by the FERC. The tariffs specify the maximum rates we can charge
our customers for natural gas transportation service on our pipelines, which are
established in FERC proceedings known as rate cases. During a rate case, a
determination is reached by the FERC, either through a hearing or a settlement,
on maximum rates that include the recovery of our prudent cost-based investment
and operating expenses and a reasonable return for our investors.
Our firm service transportation customers pay a fee to reserve capacity on our
pipelines regardless of how much natural gas they actually transport as well as
a fee based on the volume of natural gas transported. Our interruptible service
transportation customers pay a fee based only on the volume of natural gas
transported.
For the nine months ended September 30, 2005, Northern Border Pipeline accounted
for 86% of our interstate natural gas pipeline segment revenue, Midwestern Gas
Transmission accounted for 6% and Viking Gas Transmission accounted for 8%.
MARKET CONDITIONS
As of December 31, 2004, approximately 88% of the natural gas Northern Border
Pipeline transported was produced in the Western Canada Sedimentary Basin.
Viking Gas Transmission's source of natural gas is also from the Western Canada
Sedimentary Basin. As a result, the continuous supply of Canadian natural gas is
crucial to our long-term financial condition. Of equal importance is the demand
for natural gas in the Midwestern United States markets that we serve, including
in the Chicago market area which is served directly by Northern Border Pipeline
and Midwestern Gas Transmission.
Some of the significant factors that may impact our customers' desire to move
natural gas on our interstate natural gas pipelines include:
- the amount of Canadian natural gas available for export, which is
impacted by Canadian supply and demand;
- the ability to transport Canadian gas on other pipelines;
- the amount of storage capacity for Canadian gas and demand for storage
injection;
- the availability of natural gas from other supply sources that could
be transported to the Midwestern United States;
- the demand for natural gas in other markets, which may affect the
supply in the Midwestern United States, primarily as a result of
temperature and/or hydro-electric generation levels; and
19
- the natural gas market price spread between Alberta, Canada and the
Midwestern United States.
For more information about market conditions that may impact supply and demand
for natural gas, please read "Business - Demand for Interstate Pipeline
Transportation Capacity" in our annual report on Form 10-K for the year ended
December 31, 2004.
KNOWN TRENDS AND UNCERTAINTIES
Canadian Supply - We believe that Canadian natural gas supply will remain fairly
stable and import levels will be flat during the remainder of 2005.
Natural Gas Storage Levels - Natural gas storage is necessary to balance supply
and demand, especially as demand shifts from steady load industrial users to
temperature-sensitive residential, commercial and electric generation users as a
result of increasing natural gas prices. Industrial users may utilize more
economical energy sources when the price of natural gas surpasses the price of
alternatives.
During the second quarter of 2005, increased storage injection activity of
Canadian natural gas negatively impacted demand for Northern Border Pipeline's
transportation capacity. As storage levels approached full capacity during the
third quarter of 2005, demand for the pipeline's transportation capacity
increased. Additional Canadian storage projects expected to be in service in
2006 and the anticipated natural gas price differential during the upcoming
April and May shoulder months compared with the 2006-07 winter heating season
are expected to impact Northern Border Pipeline's revenue again in 2006. The
impact of shippers utilizing Canadian storage may reduce demand for Northern
Border Pipeline's capacity during the spring and early summer months and
increase demand during the winter months.
Seasonality - Winter season is considered to be during the months of November to
March and summer season is considered to be during the remaining months. Peak
summer season for electric generation includes July, August and September.
Weather conditions throughout the United States can significantly impact
regional natural gas supply and demand. The Western United States market is
sensitive to precipitation levels which impact hydro-electric generation. During
the summer, high temperatures combined with low hydro-electric generation levels
may increase demand for Canadian natural gas. In the Midwestern United States,
the current pipeline infrastructure is designed to meet winter heating demand
loads. When demand declines as a result of moderate temperatures, excess
pipeline capacity may stimulate greater competition from other supply sources.
To the extent that our transportation capacity is contracted under firm service
transportation agreements, a significant portion of our revenue, which is
generated from demand charges, will not be impacted by seasonal throughput
variations. However, when transportation agreements expire, seasonal demand may
impact our ability to recontract the interstate natural gas pipeline's firm
service transportation capacity. Accordingly, we believe that throughput on our
interstate natural gas pipelines may experience seasonal fluctuations and some
discounting may be required at times to maximize revenue.
Competition - New supply from the Rockies via Cheyenne Plains Pipeline as well
as natural gas from the San Juan and Permian Basins redirected from the Western
United States markets into the Mid-continent region created greater supply
competition in the Midwestern United States market. Cheyenne Plains is expected
to complete an expansion project that will increase its design capacity by 170
million dekatherms per day (MMdth/d) to 730 MMdth/d by early 2006.
Contracting Risk - Our interstate natural gas pipelines' primary exposure to
market risk occurs when existing transportation contracts expire and are subject
to renegotiation. For the third quarter of 2005, all of the summer design
transportation capacity on Northern Border Pipeline's Port of Morgan, Montana to
Ventura, Iowa portion of the pipeline was sold. For October 2005, 63 MMcf/d of
summer design transportation capacity was not sold. As of October 31, 2005, 88
MMcf/d of summer design capacity remained available for contracting for November
and December 2005.
We anticipate that 2006 demand for Northern Border Pipeline's capacity will be
similar to 2005 demand based on our expectations of Canadian natural gas supply
and demand for natural gas in the markets that we serve. We
20
believe that discounting transportation rates on a short-term basis may be
necessary to maximize revenue and anticipate that the level of discounting in
the future will vary from 2005 depending upon current market conditions.
Midwestern Gas Transmission's northbound capacity is 67% contracted and its
southbound capacity is 100% contracted through October 2006. Viking Gas
Transmission is 99% contracted through October 2006.
Growth Projects - We are focused on modifying our systems to meet market demand
in addition to seeking acquisitions and new pipeline development projects.
Growth projects currently underway include:
- Chicago III Expansion Project - Northern Border Pipeline
- Eastern Extension Project - Midwestern Gas Transmission
- Southbound Expansion Project - Midwestern Gas Transmission
In September 2005, Northern Border Pipeline accepted the FERC's certificate of
public convenience and necessity for the Chicago III Expansion Project which
will add 130 MMcf/d of transportation capacity from Harper, Iowa to the Chicago
market area. This expansion is fully subscribed by four shippers under long-term
firm service transportation agreements with terms ranging from five and one-half
to ten years. Construction is estimated to cost approximately $21 million and
the target in-service date is April 2006.
In October 2005, the FERC issued its Environmental Assessment concluding that
the approval of the Eastern Extension Project, with appropriate mitigating
measures, would not constitute a major federal action significantly affecting
the quality of the environment. Midwestern Gas Transmission anticipates the
issuance of a certificate of public convenience and necessity by the FERC for
the Eastern Extension Project during the fourth quarter of 2005. The Eastern
Extension Project will add 31 miles of pipeline with 120,000 dekatherms per day
of transportation capacity from Portland, Tennessee to planned interconnections
with Columbia Gulf Transmission Company and East Tennessee Pipeline Company. The
project is anticipated to cost approximately $28 million. The target in-service
date is November 2006.
The Midwestern Gas Transmission Southbound Expansion Project was completed and
began service on November 1, 2005. The fully-subscribed Southbound Expansion
Project increased the pipeline's southbound capacity by 86,000 dekatherms per
day.
Please refer to "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Interstate Natural Gas Pipeline Segment" in our annual
report on Form 10-K for the year ended December 31, 2004, for more information
about our expansion projects.
REGULATORY DEVELOPMENTS
Northern Border Pipeline Rate Case - On November 1, 2005, as required by the
provisions of the settlement of its last rate case, Northern Border Pipeline
filed a rate case with the FERC. The rate case filing proposes an increase to
Northern Border Pipeline's rates; a change to its rate design approach with a
supply zone and market area utilizing a fixed rate per dekatherm and a
dekatherm-mile rate, respectively; a compressor usage surcharge primarily to
recover costs related to powering electric compressors; and the implementation
of a short-term, firm-service rate structure on a prospective basis. Northern
Border Pipeline has proposed an increase in overall revenue of 7.8%.
The filing also incorporates an overall cost of capital of 10.56% based on a
rate of return on equity of 14.20%, an increase in the depreciation rate for
transmission plant from 2.25% to 2.84%, the institution of a negative salvage
rate of 0.59% and a decrease in the billing determinants. Also included in the
filing is the continuation of the inclusion of income taxes in the calculation
of the rates.
While we cannot predict the FERC and intervening parties' positions on the
proposed changes, we anticipate opposition. We also anticipate that the FERC
will issue an order by early December 2005 that will identify the issues raised
in the proceeding and accept the proposed rates but suspend their effectiveness
until May 1, 2006, at which time the new rates would be collected subject to
refund until final resolution of the rate case. We expect the FERC will set
issues for hearing and unless we are able to reach a settlement with the FERC
staff and our customers, final resolution of this matter may not occur until
2007.
21
Guardian Pipeline Revenue and Cost Study - In October 2005, Guardian Pipeline
filed a revenue and cost study as well as a settlement agreement to re-establish
the rates initially approved by the FERC. Guardian Pipeline expects to have an
order regarding the settlement early in 2006.
INTERSTATE NATURAL GAS PIPELINE SEGMENT OPERATING RESULTS
Net income - The interstate natural gas pipeline segment reported net income of
$36.7 million for the third quarter ended September 30, 2005, an increase of
$6.1 million, or 20%, compared with $30.6 million for the same quarter last
year. Net income was $92.9 million for the nine months ended September 30, 2005,
a decrease of $5.2 million, or 5%, compared with $98.1 million for the same
period last year.
Operating revenue - Operating revenue increased $8.2 million, or 9%, for the
third quarter of 2005 compared with the same quarter last year due to the
recognition of the sale of Northern Border Pipeline's bankruptcy claims for
contracts and associated guarantees held against Enron and Enron North America
of $9.4 million partially offset by decreased firm demand revenue of $2.0
million primarily as a result of discounted Northern Border Pipeline capacity.
Increased revenue from Midwestern Gas Transmission and Viking Gas Transmission
contributed $0.6 million and $0.2 million, respectively.
Operating revenue decreased $4.8 million, or 2%, for the nine months ended
September 30, 2005, compared with the same period last year due to decreased
Northern Border Pipeline revenue associated with uncontracted and discounted
transportation capacity of $13.6 million offset by revenue from the sale of
Northern Border Pipeline's bankruptcy claims of $9.4 million in 2005. An
additional day of transportation revenue due to leap year increased revenue by
$0.9 million in 2004.
Operations and maintenance expense - Operations and maintenance expense
decreased $0.2 million for the third quarter of 2005 compared with the same
quarter last year.
Operations and maintenance expense increased $2.0 million for the nine months
ended September 30, 2005, compared with the same period last year primarily due
to adjustments recorded in 2005 and 2004 for operational gas volume imbalances
on Viking Gas Transmission resulting in a net increase of $2.2 million. Expenses
were reduced by an adjustment to our allowance for doubtful accounts related to
bankruptcy claims of $0.6 million in 2005. In 2004, we recorded an amortization
expense related to the renewal of a right-of-way easement of $1.3 million offset
by adjustments to true up corporate charges and benefit costs of $1.9 million.
Interest expense - Interest expense increased $0.6 million for the third quarter
of 2005 and $1.6 million for the nine months ended September 30, 2005, compared
with the same periods last year as a result of higher average interest rates
partially offset by lower average debt outstanding.
Other income and expense - Net other income increased $1.4 million for the third
quarter of 2005 compared with the same quarter last year primarily due to income
recorded for an adjustment to our allowance for doubtful accounts of $0.6
million in 2005 and increased business development costs of $0.6 million
incurred in 2004.
Net other income increased $1.7 million for the nine months ended September 30,
2005, compared with the same period in 2004 primarily due to income recorded for
adjustments to our allowance for doubtful accounts of $0.4 million and income
related to a waste heat recovery project of $0.3 million in 2005 and increased
business development costs of $0.6 million incurred in 2004.
NATURAL GAS GATHERING AND PROCESSING SEGMENT
OVERVIEW
Our natural gas gathering and processing segment accepts delivery of raw gas
from natural gas wells and central collection points located primarily in the
Powder and Wind River Basins of Wyoming and the Williston Basin of Montana,
North Dakota and Saskatchewan, Canada. Our pipelines gather wellhead production
and transport raw gas to central collection points where it is treated and
processed as necessary and compressed for entry into the interstate natural gas
pipeline grid.
Our natural gas gathering and processing segment is made up of the following
subsidiaries:
22
- Bear Paw Energy, LLC, with operations in the Williston and Powder
River Basins; and
- Crestone Energy Ventures, L.L.C., which owns:
- a 49% interest in Bighorn Gas Gathering, L.L.C., with operations
in the Powder River Basin;
- a 37% interest in Fort Union Gas Gathering, L.L.C., with
operations in the Powder River Basin; and
- a 35% interest in Lost Creek Gathering, L.L.C., with operations
in the Wind River Basin.
In August 2005, Crestone Energy Ventures acquired, for $5.1 million, an
additional 3.7% interest in Fort Union Gas Gathering bringing its total interest
to 37%.
Revenue is derived primarily from two types of gathering and processing
agreements based on volumetric fees or percentage-of-proceeds (POP) contracts.
We are sensitive to fluctuations in the price of natural gas and natural gas
liquids because a significant portion of this segment's revenue is derived from
POP agreements. Under these agreements, we retain a percentage of the
commodities as payment for our services, which we sell in the open market. We
use derivative instruments to mitigate our commodity price exposure.
MARKET CONDITIONS
Key factors that may impact Bear Paw Energy and our joint venture interests are:
- the pace of reserve development by producers, which is affected by:
- a producer's ability to obtain drilling and production permits in
a timely and economic manner;
- reserve characteristics and performance;
- surface access and infrastructure issues;
- significant volumes of water associated with coalbed methane
production;
- environmental issues;
- the decline rate of existing wells;
- the composition of the gathered raw gas stream;
- the market value of natural gas and natural gas liquids; and
- competition which may reduce gathered volumes or influence contract
terms and margins.
For more information about market conditions that may impact our gathering and
processing segment, please read "Business - Future Demand and Competition" in
our annual report on Form 10-K for the year ended December 31, 2004.
KNOWN TRENDS AND UNCERTAINTIES
Powder River Basin Development - The development of new facilities in the Powder
River Basin is based on natural gas well development, field production
economics, permit considerations and other factors that impact producers'
decision to drill and produce coalbed methane gas. Drilling activity in the
Powder River Basin is expected to increase compared with 2004.
Williston Basin Development - Bear Paw Energy owns and operates the Grasslands,
Baker, Marmarth, Little Beaver and Lignite gathering and processing facilities
in the Williston Basin. We expect casinghead gas volumes will continue to
increase at least through 2006 but at a slower rate of growth compared with
2005. During the third quarter of 2005, we completed an expansion of our
gathering system in the Beaver Creek area which will increase our processing
volumes at the Grasslands facility. We also completed an optimization project at
the Baker facility which will improve the plant's utilization. In the fourth
quarter of 2005, we expect to complete an optimization project at our Grasslands
facility.
Raw Gas Composition - Changes in the raw gas composition may impact our
operating margins. Most of the wells connected to our Williston Basin facilities
produce casinghead gas which is significantly higher in energy content (measured
in Btus) than coalbed methane gas produced in the Powder River Basin. We do not
anticipate significant changes in raw gas composition in the near future.
Gathering Volumes - The volume and pressure of gas gathered impact the Powder
River Basin operations which generate revenue primarily through volumetric
fee-based contracts. We provide two different levels of service depending upon
the pressure of the gas gathered. Our processing margins are higher for low
pressure gas gathered compared with high pressure gas gathered due to the
difference in the amount of compression required to transport
23
the gas through our gathering system and into the interstate pipeline grid. As a
result of these different service levels, a change in our processing volume will
not impact revenue proportionately.
Natural Gas and Natural Gas Liquids Pricing - The price of natural gas and
natural gas liquids impact the Williston Basin operations which generate revenue
primarily through POP contracts.
Realized commodity prices, net of hedging, continued its upward trend: the
weighted average price per million British thermal units (MMBtus) of natural gas
was $6.83 for the third quarter of 2005, an increase of $1.93, or 39%, compared
with $4.90 for the same period last year; the weighted average price per gallon
of natural gas liquids was $0.93 for the third quarter of 2005, an increase of
$0.19, or 26%, compared with $0.74 for the same period last year.
Competition - Current natural gas prices are attracting competition to the
natural gas gathering and processing business particularly in the Western United
States. As competition increases, we expect that there will be continued
pressure on gathering and processing margins.
NATURAL GAS GATHERING AND PROCESSING SEGMENT OPERATING RESULTS
Net income - The natural gas gathering and processing segment reported net
income of $22.1 million for the third quarter ended September 30, 2005, an
increase of $7.9 million, or 56%, compared with $14.2 million for the same
quarter last year. Net income was $50.9 million for the nine months ended
September 30, 2005, an increase of $18.2 million, or 56%, compared with $32.7
million for the same period last year.
Operating revenue - Operating revenue increased $26.8 million, or 57%, for the
third quarter of 2005 compared with the same quarter last year due to increased
Williston Basin revenue of $27.5 million related to higher natural gas and
natural gas liquids prices and processing volumes partially offset by decreased
Powder River revenue of $0.7 million related to lower volumes.
Operating revenue increased $62.0 million, or 48%, for the nine months ended
September 30, 2005, compared with the same period last year due to increased
revenue realized in the Williston Basin of $64.4 million partially offset by
decreased Powder River revenue of $2.3 million.
Product purchases - Product purchases increased $19.2 million for third quarter
2005 and $42.3 million for the nine months ended September 30, 2005, compared
with the same periods last year as the result of higher prices and volumes
realized for Williston Basin-processed commodities.
Operations and maintenance expense - Operations and maintenance expense
increased $5.8 million for third quarter 2005 compared with the same quarter
last year primarily due to the recovery of our allowance for doubtful accounts
related to Enron and Enron North America for Bear Paw Energy's bankruptcy claims
of $1.8 million and a gain from the sale of assets of $3.1 million both
recognized in the third quarter of 2004. In the third quarter of 2005, operating
expenses related to expansions in the Williston Basin increased $0.9 million
compared with the same quarter last year.
Operations and maintenance expense increased $6.1 million for the nine months
ended September 30, 2005, compared with the same period last year due to the
recovery of our allowance for doubtful accounts and a gain from the sale of
assets of $5.2 million in 2004. In 2005, increased operating expenses related to
expansions in the Williston Basin of $1.6 million and higher general and
administrative costs of $0.5 million were partially offset by an additional
recovery of our allowance for doubtful accounts related to Enron and Enron North
America of $1.2 million.
Equity earnings - Equity earnings increased $6.3 million for the quarter
compared with the same quarter last year due to the $5.4 million Bighorn
preferred A settlement as well as increased volumes and resulting performance
from Bighorn Gas Gathering of $0.5 million and Fort Union Gas Gathering of $0.4
million.
Equity earnings increased $5.2 million for the nine months ended September 30,
2005, compared with the same period in 2004 due to an additional $2.7 million
from the Bighorn preferred A settlement recognized in 2005 as well as increased
equity earnings from Fort Union of $1.5 million and Lost Creek of $1.1 million
as a result of increased volumes in the Powder and Wind River Basins.
24
COAL SLURRY PIPELINE SEGMENT
OVERVIEW
Our coal slurry pipeline segment, which includes Black Mesa Pipeline, Inc.,
transports crushed coal suspended in water. Revenue is derived from a
transportation contract with the sole supplier of coal to the Mohave Generating
Station in Nevada. This contract generates fee-for-service revenue through
December 31, 2005.
KNOWN TRENDS AND UNCERTAINTIES
We expect Black Mesa Pipeline to be temporarily shut down upon expiration of our
coal slurry transportation contract on December 31, 2005. The Mohave Generating
Station co-owners, the Hopi Tribe, the Navajo Nation, Peabody Western Coal
Company and other interested parties continue to negotiate water and coal supply
issues. Black Mesa is working to resolve coal slurry transportation issues so
that operations may resume in the future. If there are successful resolutions of
all of these issues and the project receives a favorable Environmental Impact
Statement, we believe our coal slurry pipeline will be modified and
reconstructed in late 2008 and 2009. We anticipate that the capital expenditures
for the Black Mesa refurbishment project will be in the range of $175 million to
$200 million, which will be supported by revenue from a new transportation
contract. We expect to incur temporary shut down and stand by costs of
approximately $2 million in the fourth quarter of 2005 and approximately $4
million to $6 million in 2006. If these issues are not resolved and the Mohave
Generating Station is permanently closed, we expect to incur pipeline removal
and remediation costs of approximately $2 million to $4 million, net of salvage,
and to take a non-cash impairment charge of approximately $12 million related to
goodwill and the remaining undepreciated cost of the pipeline. The costs
associated with permanent shut down are pre-tax and do not consider tax
implications. Depending on how negotiations progress and in accordance with
accounting rules, an impairment charge may be required prior to final resolution
of the issues concerning Mohave Generating Station even though the project may
ultimately proceed.
For more information about the environmental issues surrounding our coal slurry
pipeline, please read "Business - Coal Slurry Pipeline Segment" in our annual
report on Form 10-K for the year ended December 31, 2004.
OPERATING RESULTS
Net income - The coal slurry pipeline segment reported net income of $1.7
million for the third quarter ended September 30, 2005, an increase of $0.8
million compared with $0.9 million for the same quarter last year. Net income
was $3.6 million for the nine months ended September 30, 2005, an increase of
$1.2 million compared with $2.4 million for the same period last year.
Operating revenue - Operating revenue increased $0.8 million for the third
quarter of 2005 compared with the same quarter last year primarily due to a
revenue adjustment related to the consumer price index change billed during the
quarter retroactive to January 1, 2005.
Operating revenue increased $2.0 million for the nine months ended September 30,
2005 compared with the same period last year due to an adjustment related to the
consumer price index change which increased revenue $0.6 million and increased
electricity costs and other expenses charged to the customer of $1.1 million.
Operations and maintenance expense - Operations and maintenance expense
increased $0.7 million for the third quarter of 2005 and $1.6 million for the
nine months ended September 30, 2005, compared with the same periods last year
due to increased electricity costs and other expenses.
Depreciation and amortization - Depreciation expense decreased $1.4 million for
the third quarter of 2005 and $1.6 million for the nine months ended September
30, 2005, compared with the same periods last year due to adjustments to
depreciation.
Income taxes - Income taxes increased $0.6 million for the third quarter of 2005
and $0.8 million for the nine months ended September 30, 2005, compared with the
same periods last year due to increased pre-tax income.
25
OTHER
Items not attributable to any segment include certain of our general and
administrative expenses, interest expense on our debt and other income and
expense items.
For the third quarter of 2005, operating and maintenance expense decreased $2.2
million compared with the same quarter last year due to the allocation of
expenses to subsidiaries of $0.6 million, decreased outside service expenses of
$0.3 million and decreased business development costs of $1.2 million. Interest
expense not allocated to any segment increased $2.2 million for the third
quarter compared with the same quarter last year due to increased average debt
outstanding and higher average interest rates.
For the nine months ended September 30, 2005, operations and maintenance expense
decreased $0.9 million compared to the same period in 2004 due to decreased
business development costs of $1.2 million. Interest expense not allocated to
any segment increased $6.7 million for the nine months ended September 30, 2005,
compared with the same period last year due to increased average debt
outstanding and higher average interest rates.
LIQUIDITY AND CAPITAL RESOURCES
OVERVIEW
We believe our liquidity is adequate to fund future recurring operating
activities and investments. We rely on our operating cash flow and the credit
facilities listed in the following table to meet our short-term liquidity needs.
We expect to meet our other liquidity needs by issuing long-term debt and
additional limited partner interests. The timing and our ability to complete
such offerings will depend on various factors, including:
- the prevailing market conditions;
- interest rates;
- our financial condition; and
- our credit rating.
DEBT AND CREDIT FACILITIES
The following table summarizes the Partnership's debt and credit facilities
outstanding as of September 30, 2005:
PAYMENTS DUE BY PERIOD
----------------------
CURRENT
PORTION LONG-TERM
TOTAL < 1 YEAR PORTION
---------- -------- ----------
(In thousands)
Northern Border Pipeline:
$175 million credit agreement due 2010 (a) $ -- $ -- $ --
6.25% senior notes due 2007 150,000 -- 150,000
7.75% senior notes due 2009 200,000 -- 200,000
7.50% senior notes due 2021 250,000 -- 250,000
Viking Gas Transmission:
Series A, B, C, and D senior notes due 2008 to 2014,
average 7.47% 29,520 2,133 27,387
Northern Border Partners:
$500 million credit agreement due 2010, average 4.29% (a) 204,000 -- 204,000
8.875% senior notes due 2010 250,000 -- 250,000
7.10% senior notes due 2011 225,000 -- 225,000
---------- ------ ----------
Total $1,308,520 $2,133 $1,306,387
========== ====== ==========
(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.
In May 2005, we entered into a $500 million five-year revolving credit agreement
with certain financial institutions. At our option, the interest rate on the
outstanding borrowings may be the lender's base rate or the London Interbank
26
Offered Rate (LIBOR) plus a spread that is based on our long-term unsecured debt
ratings. We are required to comply with certain financial, operational and
legal covenants, including the maintenance of EBITDA (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 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 that exceed $25 million in total purchase price, the allowable
ratio of debt to adjusted EBITDA is increased to 5.25 to 1 for two calendar
quarters following the acquisition. If we breach any of these covenants, amounts
outstanding may become due and payable immediately.
Also in May 2005, Northern Border Pipeline Company entered into a $175 million
five-year revolving credit agreement with certain financial institutions.
Similar to the Partnership's revolving credit agreement, Northern Border
Pipeline may select the lender's base rate or the LIBOR plus a spread that is
based on Northern Border Pipeline's long-term unsecured debt ratings as the
interest rate on the loan. Northern Border Pipeline is required to comply with
certain financial, operational and legal covenants, including the maintenance
of EBITDA to interest expense ratio of greater than 3 to 1 and debt to adjusted
EBITDA ratio of no more than 4.5 to 1. If Northern Border Pipeline consummates
one or more acquisitions that exceed $25 million in total purchase price, the
allowable ratio of debt to adjusted EBITDA is increased to 5 to 1 for two
calendar quarters following the acquisition. If Northern Border Pipeline
breaches any of these covenants, amounts outstanding may become due and payable
immediately.
As of September 30, 2005, the Partnership and Northern Border Pipeline were in
compliance with the covenants of their respective credit agreements.
During the fourth quarter of 2005 or early 2006, we anticipate issuing ten-year
fixed-rate senior notes to reduce amounts drawn under our $500 million revolving
credit agreement.
HEDGING ACTIVITIES
In December 2004, we entered into forward-starting interest rate swap agreements
with a total notional amount of $100 million in anticipation of a ten-year fixed
rate senior notes issuance. The forward-starting interest rate agreements
expired in late May and early June 2005, which resulted in the Partnership
paying $2.7 million to counterparties. In June 2005, we entered into a Treasury
lock interest rate agreement with a total notional amount of $200 million in
anticipation of a ten-year senior note issuance. In July 2005, we paid $0.1
million to the counterparty upon expiration of the June 2005 Treasury lock
interest rate agreement.
Our outstanding interest rate swap agreements with notional amounts totaling
$150 million expire in March 2011. Under these agreements, we make payments to
counterparties at variable rates based on LIBOR and receive payments based on a
7.10% fixed rate. As of September 30, 2005, the average effective interest rate
on our interest rate swap agreements was 6.56%.
OPERATING ACTIVITIES
Net cash provided by operating activities was $202.6 million for the nine months
ended September 30, 2005, compared with $192.0 million for the same period last
year. The $10.6 million increased cash flow was the result of increased net
income, which is discussed in the "Results of Operations" section of this
quarterly report. Other factors included a $2.9 million increase in
distributions received from unconsolidated affiliates related to payments
received for our Bighorn Gas Gathering preferred A cash flow incentives and
payments in 2004 to renew a right-of-way lease and other benefits of $5.5
million.
INVESTING ACTIVITIES
Net cash used in investing activities was $46.4 million for the nine months
ended September 30, 2005, compared with $16.3 million for the corresponding
period last year. The $30.1 million increase in cash used in investing
activities was primarily attributable to increased maintenance and growth
capital expenditures of $6.2 million and $15.5 million, respectively.
Investments in our unconsolidated affiliates increased $6.9 million, which
included the Crestone Energy Ventures acquisition of an additional 3.7% interest
in Fort Union Gas Gathering for $5.1 million and contributions made to Bighorn
Gas Gathering for its capital expenditures of $1.8 million for the nine months
ended September 30, 2005.
27
For the nine months ended September 30, 2005, the interstate natural gas
pipeline segment's capital expenditures were $22.7 million, which included
spending related to the Northern Border Pipeline Chicago III Expansion Project
of $4.3 million and Midwestern Gas Transmission's growth projects of $3.2
million. The remaining capital expenditures were primarily related to renewals
and replacements of existing facilities.
For the natural gas gathering and processing segment, capital expenditures were
$14.0 million for the nine months ended September 30, 2005, primarily related to
the expansions in the Williston Basin.
Total capital expenditures for 2005 are estimated to be approximately $85
million, which includes $49 million for the interstate natural gas pipeline
segment. Of the $49 million projected expenditures for the interstate natural
gas pipeline segment, approximately $14 million relates to the Northern Border
Pipeline Chicago III Expansion Project, $2 million relates to the Midwestern Gas
Transmission Eastern Extension Project and $3 million relates to the Midwestern
Gas Transmission Southbound Expansion Project. Capital expenditures for the
natural gas gathering and processing segment are estimated to be $30 million for
2005 primarily for growth capital expenditures. Funds required to meet our
capital expenditure requirements for 2005 are anticipated to be provided from
our credit facility and operating cash flow. Northern Border Pipeline currently
anticipates funding its capital expenditures for the remainder of 2005 primarily
by borrowing on its credit facility and using operating cash flow.
FINANCING ACTIVITIES
Net cash used in financing activities was $158.6 million for the nine months
ended September 30, 2005, compared with $171.3 million for the same period in
2004. Borrowings on long-term debt increased $14.0 million and debt repayments
decreased $38.8 million for the nine months ended September 30, 2005, compared
with the same period last year primarily due to the equity contribution of $39.0
million from minority interests received in 2004. Distributions to minority
interests decreased $3.0 million. Long-term financing costs and payments related
to the termination of derivatives increased $1.4 million and $2.8 million,
respectively, for the nine months ended September 30, 2005, compared with the
same period in 2004.
THE IMPACT OF ENRON'S CHAPTER 11 FILING ON OUR BUSINESS
In June 2005, Northern Border Pipeline, Crestone Gathering Services, a
wholly-owned subsidiary of Crestone Energy Ventures, and Bear Paw Energy
executed term sheets with a third party for the sale of their bankruptcy claims
held against Enron Corp. and Enron North America Corp. Proceeds from the sale of
the claims are expected to be $14.6 million, of which $14.0 million have been
received. In 2004, we adjusted our allowance for doubtful accounts to reflect an
estimated recovery of $3.4 million ($3.0 million, net to the Partnership) for
the claims. In the second quarter of 2005, we made an adjustment to our
allowance for doubtful accounts of $1.8 million ($1.6 million, net to the
Partnership) to reflect the agreements for the sale. In the third quarter of
2005, Northern Border Pipeline recognized revenue of $9.4 million ($6.6 million,
net to the Partnership) as a result of the sale.
For more information about the bankruptcy claims held by us against Enron and
Enron North America, please refer to "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Update on the Impact of Enron's
Chapter 11 Filing on our Business" in our annual report on Form 10-K for the
year ended December 31, 2004, and our quarterly reports on Form 10-Q for the
first and second quarters ended March 31, 2005, and June 30, 2005, respectively.
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
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 assumptions related thereto) 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 include the
following:
28
Interstate Natural Gas Pipeline Segment:
- the impact of uncontracted or discounted capacity on Northern Border
Pipeline being greater than expected;
- the ability to market pipeline capacity on favorable terms, which is
affected by:
- future demand for and prices of natural gas;
- competitive conditions in the overall natural gas and electricity
markets;
- availability of supplies of Canadian natural gas;
- availability of additional storage capacity;
- weather conditions; and
- competitive developments by Canadian and U.S. natural gas
transmission peers;
- performance of contractual obligations by the shippers;
- political and regulatory developments that impact FERC proceedings
involving interstate pipelines and the interstate pipelines' success
in sustaining their positions in such proceedings;
- the ability to recover costs in our rates;
- the timely receipt of approval by the FERC for construction and
operation of the Midwestern Gas Transmission Eastern Extension Project
and required regulatory clearances; our ability to acquire all
necessary rights-of-way and obtain agreements for interconnects in a
timely manner; our ability to promptly obtain all necessary materials
and supplies required for construction;
- orders by the FERC which are significantly different than our
assumptions related to the Northern Border Pipeline November 2005 rate
case;
Natural Gas Gathering and Processing Segment:
- the rate of development, well performance, gas quality and
competitive conditions in gas fields near our natural gas gathering
systems in the Powder River and Williston Basins and our investments
in the Powder River and Wind River Basins;
- prices of natural gas and natural gas liquids;
- the composition and quality of the natural gas we gather and process
in our plants;
- the efficiency of our plants in processing natural gas and extracting
natural gas liquids;
Coal Slurry Pipeline Segment:
- renewal of the coal slurry transportation contract under favorable
terms;
- the impact of a potential impairment charge;
General:
- developments in the December 2, 2001, filing by Enron of a voluntary
petition for bankruptcy protection under Chapter 11 of the United
States Bankruptcy Code affecting our settled claims;
- regulatory actions and receipt of expected regulatory clearances;
- actions by rating agencies;
- the ability to control operating costs;
- conditions in the capital markets and our ability to access the
capital markets;
- the risk inherent in the use of information systems in our business,
implementation of new software and hardware and the impact on the
timeliness of information for financial reporting; and
- acts of nature, sabotage, terrorism or other similar acts causing
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 future results.
These and other risks are described in greater detail in the section entitled
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Risk Factors and Information Regarding Forward-Looking Statements"
included in our annual report on Form 10-K for the year ended December 31, 2004.
All forward-looking statements attributable to us or persons acting on our
behalf are expressly qualified in their entirety by these factors. Other than as
required under the securities laws, we undertake no obligation to update
publicly any forward-looking statement whether as a result of new information,
subsequent events or changes in circumstances, expectations or otherwise.
29
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
OVERVIEW
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.
INTEREST RATE RISK
Our interest rate exposure is a result of variable rate borrowings. To reduce
our sensitivity to interest rate fluctuations, we may maintain a portion of our
consolidated debt portfolio in fixed-rate debt. We may also use interest rate
swap agreements to manage interest expense by converting a portion of fixed-rate
debt to variable-rate debt. As of September 30, 2005, we had $354 million of
variable-rate debt outstanding, $150 million of which we converted from
fixed-rate to variable-rate debt through interest rate swap agreements.
Approximately 73% of our debt portfolio was fixed-rate debt as of September 30,
2005.
To summarize the sensitivity of our variable rate borrowings to interest rate
fluctuations, if interest rates on average change by one percent from the rates
that were in effect as of September 30, 2005, our consolidated annual interest
expense would change by approximately $3.5 million.
COMMODITY PRICE RISK
Bear Paw Energy's natural gas gathering and processing operations are sensitive
to the price of natural gas and natural gas liquids because a significant
portion of its revenue is from the sale of commodities received through POP
agreements. As of September 30, 2005, approximately 77% of our projected natural
gas equity volume was hedged at a weighted average price of $7.15 per MMBtu and
65% of our projected natural gas liquids equity volume was hedged at a weighted
average price of $0.92 per gallon for the remainder of 2005. Net of hedging,
each $0.10 per MMBtu change in natural gas price will have an approximate $0.03
million impact to revenue for 2005, and each $0.01 per gallon change in natural
gas liquids price will have an approximate $0.04 million impact to revenue for
2005 based on hypothetical commodity prices of our projected gathering and
processing volumes for the remainder of 2005.
During the third quarter of 2005, Bear Paw Energy placed new hedges for 2006. As
of September 30, 2005, approximately 47% of our projected natural gas equity
volume was hedged at a weighted average price of $7.90 per MMBtu and 24% of our
projected natural gas liquids equity volume was hedged at a weighted average
price of $1.00 per gallon for 2006. Net of hedging, each $0.10 per MMBtu change
in natural gas price will have an approximate $0.2 million impact to revenue for
2006, and each $0.01 per gallon change in natural gas liquids price will have an
approximate $0.3 million impact to revenue for 2006 based on hypothetical
commodity prices of our projected gathering and processing volumes for 2006.
ITEM 4. CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
As of the end of the period covered by this report, our chief executive officer
and chief financial and accounting officer evaluated the effectiveness of our
disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e)
of the Securities Exchange Act of 1934, as amended. Based on their evaluation,
they concluded that as of September 30, 2005, our disclosure controls and
procedures were effective in ensuring that the information required to be
disclosed by us in the reports that we file or submit under the Securities
Exchange Act of 1934, as amended, is recorded, processed, summarized and
reported within the time periods specified in the Securities and Exchange
Commission's rules and forms.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There were no changes in our internal control over financial reporting during
the quarter ended September 30, 2005, that have materially affected or are
reasonably likely to materially affect our internal control over financial
reporting.
30
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Information concerning environmental claims and contingencies are set forth in
Note 6 of the Notes to Consolidated Financial Statements and such information is
incorporated herein by reference.
ITEM 6. EXHIBITS
The following exhibits are filed as part of this quarterly report on Form 10-Q:
+31.1 Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
+31.2 Rule 13a-14(a)/15d-14(a) Certification of Chief Financial and Accounting
Officer.
+32.1 Section 1350 Certification of Chief Executive Officer.
+32.2 Section 1350 Certification of Chief Financial and Accounting Officer.
- ----------
+ Filed herewith
31
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: November 7, 2005 By: /s/ Jerry L. Peters
-------------------------------------
Jerry L. Peters
Chief Financial and Accounting Officer
(Signing on behalf of the Registrant
and as Chief Financial and Accounting
Officer)
32
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
- ----------- -----------
+31.1 Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer
+31.2 Rule 13a-14(a)/15d-14(a) Certification of Chief Financial and
Accounting Officer
+32.1 Section 1350 Certification of Chief Executive Officer
+32.2 Section 1350 Certification of Chief Financial and Accounting
Officer
- ----------
+ Filed herewith
33