Spectra Energy Income Fund
TSX : SP.UN

Spectra Energy Income Fund

March 04, 2008 17:54 ET

Spectra Energy Income Fund Reports Fourth Quarter and Year End Results

CALGARY, ALBERTA--(Marketwire - March 4, 2008) - Spectra Energy Income Fund (TSX:SP.UN) (the "Fund") today released its financial and operating results for the three months and year ended December 31, 2007. Unless otherwise noted, the following references the results of Spectra Energy Facilities LP ("SEF LP"), of which the Fund currently has a 53.8 per cent indirect ownership.

Highlights:

- SEF LP's year-over-year operating revenue increased 31 percent or $31.6 million to $133.5 million in 2007 compared to 2006. Revenue for the fourth quarter was down 2 percent, or $0.6 million to $32.4 million compared to $33.0 million for the same period last year.

- For 2007, the Fund declared total distributions of $20.5 million from distributable cash of $25.2 million, for a payout ratio of 81 percent. The payout ratio for the fourth quarter was 96 percent.

- In 2007, the Fund initiated investments in excess of $40 million and completed three new projects (collectively, the "Expansion Facilities") in the Peace River Arch region, which included:

1) West Doe, a greenfield sour gas gathering and processing plant with a processing capacity of 24 mmcf/d located near the Fund's existing Pouce Coupe facility;

2) the Valhalla pipeline, a 25-kilometre sour gas gathering pipeline connected to the Gordondale East processing facility; and

3) the Valhalla Extension pipeline, a 17-kilometre, 8-inch sour gas gathering pipeline which extends the reach of the Valhalla pipeline.

- Subsequent to year-end, the Fund announced West Doe Phase II, an estimated $41 million expansion of the recently completed West Doe facility. The expansion involves increasing overall capacity at West Doe to 54 mmcf/d and includes a 50 percent ownership in a 58-kilometre gathering pipeline from the Sundown area of northeast B.C.

- The Fund is also planning a $4.2 million enhancement of the natural gas liquids recovery capabilities at the recently completed West Doe plant.

- Average daily throughputs for 2007 were up 24 percent to 564 mmcf/d compared to 454 mmcf/d in 2006. For the fourth quarter, throughputs were down 4 percent to 550 mmcf/d compared to the same period in 2006.

"We successfully executed on our business strategy and maintained a continued focus on organic growth, leading to strong financial and operational results in 2007," said Doug Haughey, president and chief executive officer of the Fund's manager. "Our solid performance was largely attributable to the full-year impact of the addition of our Fort St. John region and the addition of West Doe, Valhalla and Valhalla Extension projects. Producer activity in the Peace River Arch region remains strong and our new facilities in the area are serving growing customer gathering and processing requirements."

Financial and Operating Results:

SEF LP's revenue for the fourth quarter of 2007 was $32.4 million, a decrease of 2 percent or $0.6 million from the comparable quarter in 2006. Revenue increases due primarily to the addition of the Expansion Facilities and increased fees and facility usage at Brazeau River, were more than offset by revenue decreases in Pesh and Fort St. John resulting from decreased customer drilling and the impact of a positive equalization adjustment in the fourth quarter of 2006. Annual revenue for 2007 was $133.5 million, an increase of 31 percent or $31.7 million from the previous year. This year-over-year increase in annual revenue was largely due to full-year results from the Fort St. John region, increased throughputs from the Expansion Facilities and positive equalization adjustments. These increases were partially offset by scheduled plant turnarounds in 2007 and lower throughputs at Pesh due to decreased area drilling activity.

Earnings before interest, income taxes, depreciation and accretion (EBITDA) for the fourth quarter was $15.0 million, an increase of 5 percent, or $0.7 million, from the fourth quarter last year. EBITDA for 2007 was $60.7 million, an increase of 27 percent or $12.9 million from 2006. For the fourth quarter, the 2007 EBITDA increase was due primarily to lower operations and maintenance and general and administrative costs, partially offset by the lower revenues described previously. The $12.9 million EBITDA increase in 2007 was due to higher revenue in part offset by increased operation and maintenance and general and administrative costs due to the addition of the Fort St. John facilities and the costs associated with four scheduled plant turnarounds.

Net income for the fourth quarter of 2007 was $7.1 million, up 70 percent or $2.9 million from the same period a year earlier. Net income for 2007 was $23.2 million, up 29 percent or $5.2 million from 2006. The increase in quarterly net income is due primarily to a decrease in income tax expense due to income tax rate reductions and adjustments to tax pool balances in the fourth quarter of 2007, as well as the aforementioned revenue and operating expense variances. The increase in net income for 2007 was primarily due to higher operating income from the inclusion of the Fort St. John region for the entire year in 2007 compared with only three months in 2006 and lower income taxes in 2007 due to income tax rate reductions and adjustments to tax pool balances.

For the Fund, distributable cash for the fourth quarter of 2007 was $5.3 million and declared distributions were $0.210 per unit, totaling $5.1 million, for a payout ratio of 96 percent. For 2007, distributable cash was $25.2 million and declared distributions were $0.840 per unit, for total distributions of $20.5 million, resulting in a payout ratio of 81 percent.



--------------------------------------------------------------------------
(in thousands of dollars,
except where noted) Three Months Ended Year Ended
Statement of December 31 December 31
Distributable Cash 2007 2006 2007 2006
--------------------------------------------------------------------------
Spectra Energy Facilities LP
("SEF LP")
Cash flow from
operating activities 21,974 14,887 66,451 40,312
Changes in non-cash
working capital (2) (9,025) (2,437) (12,551) 2,112
Amortization of deferred
financing charges (2) (42) (48) (171) (191)
Maintenance capital
expenditures (2) (2,965) (2,003) (6,913) (2,985)
--------------------------------------------
Distributable Cash (1)
from SEF LP 9,942 10,399 46,816 39,248
--------------------------------------------
--------------------------------------------

Spectra Energy Income Fund
("SEIF")
Share of distributable cash
from SEF LP (3) 5,348 5,942 25,183 18,468
Interest income earned by
the Fund (4) 2 1 10 487
Management and administrative
expenses (4) - (13) 9 1
--------------------------------------------
Distributable Cash (1)
from SEIF (A) 5,350 5,930 25,202 18,956
--------------------------------------------
--------------------------------------------

Weighted average number of
units outstanding (units) 24,351,000 24,351,000 24,351,000 17,659,162
--------------------------------------------
Distributable Cash
($ / Unit) (1) 0.220 0.244 1.035 1.073
--------------------------------------------
Cash distributions declared
($ / Unit) 0.210 0.210 0.840 0.813
--------------------------------------------
Distributions
declared (B) (5) 5,114 5,114 20,455 15,599
--------------------------------------------
Payout Ratio (B / A) (1) 96% 86% 81% 82%
--------------------------------------------
--------------------------------------------------------------------------

(1) References to "Distributable Cash" are to cash available for
distribution to unitholders in accordance with the distribution
policies of the Fund. Distributable cash, distributable cash per unit
and payout ratio are non-GAAP measures generally used by Canadian
open-ended trusts as an indicator of financial performance. They are
considered key measures, as they demonstrate the cash available for
distribution to unit holders. The method of determining Distributable
Cash for the Partnership is derived from cash flow from operating
activities, a measure recognized under GAAP, and is equivalent to
EBITDA less net interest expense, current taxes and maintenance
capital expenditures for the period.

References to "EBITDA" are to earnings before interest, income taxes,
depreciation and accretion. EBITDA is a non-GAAP measure that
represents earnings generated to fund capital investments, meet
financial obligations and fund distributions. It is considered a key
measure, as it demonstrates the ability of the business to meet its
capital and financing commitments.

(2) Changes in non-cash working capital during the period are removed from
distributable cash as these changes are seen as temporary, and do not
represent a permanent change in the level in working capital.
Amortization of deferred financing charges is removed from
distributable cash because it is a non-cash item. Maintenance capital
expenditures are removed from distributable cash because these
expenditures are required to maintain the current level of productive
capacity of the revenue generating assets.

(3) The Fund does not actively operate a business and is dependent upon
distributions from the Partnership. Therefore, its distributable cash
is calculated as its share (based on equity ownership) of the
distributable cash generated by the Partnership.

(4) Interest income earned by the Fund is available for distribution to
unitholders, and is therefore included in distributable cash.
Management and administrative expenses are reimbursed by the
Partnership.

(5) The Partnership generally distributes less than the full amount of
distributable cash in order to fund a portion of its expansion capital
program with internally generated funds.


Proposed Royalty Framework:

In October 2007, the Alberta government announced its intention to revise the royalties payable for the extraction of oil and natural gas resources, effective January 1, 2009. While the impact of these changes is unknown at this time, their implementation could have an adverse effect on drilling activity and production in areas of Alberta where the Fund operates, and, as a result, on the demand for the Fund's services.

Conference Call and Webcast:

A conference call to discuss the financial results will take place at 7 a.m. MT (9:00 a.m. ET), Wednesday, March 5. The call will be hosted by Doug Haughey, president and ceo of the Fund's manager. Also participating in the call from the Fund's manager will be Tim Curry, vice president, finance and accounting; Duane Rae, vice president; and Bob Bissett, director, business development and investor relations. Following management's presentation, there will be a question and answer session for analysts and institutional investors.

To participate in the conference call, please dial 416-644-3420 or 1-800-731-6941. A webcast of the call will be available at www.spectraenergyfund.com. A replay of the conference call will be available as of 11 a.m. ET the same day until 12 a.m. on March 12, 2008. To access the replay, dial 416-640-1917 or 1-877-289-8525 followed by the passcode 21263269#.

Non-GAAP Measures:

The Fund provides financial measures that do not have a standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP). These non-GAAP measures may not be comparable to similar measures presented by other entities. All of the measures have been calculated consistent with previous disclosures by Spectra Energy LP.

Forward-Looking Statements:

This news release includes statements that do not directly or exclusively relate to historical facts, referred to as "forward-looking statements". You can typically identify forward-looking statements by the use of forward-looking words, such as "may", "will", "could", "should", "project", "believe", "anticipate", "expect", "estimate", "continue", "potential", "plan", "forecast" and other similar words. The forward-looking statements reflect management's current intentions, plans, expectations, beliefs and assumptions about future events, including the outlook for general economic trends, industry trends, commodity prices, capital markets, and the governmental, legal and regulatory environment. Forward-looking statements relate to, among other things, anticipated financial performance, business prospects, strategies, regulatory developments, new services, market forces, commitments and technological developments. These statements are subject to various known and unknown risks and uncertainties that are outside our control and could cause actual results to differ materially from the results expressed or implied by the forward-looking statements. Those risks and uncertainties include market and general economic conditions, future costs, treatment under government regulatory, tax and environmental regimes and the other material risks discussed in the Fund's Annual Information Form dated March 15, 2007, under "Risk Factors" and in the management's discussion and analysis of the Fund and Spectra Energy Facilities LP under the headings "Risk Profile" contained in the Fund's Annual Report for the year ended Dec. 31, 2006. Undue reliance should not be placed on this forward-looking information, which is given as of the date of this release, and the Fund undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise.

About Spectra Energy Income Fund

Spectra Energy Income Fund is an unincorporated open-ended trust established under the laws of the Province of Alberta and owns a 53.8 percent indirect interest in Spectra Energy Facilities LP ("SEF LP") which owns 100 per cent of Spectra Energy Midstream Corporation ("Spectra Midstream"). Spectra Energy indirectly owns the remaining 46.2 percent interest of SEF LP and is the sponsor of the Fund. Spectra Midstream is one of the largest independent midstream operations in the Western Canadian Sedimentary Basin ("WCSB") with interests in thirteen natural gas processing plants with a net processing capacity of 924 mmcf/d and over 1,600 kilometres of natural gas gathering pipelines located throughout natural gas prone areas in the western extent of the WCSB. More information on Spectra Energy Income Fund can be found at: http://www.spectraenergyfund.com.

Spectra Energy Corp. (NYSE:SE) is one of North America's premier natural gas infrastructure companies serving three key links in the natural gas value chain: gathering and processing, transmission and storage and distribution. For close to a century, Spectra Energy and its predecessor companies have developed critically important pipelines and related energy infrastructure connecting natural gas supply sources to premium markets. Based in Houston, Texas, the company operates in the United States and Canada approximately 18,000 miles of transmission pipeline, 265 billion cubic feet of storage, natural gas gathering and processing, natural gas liquids operations and local distribution assets. Spectra Energy Corp. also has a 50 percent ownership in DCP Midstream, one of the largest natural gas gatherers and processors in the United States. Visit www.spectraenergy.com for more information.

SPECTRA ENERGY INCOME FUND

and

SPECTRA ENERGY FACILITIES LP

Management Discussion and Analysis

And Consolidated Financial Statements

For the Year Ended December 31, 2007

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following management's discussion and analysis ("MD&A") of financial condition and results of operations is prepared as of March 4, 2008. This MD&A should be read together with the accompanying consolidated financial statements of Spectra Energy Income Fund (the "Fund") and Spectra Energy Facilities LP (the "Partnership") as at and for the year ended December 31, 2007 and the related notes thereto. The consolidated financial statements of the Fund and the Partnership are prepared in accordance with Canadian generally accepted accounting principles ("GAAP").

The selected financial information and discussion below also refers to certain measures to assist in assessing financial performance. These "non-GAAP measures" such as "EBITDA", "Distributable Cash", "Distributable Cash per unit", "Operating Cash Flow" and "Payout Ratio" should not be construed as alternatives to net income or loss or other comparable measures determined in accordance with GAAP as an indicator of performance or as a measure of liquidity and cash flow. Non-GAAP measures do not have standard meanings prescribed by GAAP and therefore may not be comparable to similar measures presented by other issuers.

Additional information relating to the Fund or the Partnership including the Annual Information Form ("AIF") is available on the Fund's profile on the System for Electronic Data Analysis and Retrieval ("SEDAR") website at www.sedar.com.

Forward-Looking Statements

This MD&A includes forward-looking statements. Forward-looking statements relate to, among other things, anticipated financial performance, business prospects, strategies, regulatory developments, new services, market forces, commitments and technological developments. Many of these statements can be identified by words such as "believe", "expects", "expected", "will", "intends", "projects", "anticipates", "estimates", "continues" or similar words. The Fund believes the expectations reflecting in such statements are reasonable but no assurance is given that such expectations will be correct. All forward-looking statements are based on the Fund's beliefs and assumptions based on information available at the time the assumption was made and on Management's experience and perception of historical trends, current conditions and expected further developments as well as other factors deemed appropriate in the circumstances. In addition to other assumptions made in this MD&A, assumptions have been made in respect of factors such as, but not limited to, the following:

- industry activity levels;

- commodity prices;

- the Fund's strategy;

- access to capital;

- capital expenditure estimates, plans, schedules and activities and the development, construction, operations and cost of facilities and infrastructure;

- operations and throughput levels;

- income tax considerations;

- regulatory regimes including environmental regulations;

- operating risks and related insurance coverage and inspection, turnaround and integrity systems;

- activities of the Manager;

- cash distributions; and

- competitive conditions.

By its nature, such forward-looking information is subject to various risks and uncertainties that are known and unknown, including those material risks discussed in the Fund's 2008 annual information form under "Risk Factors" and in this MD&A under the headings "Risk Profile" which could cause the Fund's actual results and experience to differ materially from the anticipated results or other expectations expressed. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this annual information form or otherwise, and the Fund undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise.

Overview

The Fund is an unincorporated open-ended trust created pursuant to a trust indenture dated November 2, 2005 as amended and restated on December 20, 2005, and governed by the laws of the Province of Alberta. The Fund is a "mutual fund trust" for the purposes of the Income Tax Act (Canada). The Fund is administered by Spectra Energy Facilities Management LP (the "Manager").

The Fund effectively commenced operations through its indirect investment in the Partnership on December 20, 2005, and income recorded by the Fund commenced on that date. The Fund now indirectly holds 53.8% of the Partnership and Spectra Energy Corp indirectly holds 46.2% of the Partnership.

The Partnership is a limited partnership established under the laws of the Province of Alberta. On December 20, 2005 it acquired all the issued and outstanding shares of Spectra Energy Midstream Corporation ("Spectra Midstream"). Spectra Midstream and its wholly owned subsidiaries own interests in thirteen natural gas processing plants and related gathering pipeline facilities in the Western Canadian Sedimentary Basin. The business of these facilities is referred herein to as Spectra Energy Midstream. Additional information relating to the business is available at www.spectraenergyfund.com.

Spectra Energy Midstream is in the business of processing natural gas and natural gas liquids in western Canada on a fee-for-service basis. Revenue generated is based solely on the volumes of energy processed and the fees levied for the various services offered. Spectra Energy Midstream has no direct exposure to commodity prices.

Spectra Energy Midstream has focused mainly on sour gas processing in the western extent of the Western Canadian Sedimentary Basin ("WCSB") for the following reasons:

- it has significant operating expertise in sour gas processing;

- due to increasing regulatory scrutiny, sour gas processing has high barriers to entry;

- sour gas processing commands higher margins; and

- management believes that demand for sour gas processing is growing in the WCSB.

Management estimates that approximately one-third of the natural gas production in the WCSB is sour gas, and management expects this percentage to continue to grow as producers increasingly focus on deeper drilling targets, which tend to have higher sour gas content. Many of these drilling targets are in areas where Spectra Energy Midstream's assets are located.

The Management of Spectra Energy Midstream will continue to investigate both organic expansion and acquisition opportunities. Growth focus will continue to be on sour gas opportunities with low-risk profiles and enhanced cash flow potential. During the period from 2002 through 2007, Spectra Energy Midstream spent approximately $270 million of capital to grow the business.

During 2007, the Partnership completed the construction of the Valhalla Pipeline Project ("Valhalla") in the Peace River Arch area of northwestern Alberta at a cost of $7.3 million. Operations for Valhalla, a 25 kilometer, 8 inch sour gas pipeline, commenced on April 12, 2007. Valhalla delivers gas for processing at the Gordondale East plant and is underpinned by firm take-or-pay contracts with area producers.

On November 2, 2007, the Partnership acquired, from area producers, the Valhalla Extension pipeline in the Peace River Arch area of northwest Alberta. The Valhalla Extension is a 17 kilometer, 8 inch sour gas gathering pipeline which extends the reach of the Valhalla pipeline. The $6.1 million Valhalla Extension delivers sour gas to the Valhalla Pipeline for transportation to the Gordondale East plant for processing and is underpinned by firm take-or-pay contracts.

During 2007, the Partnership completed the construction of a greenfield sour gas processing facility at West Doe, which is located in the Peace River Arch area of northeast British Columbia. This facility, which is located close to the existing Pouce Coupe plant, consists of a sour gas plant capable of processing 23.5 million cubic feet of gas per day and related gas gathering and sales gas pipelines. The final cost of this facility is estimated at $30.2 million, and is underpinned by firm take-or-pay contracts. Operations for this facility commenced on December 12, 2007.

Outlook

On December 20, 2007, the Trustees of Spectra Energy Commercial Trust (the "CT") approved the construction of an expansion to the recently completed West Doe facility, located in the Peace River Arch area of northeast British Columbia. The project will consist of a 30 million cubic feet per day ("mmcf/d") expansion of sour gas processing capability, increasing overall capacity at the West Doe facility to 53.5 mmcf/d. The project also includes a 50 per cent ownership interest in a 58 kilometre, 8 inch and 10 inch gathering pipeline from the Sundown area of northeast British Columbia. The approximately $41 million project is expected to be financed from cash from operations and credit facilities and is underpinned by firm take-or-pay contracts with area producers. The Sundown gathering pipeline is anticipated to commence deliveries to the existing West Doe plant during the second quarter of 2008. Expansion of the West Doe plant is expected to begin in the third quarter of 2008, with increased processing capacity available in the first quarter of 2009.

The CT Trustees approved on November 5, 2007, a new expansion project for an estimated capital expenditure of $4.2 million. This project, which is underpinned by a firm take-or-pay contract, is an enhancement of natural gas liquids recovery capabilities at the recently completed West Doe plant. This project is scheduled for completion in the first quarter of 2009.

On August 9, 2007, the CT Trustees, with those CT Trustees appointed by Westcoast Energy Inc. ("Westcoast") as the sponsor of the Fund abstaining, approved a financing arrangement with Westcoast whereby the Partnership will have access to a new credit facility in the amount of $200 million at a lower borrowing cost compared to its current bank credit facility. This arrangement will replace the Partnership's current bank credit facility and will provide the Partnership with access to adequate liquidity sources. Until this arrangement becomes effective, the Partnership will continue to have access to its current bank credit facility, as well as to an interim credit facility provided by Westcoast.

During the period 2004 through 2006, western Canada experienced historic levels of natural gas drilling activity. Beginning in late 2006, a reduction in western Canadian drilling has been occurring when compared to the levels generally experienced during the previous three years. Overall, exploration and development activity associated with the Fund's assets has been relatively steady with only the Pesh area experiencing a significant slow-down. On a longer-term basis, if drilling activity in the Fund's operating regions were to decrease from historical levels, the Fund's operating and financial results may be adversely impacted.

On October 25, 2007, the Premier of Alberta announced The New Royalty Framework which contemplates changes, effective January 1, 2009, to the current regime under which producers in the Province are charged royalties for the extraction of oil and gas resources. While the impact of these changes is unknown at this time, their implementation could have an adverse effect on drilling activity and production in areas of Alberta where the Fund operates and, as a result, on the demand for the Fund's services.

On February 19, 2008, the Province of British Columbia tabled a budget for 2008. One of the proposals in the budget is the introduction of a carbon tax on all fossil fuels. This tax is based on tones of carbon or carbon-associated emissions, and is planned to become effective July 1, 2008. The rate of tax will be phased in over a four year period. At this time, the potential impact, if any, to the Partnership's operations is not known.

On March 4, 2008 Spectra Energy Corp ("Spectra Energy") and Westcoast announced that an affiliate of Spectra Energy and Westcoast had entered into an agreement with the Fund to purchase (either by direct purchase or through a redemption by the Fund) all of the outstanding units of the Fund at a purchase price of $CDN 11.25 payable in cash. A special meeting of unitholders to consider the transaction is expected to be held in April, 2008. The closing of the transaction is subject to approval of at least a majority of the Fund's unitholders, other than Spectra Energy and its affiliates, and receipt of required regulatory approvals.

Spectra Energy Income Fund

Summarized Financial Results

The following table sets out summary consolidated financial information as at and for the years ended December 31, 2007 and 2006, and as at and for the twelve day period ended December 31, 2005.



---------------------------------------------------------------------------
(in thousands of dollars, except December 31 December 31 December 31
where noted) 2007 2006 2005
---------------------------------------------------------------------------

Statement of Operations
Equity income from Spectra Energy
Facilities LP 12,533 8,451 151
Net income and comprehensive income 3,369 8,939 141
Net income per unit (in dollars) 0.138 0.506 0.010

Distributions
Units outstanding at end of period
(in units) 24,351,000 24,351,000 14,000,000
Distributions declared per unit
(in dollars) 0.840 0.813 0.026

Balance Sheet
Total assets 249,923 258,236 143,575
Total liabilities 11,137 2,364 3,798
---------------------------------------------------------------------------


Quarterly Information

The following table sets forth selected consolidated financial information for each of the eight most recently completed quarters.



--------------------------------------------------------------------------
(in thousands
of dollars,
except where 2007 2006
noted) Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
--------------------------------------------------------------------------
Revenues 4,136 1,385 4,364 4,391 3,004 2,526 2,372 2,323
Expenses 843 (212)(11,071) (467) (425) (320) (337) (204)
--------------------------------------------------------------------------
Net income
(loss) and
comprehensive
income
(loss) 4,979 1,173 (6,707) 3,924 2,579 2,206 2,035 2,119
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Earnings
(loss) per
unit, basic
and diluted
(in
dollars) 0.204 0.048 (0.275) 0.161 0.106 0.142 0.132 0.139
Cash
distributions
declared
(1) 5,114 5,113 5,114 5,114 5,114 4,294 3,095 3,096
Cash
distributions
declared per
unit
(in
dollars) 0.210 0.210 0.210 0.210 0.210 0.201 0.201 0.201
--------------------------------------------------------------------------
(1) Includes $600 thousand distribution to Subscription Receipt holders in
third quarter of 2006.


Results of Operations

The following table presents the consolidated operating results for the three months and year ended December 31, 2007 and 2006.



--------------------------------------------------------------------------
Three months ended Year ended
December 31 December 31
(in thousands of dollars) 2007 2006 2007 2006
--------------------------------------------------------------------------
Equity income from Spectra
Energy Facilities LP 3,827 2,591 12,533 8,451
Other income 307 412 1,733 1,287
Interest income 2 1 10 487
Management and
administrative expenses (307) (425) (1,724) (1,286)
Future income taxes 1,150 - (9,183) -
------------------------------------------
Net income and
comprehensive income 4,979 2,579 3,369 8,939
--------------------------------------------------------------------------


Equity income represents the 53.80% (42.41% prior to September, 2006) indirect investment in the Partnership as well as a 100% indirect investment in the General Partner ("GP"), Spectra Energy Facilities Inc. The Partnership reimburses the Fund for all of its management and administrative expenses per the administration and governance agreement. This reimbursement is described as other income.

Liquidity and Capital Resources

The Fund does not actively operate a business and is dependent upon distributions from the Partnership. During the fourth quarter of 2007, the Fund received $5,114 thousand of distributions from the Partnership (year ended December 31, 2007: $20,455 thousand), a decrease of $41 thousand over the comparable period in 2006 (increase for the year ended December 31, 2007: $6,682 thousand). The Fund paid distributions to unitholders of $5,114 thousand during the fourth quarter of 2007 (year ended December 31, 2007: $20,455 thousand), an increase of $74 thousand over the comparable period in 2006 (increase for the year ended December 31, 2007: $6,197 thousand). The increases in distributions received and paid during year ended December 31, 2007 as compared to the same periods in 2006 were due to the increased number of Units outstanding for the entire year, as well as the increase in the per unit amount of distributions declared, effective with the November, 2006 distribution. The Partnership's cash flow from operations, before changes in non-cash working capital, of $12,949 thousand (consisting of net cash provided by operating activities of $21,974 thousand less net working capital changes other than cash and short term investments of $9,025 thousand) for the fourth quarter of 2007, and $53,900 thousand (consisting of net cash provided by operating activities of $66,451 thousand less net working capital changes other than cash and short term investments of $12,551 thousand) for the year ended December 31, 2007, was sufficient to fund all the distributions made to the Fund and other partners. No borrowings were required by the Fund or the Partnership to support the distributions made to unitholders. Management expects that cash flows from the operations of the Partnership will continue to be sufficient to fund distributions to the Fund and other partners.

The Dominion Bond Rating Service ("DBRS") has assigned a rating of STA-3 (middle) to the Units. Income funds rated at STA-3 are considered by DBRS to have good stability and sustainability of distributions per unit but performance may be more sensitive to economic factors, have greater cyclical tendencies, and may not be as well diversified as an income fund with a STA-2 rating, resulting in some potential for distributions per unit to fluctuate.

Distributions

The following table sets out the distributions for the periods ended December 31, 2007 and 2006.



--------------------------------------------------------------------------
(in thousand of dollars,
except where noted) Three Months Ended Year Ended
Statement of Distributable December 31 December 31
Cash 2007 2006 2007 2006
--------------------------------------------------------------------------
Spectra Energy Facilities
LP ("SEF LP")
Cash flow from operating
activities 21,974 14,887 66,451 40,312
Changes in non-cash
working capital(2) (9,025) (2,437) (12,551) 2,112
Amortization of deferred
financing charges(2) (42) (48) (171) (191)
Maintenance capital
expenditures(2) (2,965) (2,003) (6,913) (2,985)
---------- ---------- ---------- ----------
Distributable Cash(1)
from SEF LP 9,942 10,399 46,816 39,248
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------

Spectra Energy Income Fund
("SEIF")
Share of distributable cash
from SEF LP(3) 5,348 5,942 25,183 18,468
Interest income earned by
the Fund(4) 2 1 10 487
Management and
administrative expenses(4) - (13) 9 1
---------- ---------- ---------- ----------
Distributable Cash(1) from
SEIF (A) 5,350 5,930 25,202 18,956
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
Weighted average number
of units outstanding
(units) 24,351,000 24,351,000 24,351,000 17,659,162
---------- ---------- ---------- ----------
Distributable Cash
($/Unit)(1) 0.220 0.244 1.035 1.073
---------- ---------- ---------- ----------
Cash distributions
declared ($/Unit) 0.210 0.210 0.840 0.813
---------- ---------- ---------- ----------
Distributions
declared (B)(5) 5,114 5,114 20,455 15,599
---------- ---------- ---------- ----------
Payout Ratio (B/A)(1) 96% 86% 81% 82%
---------- ---------- ---------- ----------
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(1) References to "Distributable Cash" are to cash available for
distribution to unitholders in accordance with the distribution
policies of the Fund. Distributable cash, distributable cash per unit
and payout ratio are non-GAAP measures generally used by Canadian
open-ended trusts as an indicator of financial performance. They are
considered key measures, as they demonstrate the cash available for
distribution to unit holders. The method of determining Distributable
Cash for the Partnership is derived from cash flow from operating
activities, a measure recognized under GAAP, and is equivalent to
EBITDA less net interest expense, current taxes and maintenance
capital expenditures for the period.

References to "EBITDA" are to earnings before interest, income taxes,
depreciation and accretion. EBITDA is a non-GAAP measure that
represents earnings generated to fund capital investments, meet
financial obligations and fund distributions. It is considered a key
measure, as it demonstrates the ability of the business to meet its
capital and financing commitments.

(2) Changes in non-cash working capital during the period are removed from
distributable cash as these changes are seen as temporary, and do not
represent a permanent change in the level in working capital.
Amortization of deferred financing charges is removed from
distributable cash because it is a non-cash item. Maintenance capital
expenditures are removed from distributable cash because these
expenditures are required to maintain the current level of productive
capacity of the revenue generating assets.

(3) The Fund does not actively operate a business and is dependent upon
distributions from the Partnership. Therefore, its distributable cash
is calculated as its share (based on equity ownership) of the
distributable cash generated by the Partnership.

(4) Interest income earned by the Fund is available for distribution to
unitholders, and is therefore included in distributable cash.
Management and administrative expenses are reimbursed by the
Partnership.

(5) The Partnership generally distributes less than the full amount of
distributable cash in order to fund a portion of its expansion capital
program with internally generated funds.


The following table shows the relationship between cash flows from operating activities and net income, and historical distributed cash amounts for the Partnership.



--------------------------------------------------------------------------
Three 12 Day
Months Year Year Period
Ended Ended Ended Ended
December 31 December 31
(in thousand of dollars) 2007 2007 2006 2005
--------------------------------------------------------------------------
Spectra Energy Facilities LP
Cash flow from operating
activities (A) 21,974 66,451 40,312 3,048
-----------------------------------------------
Net income (B) 7,112 23,239 18,024 376
-----------------------------------------------
Actual cash distributions
paid or payable relating
to the period (C) 9,506 38,026 32,119 908
-----------------------------------------------
--------------------------------------------------------------------------

--------------------------------------------------------------------------
Excess of cash flows from
operating activities over
cash distributions paid
(A)-(C) 12,468 28,425 8,193 2,140
-----------------------------------------------
-----------------------------------------------
(Shortfall) of net income
over cash distributions
paid (B)-(C)(1) (2,394) (14,787) (14,095) (532)
-----------------------------------------------
-----------------------------------------------
--------------------------------------------------------------------------

(1) It has been the expectation of management of the Partnership from the
date of inception on December 20, 2005 that distributions to
unitholders could exceed net income due to the fact that net income
contains major non-cash deductions, such as depreciation and
amortization. There is no plan to change the current level of
distributions at this time. The Partnership does not consider the
distributions in excess of net income to be an economic return of
capital because distributions are generally made using incremental
cash from operations.


Income Taxes

The Fund is a mutual fund trust for income tax purposes. As such, the Fund is only taxable on any amount not allocated to unitholders. The Fund intends to distribute substantially all of its taxable income to its unitholders and to comply with the provisions of the Income Tax Act (Canada) that permit, among other items, the deduction of distributions to unitholders from the Fund's taxable income until 2011.

On June 22, 2007, the Parliament of Canada passed into law Bill C-52, an Act to implement certain provisions of the federal budget tabled in Parliament on March 19, 2007, which included legislation to implement the proposal announced by the Minister of Finance on October 31, 2006 to tax certain publicly traded trusts and partnerships on the taxable portion of their distributions. As a result of the enactment of Bill C-52, commencing January 1, 2011 (subject to the qualification below regarding the possible loss of the four year grandfathering period in the case of "undue expansion"), the Fund will not be entitled to deduct certain of its distributed income (referred to as specified income) and the Fund will be subject to a distribution tax on the specified income at a special rate estimated to be 29.5% in 2011and 28.0% thereafter.

As a result of the new tax legislation, future income tax liabilities for the year ended December 31, 2007 increased by $9,183 thousand. This is a reduction of $1,150 thousand from the amount estimated at September 30, 2007 due to a reduction in future distribution tax rates from 31.5% to 28% after 2011. Until June 2007, the Fund had been tax effecting the reversal of taxable temporary differences at a nil tax rate on the assumption that the Fund would make sufficient tax deductible cash distributions to unitholders, such that the Fund's taxable income would be nil for the foreseeable future. The Fund has estimated its future income taxes based on its best estimates of results of operations and tax pool claims and cash distributions in the future, assuming no material change to the Fund's current organizational structure. As currently interpreted, Canadian GAAP does not permit the Fund's estimate of future income taxes to incorporate any assumptions related to a change in organizational structure until such structures are given legal effect. The Fund's estimate of its future income taxes will vary as do the Fund's assumptions pertaining to the factors described above, and such variations may be material.

The Fund may be subject to this distribution tax in respect of a taxation year of the Fund commencing earlier than January 1, 2011 if, prior to such date, the Fund engages in "undue expansion" as set out in the guidelines released by the Department of Finance on December 15, 2006 and which was incorporated by reference in Bill C-52.

The enactment of new rules in respect of the taxation of specified income could have an adverse effect on the Fund, the amount of its distributions and the market value of its units.

Related Party Transactions

Spectra Energy Facilities Management LP as administrator of the Fund, the manager of the CT and the Partnership, receives a base fee, an incentive fee, and reimbursement of costs for its services per the management agreement and the administration and governance agreement. During the three months ended December 31, 2007, these amounts were $128 thousand (2006 - $155 thousand), and for the year ended December 31, 2007, these amounts were $512 thousand (2006 - $296 thousand). Accounts payable represents the unpaid portion of these fees, as well as amounts owing to various related parties for expenses paid on behalf of the Fund. The amount payable for these fees and advances at December 31, 2006 has been repaid.

The Partnership reimburses the Fund for all of its management and administrative expenses per the administration and governance agreement, and this reimbursement is described as other income in the consolidated statements of operations and net accumulated deficit. The unpaid portion of these reimbursed expenses at December 31, 2007 has been netted against the amounts payable by the Fund to the Partnership for advances received from the Partnership, and has been included as part of accounts receivable. The amount receivable for these reimbursed expenses at December 31, 2006 has been received.

Outstanding Securities of the Fund

The beneficial interests in the Fund are represented and constituted by two classes of units described and designated as Units and Special Voting Units. An unlimited number of the Units and Special Voting Units may be issued pursuant to the trust indenture of the Fund dated November 2, 2005, as amended on December 20, 2005 (the "Fund Trust Indenture"). The Fund may also issue an unlimited number of Other Fund Securities (as defined in the Fund Trust Indenture). As at March 4, 2008, there were 24,351,000 Units and 20,913,750 Special Voting Units outstanding.

Each Unit represents an equal, undivided beneficial interest in the Fund property and ranks equally with all of the other Units without discrimination, preference or priority. Each Unit entitles the holder to one vote at all meetings of holders of Units. Except for the right to attend and vote at meetings of holders of Units or in respect of written resolutions of holders of Units, Special Voting Units do not confer upon the holders thereof any other rights. Each Special Voting Unit entitles the holder to a number of votes at all meetings of trust unitholders or in respect of any written resolution of trust unitholders equal to the number of Units into which the Exchangeable Securities ("Exchangeable LP Units") to which such Special Voting Units relate are, directly or indirectly, exchangeable, exercisable or convertible. The Exchangeable LP Units, issued by the Partnership, are exchangeable for Units on the basis of one Unit for each Exchangeable LP Unit. The holder of an Exchangeable LP Unit may initiate the exchange procedure at any time by delivering to the GP, as exchange agent, a unit certificate in respect of that portion of its Exchangeable LP Units to be exchanged.

Risk Profile

The Fund's AIF for the year ended December 31, 2007 contains a thorough description of the business and other risk factors and should be read in conjunction herewith. Additional information relating to the Fund, including the Fund's AIF is available on SEDAR at www.sedar.com.

The Fund is entirely dependent on distributions from the Partnership to make its own distributions to unitholders. Any decrease in the cash generated by the Partnership or any requirements for the Partnership to retain cash for capital or other expenditures will reduce the cash distributions made by the Partnership to the Fund and as a result will decrease the distributions to unitholders.

Spectra Energy Facilities LP

Summarized Financial Results

The following table sets out summary consolidated financial information as at and for the three years ended December 31, 2007, 2006, and 2005.



---------------------------------------------------------------------------
(in thousands of dollars, except
where noted)
Years ended December 31 2007 2006 2005
---------------------------------------------------------------------------

Statement of Operations
Total revenue 133,496 101,845 81,934
Net income 23,239 18,024 3,048

Distributions
Units outstanding at end of period
(in units) 45,264,750 45,264,750 34,913,750
Distribution per Exchangeable LP
unit (in dollars) 0.840 0.813 0.026
Distribution per Ordinary LP unit
(in dollars) 0.840 0.813 0.026

Balance Sheet
Total assets 641,133 635,350 473,992
Long-term liabilities 203,425 194,549 127,405
---------------------------------------------------------------------------


Net income during 2007 was $23,239 thousand, up $5,215 thousand compared to 2006 primarily as a result of higher operating income from the inclusion of the Fort St. John region (the former Westcoast Gas Services Inc. assets) for the entire year in 2007 compared with only three months in 2006, increased revenue from the addition of the Valhalla pipelines, and lower income taxes, partially offset by more plant turnarounds in 2007, asset impairment provisions for the Boundary Lake and Sunrise facilities, and higher interest expense due to a higher average debt balance and a higher interest rate.

Net income during 2006 was $18,024 thousand, up $14,976 thousand compared to 2005 primarily as a result of higher operating income from the acquisition of Westcoast Gas Services Inc. ("WGSI") at the end of the third quarter, increased plant throughput, and fewer plant turnarounds in 2006, as well as lower interest expense due to a lower average debt balance and a lower interest rate.

Total assets increased in 2006 compared to 2005 due primarily to the acquisition of WGSI on September 29, 2006.

Long term liabilities increased in 2007 compared to 2006 due primarily to the debt financing for the construction of the West Doe facility and the Valhalla pipeline, as well as the acquisition of the Valhalla pipeline extension.

Long term liabilities increased in 2006 compared to 2005 due primarily to the debt financing for the acquisition of WGSI on September 29, 2006, as well as future income tax liabilities assumed upon the acquisition of WGSI.

Quarterly Information

The following table sets forth selected consolidated financial information for each of the eight most recently completed quarters. These results include the operations of the Fort St. John region subsequent to the closing of the acquisition of WGSI on September 29, 2006.



--------------------------------------------------------------------------
(in thousands 2007 2006
of dollars) Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
--------------------------------------------------------------------------
Revenues 32,380 33,817 33,298 34,001 32,989 22,862 22,754 23,240
Expenses (25,268)(32,242)(25,964)(26,783)(28,806)(18,792)(17,980)(18,243)
--------------------------------------------------------------------------
Net income
and
comprehensive
income 7,112 1,575 7,334 7,218 4,183 4,070 4,774 4,997
--------------------------------------------------------------------------
--------------------------------------------------------------------------


Quarterly results are impacted primarily by the timing and level of costs associated with plant turnarounds (where a facility is taken out of service for a period of time to undergo inspections and maintenance), throughput volumes and plant and gathering system expansions.

Revenues and expenses during the fourth quarter of 2006 increased by $10,127 thousand and $10,014 thousand, respectively, compared to the third quarter of 2006 due primarily to the acquisition of the Fort St. John region facilities.

Results of Operations

The following tables present the consolidated operating results for the three months and years ended December 31, 2007 and 2006.



--------------------------------------------------------------------------
Three months ended December 31
(in thousands of dollars) 2007 2006 Variance
--------------------------------------------------------------------------
Operating revenues 32,380 32,989 (609)
Operating expenses (26,257) (26,360) 103
Net interest expense and other income (2,051) (1,811) (240)
Income taxes 3,040 (635) 3,675
---------- ---------- ----------
Net income and comprehensive income 7,112 4,183 2,929
---------- ---------- ----------
---------- ---------- ----------
--------------------------------------------------------------------------

--------------------------------------------------------------------------
Year ended December 31
(in thousands of dollars) 2007 2006 Variance
--------------------------------------------------------------------------
Operating revenues 133,496 101,845 31,651
Operating expenses (104,725) (76,247) (28,478)
Net interest expense and other income (6,988) (5,573) (1,415)
Income taxes 1,456 (2,001) 3,457
---------- ---------- ----------
Net income and comprehensive income 23,239 18,024 5,215
---------- ---------- ----------
---------- ---------- ----------
--------------------------------------------------------------------------


For the Three Months Ended December 31, 2007 compared to the Three Months Ended December 31, 2006

Operating Revenues

During the three months ended December 31, 2007, operating revenues decreased by $609 thousand compared to the same period in 2006, to a total of $32,380 thousand, due primarily to:

- Revenue decreased in the Pesh Complex region by $1,550 thousand due mainly to lower gathering and processing volumes resulting from decreased area drilling activity.

- Revenue decreased in the Nevis region by $397 thousand due mainly to a positive equalization adjustment in 2006.

- Revenue decreased in the Fort St. John region by $333 thousand due mainly to lower gathering and processing volumes resulting from decreased area drilling activity by existing customers.

- Revenue increased in the Brazeau River region by $608 thousand due mainly to higher average fees from increased volumes of sour gas processed, increased operating cost recoveries, and increased usage by customers of the Partnership's compression facilities, partially offset by a negative equalization adjustment.

- Revenue increased in the Peace River Arch region by $1,063 thousand due mainly to increased production on stream from the addition of the Valhalla pipeline, the Valhalla Extension pipeline, and the West Doe plant, partially offset by lower revenue due to lower production volumes from reduced area activity around Fourth Creek.

Operating Expenses

Operating expenses decreased by $103 thousand for the three months ended December 31, 2007 compared to the same period in 2006, to a total of $26,257 thousand, due primarily to:

Operations and Maintenance

Operations and maintenance expenses were $14,928 thousand for the three months ended December 31, 2007, a decrease of $569 thousand compared to the same period in 2006. This was due largely to lower utilities costs of approximately $1,400 thousand at the Brazeau River plant, higher maintenance costs of approximately $500 thousand in the Fort St. John region in 2006, partially offset by an equalization payment of approximately $500 thousand at the Brazeau River plant, higher labour, environmental and utilities costs of approximately $500 thousand in the Nevis region, and pipeline integrity work of approximately $400 thousand in the Brazeau River region.

Depreciation

Depreciation expense was $7,486 thousand for the three months ended December 31, 2007, an increase of $97 thousand compared to the same period in 2006, due primarily to the inclusion of the Valhalla Pipeline and the Valhalla Extension pipeline.

General and Administrative

General and administrative expenses were $2,494 thousand for the three months ended December 31, 2007, a decrease of $724 thousand compared to the same period in 2006, due primarily to timing of costs for services provided by affiliated companies, and a decrease in bad debts, partially offset by higher employee incentive pay, reimbursable to the Manager, for favourable 2007 results.

Asset Impairment

During 2007 continued declines in gas volumes processed at the Boundary Lake Plant, in which the Partnership owns a 50% interest, and the resultant decline in revenues, triggered an impairment review of that facility. As a result of the review, a pre-tax impairment provision of $283 thousand was recorded in the fourth quarter of 2007, representing the excess of the carrying amount of the facility over its fair value. Fair value was determined based on the present value of estimated future cash flows from net operating revenue generated by the facility.

During 2007, it was determined that compression facilities were no longer required to support production at the Sunrise facility. This caused an impairment review of the assets at this location. As a result of the review, a pre-tax impairment provision of $803 thousand was recorded in the fourth quarter of 2007, representing the excess of the carrying amount of the facility over its fair value. Fair value was determined based on the present value of estimated future cash flows from net operating revenue generated by the facility.

Net Interest Expense and Other Income

Net interest and other income totaled $2,051 thousand for the three months ended December 31, 2007, an increase of $240 thousand compared to the same period in 2006, due primarily to a higher average debt balance and a higher interest rate.

Income Taxes

Partnership earnings are taxed at the partner level rather than at the Partnership financial statement reporting level. The Partnership reports only corporate income tax related to corporate entities included in the Partnership's consolidated financial statements.

An income tax recovery of $3,040 thousand was recorded for the three months ended December 31, 2007, a decrease in expense of $3,675 thousand compared to the same period in 2006. The decrease in expense is attributable to income tax rate reductions and adjustments to tax pool balances, partially offset by higher income tax expense associated with increased current period earnings related to corporate entities included in the Partnership's consolidated financial statements.

For the Year Ended December 31, 2007 compared to the Year Ended December 31, 2006

Operating Revenues

During the year ended December 31, 2007, operating revenues increased by $31,651 thousand compared to 2006, to a total of $133,496 thousand, due primarily to:

- Revenue attributable to the Fort St. John region increased by $27,104 thousand due to its inclusion for the entire year ended December 31, 2007 as compared to only three months and two days included in the year ended December 31, 2006 following the closing of the acquisition of WGSI on September 29, 2006.

- Revenue increased in the Brazeau River region by $4,454 thousand due mainly to higher positive equalization adjustments of approximately $1,200 thousand, and higher average fees as a result of increased operating cost recoveries, higher average fees from increased volumes of sour gas processed, higher gathering revenues and increased usage by customers of the Partnership's compression facilities, partially offset by lower revenue due to a plant turnaround in 2007.

- Revenue increased in the Peace River Arch region by $2,567 thousand due mainly to increased production on stream from the addition of the Valhalla pipeline, the Valhalla Extension pipeline, and the West Doe plant, and increased throughputs at the Pouce Coupe plant due to an expansion of capacity in late 2006, partially offset by lower revenue due to turnarounds at the Pouce Coupe, Gordondale East and Fourth Creek plants in 2007.

- Revenue increased in the Nevis region by $1,323 thousand due mainly to higher positive equalization adjustments in 2007 of approximately $500 thousand, with the balance of the increase due mainly to higher plant throughput in 2007.

- Revenue decreased in the Pesh Complex region by $3,797 thousand due mainly to lower gathering and processing volumes resulting from decreased area drilling activity.

Operating Expenses

Operating expenses increased by $28,478 thousand for the year ended December 31, 2007 compared to 2006, to a total of $104,725 thousand, due primarily to:

Operations and Maintenance

Operations and maintenance expenses were $60,380 thousand for the year ended December 31, 2007, an increase of $16,278 thousand compared to 2006. This was due largely to the addition of the Fort St. John facilities, accounting for approximately $14,900 thousand, higher maintenance costs of approximately $3,400 thousand for plant turnarounds at Pouce Coupe, Brazeau River, Fourth Creek, and Gordondale East, higher equalization payments of approximately $1,000 thousand at the Brazeau River plant, and higher labour, environmental and utilities costs of approximately $500 thousand in the Nevis region, partially offset by lower utilities costs of approximately $1,400 thousand at the Brazeau River plant, lower maintenance costs at the Pesh Complex in 2007 of approximately $1,200 thousand due mainly to a cost reduction plan implemented as a result of lower processing volumes, and higher maintenance costs at the Pesh Complex in 2006 of approximately $500 thousand related to plant turnarounds.

Depreciation

Depreciation expense was $29,808 thousand for the year ended December 31, 2007, an increase of $8,571 thousand compared to 2006, due primarily to the inclusion of the Fort St. John facilities for the entire year in 2007 as compared to only three months and two days in 2006.

General and Administrative

General and administrative expenses were $12,399 thousand for the year ended December 31, 2007, an increase of $2,517 thousand compared to 2006, due primarily to the inclusion of the Fort St. John facilities for the entire year, an increase in services provided by affiliated companies in 2007, higher employee incentive pay, reimbursable to the Manager, for favourable 2007 results, and an adjustment to employee incentive pay, reimbursable to the Manager, for favourable 2006 results, partially offset by a decrease in bad debts.

Asset Impairment

During 2007 continued declines in gas volumes processed at the Boundary Lake Plant, in which the Partnership owns a 50% interest, and the resultant decline in revenues, triggered an impairment review of that facility. As a result of the review, a pre-tax impairment provision of $283 thousand was recorded in 2007, representing the excess of the carrying amount of the facility over its fair value. Fair value was determined based on the present value of estimated future cash flows from net operating revenue generated by the facility.

During 2007, it was determined that compression facilities were no longer required to support production at the Sunrise facility. This caused an impairment review of the assets at this location. As a result of the review, a pre-tax impairment provision of $803 thousand was recorded in 2007, representing the excess of the carrying amount of the facility over its fair value. Fair value was determined based on the present value of estimated future cash flows from net operating revenue generated by the facility.

Net Interest Expense and Other Income

Net interest and other income totaled $6,988 thousand for the year ended December 31, 2007, an increase of $1,415 thousand compared to 2006, due primarily to a higher average debt balance and a higher interest rate.

Income Taxes

Partnership earnings are taxed at the partner level rather than at the Partnership financial statement reporting level. The Partnership reports only corporate income tax related to corporate entities included in the Partnership's consolidated financial statements.

An income tax recovery of $1,456 thousand was recorded for the year ended December 31, 2007, a decrease in expense of $3,457 thousand compared to the same period in 2006. The decrease in expense is attributable to income tax rate reductions and adjustments to tax pool balances, partially offset by higher income tax expense associated with increased current period earnings related to corporate entities included in the Partnership's consolidated financial statements.

Cash Flow, Liquidity and Capital Resources

Cash flow from operating activities provides the primary source of funds to finance operating needs, expansion projects and capital expenditures. In addition, the Partnership may supplement cash from operating activities with borrowings as needed based on management's evaluation of the capital structure.

On December 20, 2005, the Partnership entered into a credit facility with a syndicate of financial institutions (the "Credit Facility"). The Credit Facility contains restrictive covenants that limit the discretion of management with respect to certain business matters. These covenants place restrictions on, among other things, the Partnership's ability to incur additional indebtedness, to create liens or other encumbrances, to pay dividends or make certain other payments, investments, loans and guarantees and to sell or otherwise dispose of assets and merge or consolidate with another entity. In addition, the Credit Facility contains financial covenants that require the Partnership to meet certain financial ratios and financial condition tests. A failure to comply with the obligations in the Credit Facility could result in an event of default which, if not cured or waived, could permit acceleration of the relevant indebtedness and may limit the Fund's ability to make distributions. The Partnership was in full compliance with all covenants of the Credit Facility as at December 31, 2007.

On August 9, 2007, the CT Trustees, with those CT Trustees appointed by Westcoast as the sponsor of the Fund abstaining, approved a financing arrangement with Westcoast whereby the Partnership will have access to a new credit facility in the amount of $200 million at a lower borrowing cost compared to its current bank credit facility. This arrangement will replace the Partnership's current bank credit facility and will provide the Partnership with access to adequate liquidity sources. Until this arrangement becomes effective, the Partnership will continue to have access to its current bank credit facility, as well as to an interim credit facility provided by Westcoast.

The following tables set out the comparison of cash flows for the three months and years ended December 31, 2007 and 2006.



--------------------------------------------------------------------------
Three months ended December 31
(in thousands of dollars) 2007 2006 Variance
--------------------------------------------------------------------------
Cash provided by operating activities 21,974 14,887 7,087
Cash used in investing activities (21,373) (2,912) (18,461)
Cash used in financing activities (3,475) (9,503) 6,028
---------- ---------- ----------
Net (decrease) increase in cash and
short term investments (2,874) 2,472 (5,346)
---------- ---------- ----------
---------- ---------- ----------
--------------------------------------------------------------------------

--------------------------------------------------------------------------
Year ended December 31
(in thousands of dollars) 2007 2006 Variance
--------------------------------------------------------------------------
Cash provided by operating activities 66,451 40,312 26,139
Cash used in investing activities (40,730) (147,304) 106,574
Cash (used in) provided by financing
activities (26,995) 108,508 (135,503)
---------- ---------- ----------
Net (decrease) increase in cash and
short term investments (1,274) 1,516 (2,790)
---------- ---------- ----------
---------- ---------- ----------
--------------------------------------------------------------------------


Cash Provided by Operating Activities

Cash from operating activities was generated primarily from fees charged for the gathering, processing and transportation of natural gas and natural gas liquids fractionation and is reduced by facility operating costs, labour costs and general and administrative expenditures. During the three months ended December 31, 2007, cash provided by operating activities was $21,974 thousand, an increase of $7,087 thousand compared to the same period in 2006. During the year ended December 31, 2007, cash provided by operating activities was $66,451 thousand, an increase of $26,139 thousand compared to 2006. The increase for both the three months and year ended December 31, 2007 is due mainly to an increase in net income as well as a more rapid collection of fees charged to customers.

Cash Used in Investing Activities

Cash used in investing activities during the three and year ended December 31, 2007 was comprised of cash capital expenditures. In 2006, the Partnership acquired WGSI for $142,491 thousand. The Partnership has invested the following maintenance and expansion amounts in the business, excluding the acquisition of WGSI.



--------------------------------------------------------------------------
Three months ended December 31
(in thousands of dollars) 2007 2006 Variance
--------------------------------------------------------------------------
Maintenance(i) 2,965 2,003 962
Expansion 18,408 877 17,531
---------- ---------- ----------
Total cash capital expenditures
(net of accruals) 21,373 2,880 18,493
---------- ---------- ----------
---------- ---------- ----------
--------------------------------------------------------------------------

--------------------------------------------------------------------------
Year ended December 31
(in thousands of dollars) 2007 2006 Variance
--------------------------------------------------------------------------
Maintenance(i) 6,913 2,985 3,928
Expansion 33,817 1,796 32,021
---------- ---------- ----------
Total cash capital expenditures
(net of accruals) 40,730 4,781 35,949
---------- ---------- ----------
---------- ---------- ----------
--------------------------------------------------------------------------
(i) Includes maintenance and information systems costs.


The increase in maintenance cash capital expenditures during the three months ended December 31, 2007 is due primarily to integrity work on the Brazeau River gathering lines, and the increase in maintenance cash capital expenditures during the year ended December 31, 2007 is due primarily to the timing of the maintenance projects, as well as the Brazeau River integrity work. The increase in expansion cash capital expenditures during the three months ended December 31, 2007 relates primarily to the greenfield sour gas processing facility at West Doe and the acquisition of the Valhalla Extension pipeline, and the increase in expansion cash capital expenditures during the year ended December 31, 2007 relates primarily to the greenfield sour gas processing facility at West Doe, the Valhalla Pipeline Project and the Valhalla Extension pipeline.

The Partnership anticipates that maintenance cash capital expenditures will be approximately $6.5 million. Expansion cash capital expenditures will be approximately $45 million in 2008 for new expenditures, as well as approximately $10 million for 2007 West Doe facility costs to be paid in 2008. The maintenance cash capital expenditures will be funded from operating cash flows, while the expansion cash capital expenditures will be funded primarily from additional borrowing under credit facilities, as well as operating cash flows.

Cash Provided by Financing Activities

Cash used in financing activities for the three months ended December 31, 2007 was comprised mainly of distributions of $9,506 thousand paid to partners, of which $5,114 thousand were paid to the Fund. The Partnership also borrowed funds from WEI in the amount of $153,400 thousand during the fourth quarter of 2007 to pay down its Credit Facility in the amount of $147,300 thousand and to partially finance the expansion capital projects.

Cash used in financing activities for the year ended December 31, 2007 was comprised mainly of distributions of $38,026 thousand paid to partners, of which $20,455 thousand were paid to the Fund. The Partnership also borrowed funds from WEI in the amount of $153,400 thousand during the year ended December 31, 2007 to pay down its Credit Facility in the amount of $142,300 thousand and to partially finance the expansion capital projects.

Distributable Cash Flow

The Partnership pays distributions to its partners on a monthly basis from its distributable cash, as determined in accordance with the terms of a partnership agreement dated December 5, 2005. The Partnership's distributable cash for each month will generally be all of its cash flow from operations for such month, including dividends received from subsidiaries, after satisfaction of its debt service obligations, reclamation expenditures, maintenance capital expenditures, other expense obligations and reasonable reserves for working capital and capital expenditures as may be considered appropriate by the Manager of the Partnership.

During the three months ended December 31, 2007, the Partnership declared $9,506 thousand (2006 - $9,620 thousand) of distributions to partners, of which $5,114 thousand (2006 - $5,227 thousand) was due to the Fund, and during the year ended December 31, 2007, the Partnership declared $38,026 thousand (2006 - $32,119 thousand) of distributions to partners, of which $20,455 thousand (2006 - $15,113 thousand) was due to the Fund.

Contractual and Other Long Term Obligations

The Partnership enters into contracts that require payments of cash in specific periods. The following table summarizes the contractual cash obligations as at December 31, 2007 for each of the periods presented.



--------------------------------------------------------------------------
Payment Due by Period
---------------------------------------------------
1 to 3 4 to 5 After
Less than years years 5 years
(in thousands of 1 Year (2009 and (2011 and (beyond
dollars) Total (2008) 2010) 2012) 2012)
--------------------------------------------------------------------------
Long-term debt (1) - - - - -
--------------------------------------------------------------------------
Due to affiliate (2) 153,400 - - 153,400 -
--------------------------------------------------------------------------
Power contract (3) 1,996 1,996 - - -
--------------------------------------------------------------------------

(1) The Partnership has a $200 million revolving long-term credit facility
maturing in 2009 with a banking syndicate. As at December 31, 2007,
the face value of the indebtedness under the Credit Facility is $nil.
(2) The Partnership has access to an uncommitted revolving long-term
credit facility, up to $200 million, via its affiliate, Westcoast,
maturing in 2011. As at December 31, 2007, the face value of the
indebtedness is $153.4 million.
(3) A subsidiary of the Partnership has entered into a one year contract
expiring on December 31, 2008 for the purchase of electricity at a
fixed price and fixed quantity.


Other long-term liabilities include $1.9 million of environmental reserve, $32.5 million of future income taxes and $16.0 million of asset retirement obligations recognized on the December 31, 2007 consolidated balance sheet.

Risk Profile

Business Risk

Management has summarized below, what it considers to be important business risks that could potentially have a material impact on the operations and financial results of the Partnership. The Fund's AIF for the year ended December 31, 2007 contains a thorough description of these and other risk factors and should be read in conjunction herewith. Additional information on the Fund including the Fund's AIF can be found on SEDAR at www.sedar.com.

The business of the Partnership is subject to operational and commercial risks that could adversely affect future earnings and distributions. These risks include decline in facilities throughput, change in gas composition, operational problems and hazards, cost overruns, increased competition, regulatory intervention, environmental considerations, uncertainty of abandonment costs and dependence upon key personnel.

The Partnership has structured business arrangements to mitigate the effect of certain of these risks on the Partnership's revenues and distributions. Operational risks are mitigated by application of high standards in the planning, construction, maintenance and operation of the facilities. In addition, the Partnership places high emphasis on training in safety and lost time prevention.

Business risk is also mitigated through the purchase of insurance coverage, including coverage for property damages, business interruptions and liability.

The Partnership is indirectly exposed to the impact of market fluctuations in the price of natural gas.

Financial Instruments and Financial Risk

The Partnership's financial instruments are comprised of cash, short term investments, accounts receivable, accounts payable, distributions payable, the Credit Facility, and the interim credit facility provided by Westcoast. Cash and short term investments are classified as held-for-trading and are measured at fair value. Accounts receivable is measured at amortized cost consistent with the "loan and receivable" classification. The financial liabilities are all measured at amortized cost consistent with the "other" classification. The fair value of these financial instruments approximate carrying value due either to their short term to maturity or, as with the Credit Facility and the interim credit facility provided by Westcoast, they bear interest at floating market rates.

The Partnership entered into a Credit Facility with a syndicate of financial institutions on December 20, 2005. The Credit Facility bears interest at rates that vary depending on the consolidated debt to EBITDA ratio of the Partnership and which may be based on the lender's Canadian prime rate or U.S. base rate, Canadian bankers' acceptance or the LIBOR drawing rate plus a margin.

The CT Trustees approved a financing arrangement with Westcoast whereby the Partnership will have access to a new credit facility which will replace the Partnership's current bank credit facility. Until this arrangement becomes effective, the Partnership will continue to have access to its current bank credit facility, as well as to an interim credit facility provided by Westcoast which bears interest at rates that vary depending on the consolidated debt to EBITDA ratio of the Partnership and which may be based on the lender's Canadian prime rate or U.S. base rate, CDOR fee, or the LIBOR drawing rate, plus a margin.

At December 31, 2007, there exists a Demand Operating Loan Agreement for $10 million between the Partnership and the Bank of Nova Scotia that took effect on December 20, 2005. As at December 31, 2007, no drawings had occurred against the operating loan.

The Partnership does not own the product that it processes and thus there is no direct exposure to commodity price risk as it relates to the Partnership's cash flows from its revenues. The pricing of the services provided is covered by contractual arrangements over varying terms.

The Partnership is subject to price fluctuations for electricity consumed in the operation of its facilities. In order to minimize this risk, a subsidiary of the Partnership has entered into a fixed price electricity purchase contract for the calendar year 2008.

All of the operations are conducted in Canadian dollars, so there is minimal exposure to foreign exchange fluctuations.

Credit Risk

The Partnership has extensive contractual relationships with natural gas, natural gas liquids and electricity producers and customers, natural gas marketers, local distribution companies, commercial enterprises, industrial companies, suppliers and financial institutions. The risk of non-performance by a contracting party may be analyzed and managed but it cannot be entirely eliminated. Ongoing consolidation of customers, financial institutions and partners may increase the severity of a default.

Related Party Transactions

The Partnership has entered into various management, administrative and governance agreements with Spectra Energy Facilities Management LP (the "Manager") and its affiliates. The Manager provides management, administrative and governance services for a base fee plus reasonable direct costs. The Partnership has also entered into service agreements with Spectra Energy Corp and its affiliates, who provide services such as legal, human resources, IT, infrastructure, information management, environmental health and safety, accounting, taxes, and corporate governance. The Partnership also had transactions with companies related through common or joint control for operational revenues and expenses, and these transactions are in the normal course of operations and are recorded at exchange amounts established and agreed between the related parties.

A subsidiary of the Partnership has entered into a fixed price electricity purchase contract for the calendar year 2008. Payment of this contract has been guaranteed by Westcoast.

The following table outlines the various material transactions for the three months and years ended December 31, 2007 and 2006.



---------------------------------------------------------------------------
Management,
Administrative,
and
Processing Gathering Governance Service
Fees Fees Agreements Agreement
(in thousands of dollars) Revenue Paid Charges Charges
---------------------------------------------------------------------------

Three months ended
December 31, 2007
Spectra Energy Facilities
Management LP - - 3,535 -
Westcoast Energy Inc. 2,224 1,174 - 1,046
Union Gas Limited - - - 67
Spectra Energy Corp. - - - 47
-----------------------------------------------
Totals 2,224 1,174 3,535 1,160
-----------------------------------------------
-----------------------------------------------

Three months ended
December 31, 2006
Spectra Energy Facilities
Management LP - - 2,891 -
Westcoast Energy Inc. 2,144 1,177 - 1,055
Union Gas Limited - - - 91
Duke Energy Corporation - - - 101
-----------------------------------------------
Totals 2,144 1,177 2,891 1,247
-----------------------------------------------
-----------------------------------------------

Year ended December 31, 2007
Spectra Energy Facilities
Management LP - - 14,019 -
Westcoast Energy Inc. 8,567 5,820 - 5,198
Union Gas Limited - - - 355
Spectra Energy Corp. - - - 216
-----------------------------------------------
Totals 8,567 5,820 14,019 5,769
-----------------------------------------------
-----------------------------------------------

Year ended December 31, 2006
Spectra Energy Facilities
Management LP - - 8,275 -
Westcoast Energy Inc. 2,144 1,177 - 3,454
Union Gas Limited - - - 274
Duke Energy Corporation - - - 279
-----------------------------------------------
Totals 2,144 1,177 5,384 4,007
-----------------------------------------------
-----------------------------------------------
---------------------------------------------------------------------------


The acquisition of WGSI in 2006 is also a related party transaction. The acquisition has been accounted for using the purchase method, whereby the purchase consideration was allocated to the estimated fair values of the assets acquired and liabilities assumed at the effective date of the purchase.

The allocation of the purchase cost for the acquisition was finalized during 2007, and is as follows:



(in thousands of dollars)

Net assets acquired $ 145,223
Less: Cash acquired (2,700)
------------
Net non-cash assets acquired $ 142,523
------------
------------
Allocation:
Accounts receivable 7,326
Prepaid expenses and deposits 413
Net property, plant & equipment 165,132
Accounts payable and accrued liabilities (3,130)
Accounts payable - affiliate (199)
Other taxes payable (110)
Long term payable - affiliate (1,644)
Future income tax liabilities (25,265)
------------
Net cash consideration $ 142,523
------------
------------


The Partnership had the following balances receivable from and due to affiliates and related parties reflected in current assets and current liabilities.



--------------------------------------------------------------------------
As at
December 31, December 31,
(in thousands of dollars) 2007 2006
--------------------------------------------------------------------------
Due from affiliates - current 232 1,360

Due to affiliates - current 12,347 3,692

Due to affiliate - long term 152,989 -
--------------------------------------------------------------------------


Due from affiliates at December 31, 2007 of $232 thousand represents primarily costs paid on behalf of the Fund, as well as fees due from Westcoast for natural gas processing by the Fort St. John facilities.

Due from affiliates at December 31, 2006 of $1,360 thousand represents certain costs associated with the acquisition of WGSI due from Westcoast, as well as fees due from Westcoast for natural gas processing by the Fort St. John facilities. The balance owing for these costs and fees has been received during the first quarter of 2007.

The current portion of Due to affiliates at December 31, 2007 of $12,347 thousand relates to the management, administrative and governance agreement charges and the service agreement charges noted above, as well as other short-term advances. The balance owing for the management, administrative and governance agreement charges and the service agreement charges at December 31, 2006 has been repaid during 2007.

The long term portion of Due to affiliate at December 31, 2007 of $152,989 thousand represents interim financing under an uncommitted credit facility from Westcoast to replace the existing Credit Facility, net of deferred financing charges. The interim credit facility is an uncommitted facility in the amount of $200 million, and will expire in October, 2011, and is extendible for further one year periods. The credit facility bears interest at rates that vary depending on the consolidated debt to EBITDA ratio of the Partnership and which may be based on Canadian prime rate, US base rate, CDOR fee, or LIBOR drawing rate, plus a margin. The Partnership may draw down the credit facility in either Canadian or US Dollars.

Critical Accounting Estimates

The application of accounting estimates is an important process that continues to evolve as the Partnership's operations change and accounting guidance evolves. The Partnership has identified a number of critical accounting estimates that require the use of significant estimates and judgment. The Partnership considers an accounting estimate to be critical if: (i) an accounting estimate requires it to make assumptions about matters that were highly uncertain at the time the accounting estimate was made; and (ii) changes in an estimate that are reasonably likely to occur from period to period, or use different estimates that the Partnership reasonably could have used in the current period would have a material impact on the Partnership's financial condition or results of operations. Changes in estimates used in these and other items could have a material impact on the Partnership's financial condition or results of operations.

Management bases its estimates and judgments on historical experience and on other various assumptions that they believe are reasonable at the time of application. The estimates and judgments may change as time passes and more information about the Partnership's environment becomes available. If estimates and judgments are different than the actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new information. The Partnership discusses its critical accounting estimates and other accounting policies with senior management.

Revenue Recognition

The Partnership recognizes revenue on a fee-for-service basis when the service has been performed as third party product is gathered and treated in accordance with the applicable agreements.

Property, Plant and Equipment

Management uses estimated expected future net cash flows to measure the recoverability of its investment in these assets. The estimation of expected future net cash flows is inherently uncertain and relies to a considerable extent on assumptions regarding current and future economics and market conditions. If, in future periods, there are changes in the estimates or assumptions incorporated in to the impairment review analysis, the changes could result in a reduction to the book value of these assets.

Depreciation is calculated on a straight line basis over the estimated remaining useful lives of the capital assets over periods of up to twenty five years.

Goodwill

Impairment testing of goodwill is performed annually and consists of a two-step process. The first step involves a comparison of the fair value of a reporting unit with its book value. Within the Partnership, there are no reporting units below the consolidated level. If the carrying amount of the reporting unit exceeds its fair value, the second step of the process involves a comparison of the fair value and book value of the goodwill of that reporting unit. If the book value of the goodwill of a reporting unit exceeds the fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess. Additional impairment tests are performed between the annual reviews if events or changes in circumstances make it more likely than not that the fair value of the reporting unit is below its book value.

During the years ended December 31, 2007 and 2006, the fair value of the Partnership was determined to exceed the book value, and therefore, there were no goodwill impairment charges.

Asset Retirement Obligations

The Partnership provides for future asset retirement obligations associated with the retirement of property, plant and equipment when those obligations result from the acquisition, construction, development or normal operation of the assets. The obligations are measured initially at fair market value, discounted using a credit adjusted risk free interest rate and the resulting costs capitalized as part of the carrying amount of the related asset. The asset retirement cost is depreciated over the life of the asset. In subsequent periods, the liability increases due to the passage of time based on the time value of money until the obligation is settled and reflects changes in the amount or timing of the underlying future cash flows.

The gathering systems acquired with the purchase of the WGSI assets can be extended to serve exploration growth in the northwestern area of the Western Canadian Sedimentary Basin and, as well, are integrated with the large diameter gathering systems in the area. Therefore, management has determined that, for the operating assets acquired upon the acquisition of WGSI, these assets do not have a determinate life and therefore, a liability for asset retirement obligations has not been recorded for these assets.

Supplemental Information on Quarterly Results

The Partnership's operating assets are located in five geographically distinct operating areas (the Peace River Arch region, the Nevis region, the Pesh Complex region, the Brazeau River region and the Fort St. John region). The following table illustrates throughput volumes by region for each of the eight most recently completed quarters:



--------------------------------------------------------------------------
Average Daily
Throughput 2007 2006
(mmcf /d) Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
--------------------------------------------------------------------------
Peace River
Arch Region 184 174 187 177 173 172 185 200
Nevis Region 83 84 79 84 85 83 82 77
Pesh Complex
Region 71 82 88 86 83 100 103 85
Brazeau River
Region 51 37 60 54 50 48 52 51
Fort St.
John Region
(1) 161 171 167 177 184 - - -
--------------------------------------------------------------------------
Total average
daily
throughput 550 548 581 578 575 403 422 413
--------------------------------------------------------------------------

(1) The Fort St. John facilities were acquired on September 29, 2006.


EBITDA and Operating Cash Flow by Region

The Partnership provides financial measures in this MD&A that do not have a standardized meaning prescribed by GAAP. These non-GAAP measures may not be comparable to similar measures presented by other entities.

The purpose of these financial measures and their reconciliation to GAAP financial measures is shown below. All of the measures have been calculated consistent with previous disclosures by the Partnership.

The following table illustrates Operating Cash Flow by region and EBITDA for each of the eight most recently completed quarters:



--------------------------------------------------------------------------
(in thousands 2007 2006
of dollars) Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
--------------------------------------------------------------------------
Peace River
Arch Region 5,877 4,105 5,268 5,517 4,909 5,573 4,052 5,713
Nevis Region 2,817 3,673 2,543 2,782 3,706 1,977 2,747 2,723
Pesh Complex
Region 2,088 2,448 3,252 3,772 3,654 3,732 3,277 2,629
Brazeau River
Region 2,374 1,526 4,093 4,525 1,073 2,203 2,642 2,874
Fort St.
John Region
(3) 4,296 4,407 3,183 4,570 4,150 109 - -
--------------------------------------------------------------------------
Operating
cash flow
(1) 17,452 16,159 18,339 21,166 17,492 13,594 12,718 13,939
General and
adminis-
trative 2,494 3,143 3,293 3,469 3,218 2,044 2,147 2,473
--------------------------------------------------------------------------
EBITDA
(2) 14,958 13,016 15,046 17,697 14,274 11,550 10,571 11,466
Less:
Taxes -
current
and
future (3,040) 1,828 (1,678) 1,434 635 1,252 (319) 433
Net interest
expense 2,051 1,867 1,682 1,388 1,811 1,322 1,264 1,176
Asset
impairment 1,086 - - - - - - -
Depreciation
and
accretion 7,749 7,746 7,708 7,657 7,645 4,906 4,852 4,860
--------------------------------------------------------------------------
Net income
(GAAP) 7,112 1,575 7,334 7,218 4,183 4,070 4,774 4,997
--------------------------------------------------------------------------

(1) References to "Operating Cash Flow" are to revenue less direct
operating expenses, which includes operating and maintenance expenses
but excludes general and administrative expenses and accretion expense.
It is considered a key measure, as it demonstrates the ability of the
business to generate cash to meet its capital and financing
commitments.
(2) References to "EBITDA" are to earnings before interest, income taxes,
depreciation and accretion. EBITDA is a non-GAAP measure that
represents earnings generated to fund capital investments, meet
financial obligations and fund distributions. It is considered a key
measure, as it demonstrates the ability of the business to meet its
capital and financing commitments.
(3) These facilities were acquired on September 29, 2006.


Peace River Arch Region

Operating cash flow increased by $968 thousand during the three months ended December 31, 2007 as compared to the same period in 2006. The increase was due primarily to higher revenues of $1,063 thousand due mainly to increased production on stream from the addition of the Valhalla pipeline, the Valhalla Extension pipeline, and the West Doe plant, partially offset by lower revenue due to lower production volumes from reduced area activity around Fourth Creek.

Operating cash flow increased by $520 thousand during the year ended December 31, 2007 as compared to 2006. The increase was due primarily to higher revenues of $2,567 thousand due mainly to increased production on stream from the addition of the Valhalla pipeline, the Valhalla Extension pipeline, and the West Doe plant, and increased throughputs at the Pouce Coupe plant due to an expansion of capacity in late 2006, partially offset by lower revenue due to turnarounds at the Pouce Coupe, Gordondale East and Fourth Creek plants in 2007. The increase in revenues was partially offset by higher operating expenses of $2,047 thousand due mainly to higher maintenance costs for plant turnarounds at Pouce Coupe, Fourth Creek, and Gordondale East.

Nevis Region

Operating cash flow decreased by $889 thousand during the three months ended December 31, 2007 as compared to the same period in 2006. The decrease was due primarily to higher operating expenses of $492 thousand due mainly to higher labour, environmental and utilities costs, as well as lower revenues of $397 thousand due mainly to a positive equalization adjustment in 2006.

Operating cash flow increased by $662 thousand during the year ended December 31, 2007 as compared to 2006. The increase was due primarily to higher revenues of $1,323 thousand due mainly to higher positive equalization adjustments in 2007 of approximately $500 thousand, with the balance of the increase due mainly to higher plant throughput in 2007, partially offset by higher operating expenses of $661 thousand due mainly to higher labour, environmental and utilities costs.

Pesh Complex Region

Operating cash flow decreased by $1,566 thousand during the three months ended December 31, 2007 as compared to the same period in 2006. The decrease was due primarily to lower revenues of $1,550 thousand due mainly to lower gathering and processing volumes resulting from decreased area drilling activity.

Operating cash flow decreased by $1,732 thousand during the year ended December 31, 2007 as compared to 2006. The decrease was due primarily to lower revenues of $3,797 thousand due mainly to lower gathering and processing volumes resulting from decreased area drilling activity, partially offset by lower operating expenses of $2,065 thousand due primarily to lower maintenance costs in 2007 due mainly to a cost reduction plan implemented as a result of lower processing revenues and higher maintenance costs in 2006 related to plant turnarounds.

Brazeau River Region

Operating cash flow increased by $1,301 thousand during the three months ended December 31, 2007 as compared to the same period in 2006. The increase was due primarily to lower operating expenses of $693 thousand due mainly to lower utilities, partially offset by an equalization payment and pipeline integrity work. The remainder of the increase in operating cash flow was due to higher revenues of $608 thousand due mainly to higher average fees from increased volumes of sour gas processed, increased operating cost recoveries, and increased usage by customers of the Partnership's compression facilities, partially offset by a negative equalization adjustment.

Operating cash flow increased by $3,726 thousand during the year ended December 31, 2007 as compared to 2006. The increase was due primarily to higher revenues of $4,454 thousand due mainly to higher positive equalization adjustments of approximately $1,200 thousand, with the balance of the revenue increase represented by higher average fees as a result of increased operating cost recoveries, higher average fees from increased volumes of sour gas processed, higher gathering revenues, and increased usage by customers of the Partnership's compression facilities, partially offset by lower revenue due to a plant turnaround in 2007. The increase in revenue was partially offset by higher operating expenses of $728 thousand due mainly to higher maintenance costs for a plant turnaround, higher equalization payments, and pipeline integrity work, partially offset by lower utilities.

Fort St. John Region

Operating cash flow increased by $146 thousand during the three month period ended December 31, 2007 as compared to the same period in 2006. The increase was due primarily to lower operating expenses of $479 thousand due mainly to higher maintenance costs in 2006 for plant turnarounds, partially offset by lower revenues of $333 thousand due mainly to lower gathering and processing volumes resulting from decreased area drilling activity by existing customers.

Operating cash flow increased by $12,197 thousand during the year ended December 31, 2007 as compared to 2006. The increase was due primarily to the fact that the facilities were acquired on September 29, 2006, resulting in just three months and two days operating cash flows being reported during 2006.

EBITDA

EBITDA increased by $684 thousand during the three months ended December 31, 2007 to $14,958 thousand compared to the same period in 2006, primarily as a result of lower operations and maintenance costs of $569 thousand and lower general and administrative costs of $724 thousand, partially offset by lower revenues of $609 thousand.

EBITDA increased by $12,856 thousand during the year ended December 31, 2007 to $60,717 thousand compared to 2006, primarily as a result of higher revenues of $31,651 thousand, partially offset by higher operations and maintenance costs of $16,278 thousand and higher general and administrative costs of $2,517 thousand.

New Accounting Standards

On April 1, 2005, the Accounting Standards Board issued new Handbook Sections 1530, 3855, and 3865, entitled "Comprehensive Income", "Financial Instruments - Recognition and Measurement", and "Hedges", respectively. Under these new standards, all financial assets should be measured at fair value with the exception of loans, receivables and investments that are intended to be held to maturity and certain equity investments, which should be measured at cost. Similarly, all financial liabilities should be measured at fair value when they are held for trading or they are derivatives.

Gains and losses on financial instruments measured at fair value will be recognized in the income statement in the periods in which they arise, with the exception of gains and losses arising from:

- financial assets held for sale, for which unrealized gains and losses are deferred in other comprehensive income until sold or impaired; and

- certain financial instruments that qualify for hedge accounting.

Other comprehensive income comprises revenues, expenses, gains and losses that are recognized in comprehensive income, but are excluded from net income. Unrealized gains and losses on qualifying hedging instruments, translation of self-sustaining foreign operations, and unrealized gains or losses on financial instruments held for sale will be included in other comprehensive income and reclassified to net income when realized. Comprehensive income and its components will be a required disclosure under the new standards.

These new standards have been adopted by the Fund and the Partnership as of January 1, 2007 on a prospective basis. There has been no significant financial impact on the consolidated financial statements of the Fund and the Partnership as a result of the adoption of these new standards.

On December 1, 2006, the Accounting Standards Board issued new Handbook Section 1535, entitled "Capital Disclosures". Under this new standard, an entity will be required to disclose information about its capital and how it is managed. This information will enable users of its financial statements to evaluate the entity's objectives, policies and processes for managing capital. This new standard is effective for fiscal years beginning on or after October 1, 2007 and early adoption is permitted. This standard will be adopted by the Fund and the Partnership as of January 1, 2008.

On December 1, 2006, the Accounting Standards Board issued new Handbook Sections 3862 and 3863, entitled "Financial Instruments - Disclosures" and "Financial Instruments - Presentation", respectively. Under these new standards, an entity will be required to disclose qualitative and quantitative information about its financial instruments and the risks associated with them. The new standard of disclosure will be more detailed than current disclosure requirements and is expected to give users of financial statements a better understanding of the significance of financial instruments in the determination of an entity's financial position, performance and cash flows, as well as a better understanding of the nature and extent of risks arising from financial instruments to which an entity is exposed during the period and at the balance sheet date, and how an entity manages those risks. These new standards are effective for fiscal years beginning on or after October 1, 2007 and early adoption is permitted. These standards will be adopted by the Fund and the Partnership as of January 1, 2008.

Certification of Disclosure Controls and Procedures and Internal Controls Over Financial Reporting

Internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with Canadian generally accepted accounting principles. Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Fund and the Partnership.

Management, including the President and Chief Executive Officer and the Vice-President of Finance and Accounting, of Spectra Energy Facilities Management Inc. as general partner for and on behalf of Spectra Energy Facilities Management LP, the administrator of the Fund ("the Administrator") and Manager of Spectra Energy Commercial Trust and the Partnership has evaluated the effectiveness of the Fund's and the Partnership's disclosure controls and procedures as of the end of the period covered by the annual filings and has concluded that the disclosure controls are effective in ensuring that all material information required to be filed in this report has been made known to them in a timely fashion. The required information was effectively recorded, processed, summarized and reported within the time period necessary to prepare the annual filings. The disclosure controls and procedures are effective in ensuring that information required to be disclosed pursuant to applicable securities laws are accumulated and communicated to management, including the President and Chief Executive Officer and the Vice-President of Finance and Accounting of the Administrator and Manager as appropriate to allow timely decisions regarding required disclosure. Management has also designed internal controls over financial reporting for the Fund and the Partnership to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian generally accepted accounting principles. Management has determined that there has been no change in internal control over financial reporting for the Fund and the Partnership that occurred during the reporting period that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting. As in prior periods, the Audit Committee for the Fund and the Partnership reviewed this MD&A and the attached consolidated financial statements and the Board of Trustees approved the documents prior to their release.

MANAGEMENT RESPONSIBILITY FOR FINANCIAL REPORTING

The consolidated financial statements included in this Annual Report are the responsibility of Spectra Energy Facilities Inc. as general partner for and on behalf of Spectra Energy Facilities Management LP, the administrator of the Fund (the "Manager"). The financial statements have been prepared by the Manager in conformity with Canadian generally accepted accounting principles and include certain estimated amounts which are based on informed judgments to ensure fair representation in all material aspects. When alternative accounting methods exist, management has chosen those it considers most appropriate. Financial information contained elsewhere in the Annual Report is consistent with the financial statements.

The Manager has overall responsibility for internal controls and has developed a system of internal controls and formal policies and procedures to ensure the consistency, integrity and reliability of accounting and financial reporting, and to provide reasonable assurance that assets are safeguarded and that transactions are properly executed in accordance with the Manager's authorization. The Manager is also supported and assisted by a program of internal audit services.

The Audit Committee, consisting of independent trustees of the Fund, has reviewed the consolidated financial statements with the Manager and the external auditors and has reported to the trustees of the Fund who have approved the consolidated financial statements on behalf of the Fund.

The Unitholders' auditors have full and free access to the Audit Committee, as do senior representatives of internal audit services of the Manager. The Audit Committee reports its findings to the Board of Trustees.

Deloitte & Touche LLP performed an independent audit of the consolidated financial statements in this report. Their independent professional opinion on the fairness of these consolidated financial statements is included in the Auditor's Report.



Deloitte & Touche LLP
3000 Scotia Centre
700 Second Street S.W.
Calgary AB T2P 0S7
Canada

Tel: (403) 267-1700
Fax: (403) 264-2871
www.deloitte.ca


AUDITORS' REPORT

To the Unitholders of Spectra Energy Income Fund

We have audited the consolidated balance sheets of Spectra Energy Income Fund (the "Fund") as at December 31, 2007 and 2006 and the consolidated statements of operations, comprehensive income and net accumulated deficit and cash flows for the years then ended. These financial statements are the responsibility of the Fund's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these financial statements present fairly, in all material respects, the financial position of the Fund as at December 31, 2007 and 2006 and the results of its operations and its cash flows for the years then ended, in accordance with Canadian generally accepted accounting principles.

Calgary, Alberta

February 1, 2008

Deloitte & Touche, Chartered Accountants



Spectra Energy Income Fund
Consolidated Statements of Operations, Comprehensive Income
and Net Accumulated Deficit
--------------------------------------------------------------------------

--------------------------------------------------------------------------
For the years ended December 31 (in thousands
of Canadian dollars, except unit and per unit
amounts) 2007 2006
--------------------------------------------------------------------------

Equity income from Spectra Energy Facilities
LP (Note 4) $ 12,533 $ 8,451
Other income (Note 7) 1,733 1,287
Interest income 10 487
------------ ------------

Total income 14,276 10,225

Management and administrative expenses (Note 7) 1,724 1,286
------------ ------------

Income before taxes 12,552 8,939

Future income taxes (Note 8) 9,183 -
------------ ------------

Net income and comprehensive income 3,369 8,939

Net accumulated deficit, beginning of year (6,883) (223)
Distributions declared (20,455) (15,599)
------------ ------------
Net accumulated deficit, end of year $ (23,969) $ (6,883)
------------ ------------
------------ ------------

Weighted average number of units outstanding
during the year 24,351,000 17,659,162

Earnings per unit (basic and diluted) (Note 5) $ 0.138 $ 0.506
------------ ------------
------------ ------------

See accompanying notes to the consolidated financial statements.


Spectra Energy Income Fund
Consolidated Balance Sheets
--------------------------------------------------------------------------

--------------------------------------------------------------------------
As at
(in thousands of Canadian dollars) December 31, December 31,
ASSETS 2007 2006
--------------------------------------------------------------------------
CURRENT ASSETS
Cash $ 162 $ 150
Accounts receivable (Note 7) 65 501
Distributions receivable 1,705 1,705
Prepaid expenses 33 -
------------ ------------
1,965 2,356
------------ ------------

LONG-TERM ASSETS
Investment in Spectra Energy Facilities LP
(Note 4) 247,958 255,880
------------ ------------

TOTAL ASSETS $ 249,923 $ 258,236
------------ ------------
------------ ------------

--------------------------------------------------------------------------
LIABILITIES AND UNITHOLDERS' EQUITY
--------------------------------------------------------------------------
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 249 $ 659
(Note 7)
Distributions payable 1,705 1,705
------------ ------------
1,954 2,364
------------ ------------

FUTURE INCOME TAX LIABILITIES (Note 8) 9,183 -
------------ ------------

UNITHOLDERS' EQUITY
Unitholders' capital (Note 6) 262,755 262,755
------------ ------------

Accumulated earnings 12,449 9,080
Accumulated distributions (36,418) (15,963)
------------ ------------
Accumulated deficit (23,969) (6,883)
------------ ------------

238,786 255,872
------------ ------------

TOTAL LIABILITIES AND UNITHOLDERS' EQUITY $ 249,923 $ 258,236
------------ ------------
------------ ------------

See accompanying notes to the consolidated financial statements.

Approved by the Trustees of Spectra Energy Commercial Trust on behalf of
Spectra Energy Income Fund

Douglas J. Black John G. Schissel
Trustee Trustee


Spectra Energy Income Fund
Consolidated Statements of Cash Flows
--------------------------------------------------------------------------

--------------------------------------------------------------------------
For the years ended December 31
(in thousands of Canadian dollars) 2007 2006
--------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income $ 3,369 $ 8,939
Distributions received 20,455 13,773
Add (deduct) items not involving cash:
Equity income from Spectra Energy Facilities (12,533) (8,451)
LP (Note 4)
Future income taxes 9,183 -
Net working capital changes other than cash (7) 147
------------ ------------
Net cash provided by operating activities 20,467 14,408
------------ ------------

INVESTING ACTIVITIES
Increase in investment in Spectra Energy - (122,755)
Facilities LP
------------ ------------
Net cash used in investing activities - (122,755)
------------ ------------

FINANCING ACTIVITIES
Distributions declared (20,455) (15,599)
Change in distributions payable - 1,341
Issuance of Fund units - 122,755
------------ ------------
Net cash (used in) provided by financing
activities (20,455) 108,497
------------ ------------

INCREASE IN CASH 12 150
------------ ------------

CASH, BEGINNING OF YEAR 150 -
------------ ------------

CASH, END OF YEAR $ 162 $ 150
------------ ------------
------------ ------------

See accompanying notes to the consolidated financial statements.


Spectra Energy Income Fund

Notes to the Consolidated Financial Statements

For the years ended December 31, 2007 and 2006

1. Organization and Business

Spectra Energy Income Fund (the "Fund") is an unincorporated open-ended trust established under the laws of the Province of Alberta by a Trust Indenture on November 2, 2005 as amended and restated on December 20, 2005. The Fund is a mutual fund trust for the purposes of the Income Tax Act (Canada). The Fund indirectly owns a 53.80% interest in Spectra Energy Facilities LP (the "Partnership").

Spectra Energy Facilities LP (the "Partnership") is a limited partnership established under the laws of the Province of Alberta. The Partnership through its subsidiaries operates and manages natural gas processing plants and related natural gas gathering pipelines located throughout the Western Canadian Sedimentary Basin. The Fund is administered by and the Partnership is managed by Spectra Energy Facilities Management LP (the "Manager"). The general partner of the Partnership is Spectra Energy Facilities Inc. ("SEF Inc." or "GP"), a corporation incorporated under the laws of Canada.

2. Significant Accounting Policies

Accounting Principles

The Fund prepares its financial statements in accordance with Canadian generally accepted accounting principles ("GAAP"). The consolidated financial statements are presented in Canadian dollars, unless otherwise stated.

The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and notes. Although these estimates are based on management's best available knowledge at the time, actual results could differ.

Investments

The Fund indirectly holds a 53.80% interest in the Partnership, but does not account for its investment on a consolidated basis. The Fund does not have the ability to appoint a majority of the board positions responsible for the governance of the Partnership and, therefore, the Fund does not control the strategic operating, investing and financing decisions. Accordingly, the Fund's investment in the Partnership is accounted for using the equity basis of accounting whereby the cost of the investment is increased or decreased for net earnings or losses and reduced by the cash distributions paid to the Fund.

The Fund indirectly owns 100% of the shares of SEF Inc., but does not account for its investment on a consolidated basis, due to Spectra Energy Midstream Holdings Partnership ("SEMHP") having the ability to appoint a majority of the board positions of SEF Inc. The Fund's investment in SEF Inc. has been combined with its investment in the Partnership for financial reporting purposes.

The Fund reviews and evaluates the carrying value of its investments for impairment annually. More frequent reviews are conducted as conditions necessitate. In the event a decrease in the value of an investment is other than a temporary decline, the investment will be written down to recognize any impairment in the carrying value.

Earnings Per Unit

Net earnings and distributions accruing to unitholders per trust unit are calculated by dividing net earnings and distributions accruing to unitholders, respectively, by the weighted average number of trust units outstanding during the period. For the purposes of the weighted average number of trust units calculation, trust units are determined to be outstanding from the date they are issued. Diluted earnings per unit are calculated the same as basic earnings per unit except the weighted average numbers of diluted Fund units outstanding are used in the denominator.

3. Change in Accounting Policies

On January 1, 2007 the Fund adopted new Handbook Sections 1530, 3855, 3861, and 3865, entitled "Comprehensive Income", "Financial Instruments - Recognition and Measurement", "Financial Instruments - Disclosure and Presentation", and "Hedges", respectively. Under these new standards, all financial assets should be measured at fair value with the exception of loans, receivables and investments that are intended to be held to maturity and certain equity investments, which should be measured at amortized cost. Similarly, all financial liabilities should be measured at fair value when they are held for trading or they are derivatives.

Gains and losses on financial instruments measured at fair value will be recognized in the income statement in the periods in which they arise, with the exception of gains and losses arising from:

- financial assets held for sale, for which unrealized gains and losses are deferred in other comprehensive income until sold or impaired; and

- certain financial instruments that qualify for hedge accounting.

Other comprehensive income comprises revenues, expenses, gains and losses that are recognized in comprehensive income, but are excluded from net income. Unrealized gains and losses on qualifying hedging instruments, translation of self-sustaining foreign operations, and unrealized gains or losses on financial instruments held for sale will be included in other comprehensive income and reclassified to net income when realized. Comprehensive income and its components are a required disclosure under the new standards.

There has been no significant impact on the consolidated financial statements of the Fund as a result of the adoption of these new standards.

The Fund's financial instruments are comprised of cash, accounts receivable, distributions receivable and payable and accounts payable and accrued liabilities. Cash is classified as held-for-trading and is measured at fair value. Accounts receivable and distributions receivable are measured at amortized cost consistent with the "loan and receivable" classification. The financial liabilities are all measured at amortized cost consistent with the "other" classification. The fair values of these financial instruments approximate carrying value due to their short term to maturity.

The Fund also adopted Section 1506 - Accounting Changes the only impact of which is to provide disclosure of when an entity has not applied a new source of GAAP that has been issued but is not yet effective. This is the case with Section 3862 - Financial Instruments Disclosures, Section 3863 - Financial Instruments Presentations and Section 1535 - Capital Disclosures, which are required to be adopted for fiscal years beginning on or after October 1, 2007. The Fund will adopt these standards on January 1, 2008 and it is expected the only affect on the Fund will be incremental disclosures, including the significance of financial instruments for the entity's financial position and performance; and the nature, extent and management of risks arising from financial instruments to which the company is exposed.

4. Investment in Spectra Energy Facilities LP

Changes in the Fund's equity investment in the Partnership and GP during the year ended December 31, 2007 were as follows:



------------------------------------------------------------
(in thousands of Canadian dollars)
------------------------------------------------------------
Investment at December 31, 2006 $ 255,880

Equity income 12,533

Distributions (20,455)
------------

Investment at December 31, 2007 $ 247,958
------------
------------
------------------------------------------------------------


5. Earnings Per Unit

Earnings per unit are calculated using net income divided by the weighted average number of Units outstanding. Basic and diluted earnings per unit are the same because the Fund currently has no dilutive instruments.

6. Unitholders' Capital



--------------------------------------------------------------------------
As at
(in thousands of Canadian dollars, December 31, December 31,
except unit amounts) 2007 2006
--------------------------------------------------------------------------

FUND UNITS
Cost $ 262,755 $ 262,755
------------ ------------
------------ ------------

Number of Units outstanding 24,351,000 24,351,0
------------ ------------
------------ ------------
--------------------------------------------------------------------------


7. Related Party Transactions

Spectra Energy Facilities Management LP as administrator of the Fund, the manager of the Spectra Energy Commercial Trust (the "CT") and the Partnership, receives a base fee, an incentive fee, and reimbursement of costs for its services. During the year ended December 31, 2007, these amounts were $512 thousand (2006 - $296 thousand). The unpaid portion of these fees, as well as amounts owing to various related parties for expenses paid on behalf of the Fund, are included in accounts payable. The amount payable for these fees and advances at December 31, 2006 has been repaid in 2007.

The Partnership reimburses the Fund for all of its management and administrative expenses per the administration and governance agreement, and this reimbursement is described as other income in the consolidated statements of operations and net accumulated deficit. The unpaid portion of these reimbursed expenses at December 31, 2007 has been netted against the amounts payable by the Fund to the Partnership for advances received from the Partnership, and has been included as part of accounts receivable. The amount receivable for these reimbursed expenses at December 31, 2006 has been received in 2007.

8. Income Taxes

In June 2007 the Government of Canada enacted new legislation imposing additional income taxes upon publicly traded income trusts, including the Fund, effective January 1, 2011. Prior to June 2007, the Fund estimated the future income tax on certain temporary differences between amounts recorded on its balance sheet for book and tax purposes at a nil effective tax rate. Under the legislation, the Fund now estimates the effective tax rate on the post 2010 reversal of these temporary differences to be 28.0%. Temporary differences reversing before 2011 will still give rise to nil future income taxes.

Based on its assets and liabilities as at December 31, 2007, the Fund has estimated the amount of its temporary differences which were previously not subject to tax, and has estimated the periods in which these differences will reverse. The Fund estimates that $32,797 thousand net taxable temporary differences will reverse after January 1, 2011, resulting in an additional $9,183 thousand future income tax liability. The taxable temporary differences relate principally to the excess of net book value of natural gas processing assets over the remaining tax pools attributable thereto.

As the legislation gives rise to a change in the Fund's estimated future income tax liability in the period, the recognition of the additional liability is accounted for prospectively in the period and an additional $9,183 thousand of future income tax expense has been recorded for the year ended December 31, 2007.

While the Fund believes it will be subject to additional tax under the new legislation, the estimated effective tax rate on temporary difference reversals after 2011 may change in future periods. As the legislation is new, future technical interpretations of the legislation could occur and could materially affect management's estimate of the future income tax liability.

The amount and timing of reversals of temporary differences will also depend on the Fund's future operating results, acquisitions and dispositions of assets and liabilities, and distribution policy. A significant change in any of the preceding assumptions could materially affect the Fund's estimate of the future tax liability.



Significant components of the Fund's future income taxes on the Balance
Sheet:

--------------------------------------------------------------------------
(in thousands of Canadian dollars) 2007 2006
--------------------------------------------------------------------------

Future Tax Liabilities
Property, plant and equipment $ (10,907) $ -

Future Tax Assets
Asset retirement obligation 1,540 -
Environmental remediation liability 184 -
------------ ------------
Net Future Tax Liabilities $ (9,183) $ -
--------------------------------------------------------------------------


Statement of Operations and Comprehensive Income:

--------------------------------------------------------------------------
(in thousands of Canadian dollars) 2007 2006
--------------------------------------------------------------------------

Current income taxes at Canadian statutory rate $ - $ -

Future income taxes resulting from a change in
tax status with the enactment of Bill C-52 9,183 -
------------ ------------
Income tax expense $ 9,183 $ -
--------------------------------------------------------------------------


9. Economic Dependence

For the purposes of declaring distributions, the Fund is entirely dependent on cash distributions, the business and operations of the Partnership.

10. Subsequent Events

On March 4, 2008 Spectra Energy Corp. ("Spectra Energy") and Westcoast Energy Inc. ("Westcoast") announced that an affiliate of Spectra Energy and Westcoast had entered into an agreement with the Fund to purchase (either by direct purchase or through a redemption by the Fund) all of the outstanding units of the Fund at a purchase price of $CDN 11.25 payable in cash. A special meeting of unitholders to consider the transaction is expected to be held in April, 2008. The closing of the transaction is subject to approval of at least a majority of the Fund's unitholders, other than Spectra Energy and its affiliates, and receipt of required regulatory approvals.



Deloitte & Touche LLP
3000 Scotia Centre
700 Second Street S.W.
Calgary AB T2P 0S7
Canada

Tel: (403) 267-1700
Fax: (403) 264-2871
www.deloitte.ca


AUDITORS' REPORT

To the Partners of Spectra Energy Facilities LP

We have audited the consolidated balance sheets of Spectra Energy Facilities LP (the "Partnership") as at December 31, 2007 and 2006 and the consolidated statements of operations, comprehensive income and partner's deficit and cash flows for the years then ended. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these financial statements present fairly, in all material respects, the financial position of the Partnership as at December 31, 2007 and 2006 and the results of its operations and its cash flows for the years then ended, in accordance with Canadian generally accepted accounting principles.

Calgary, Alberta

February 1, 2008

Deloitte & Touche, Chartered Accountants



Spectra Energy Facilities LP
Consolidated Statements of Operations, Comprehensive Income and Partners'
Deficit
--------------------------------------------------------------------------

--------------------------------------------------------------------------
For the years ended December 31
(in thousands of Canadian dollars) 2007 2006
--------------------------------------------------------------------------

OPERATING REVENUES $ 133,496 $ 101,845
------------ ------------

OPERATING EXPENSES
Operations and maintenance 60,380 44,102
Depreciation 29,808 21,237
Accretion 1,052 1,026
General and administrative 12,399 9,882
Asset impairment (Note 6) 1,086 -
------------ ------------
104,725 76,247
------------ ------------

OPERATING INCOME BEFORE OTHER INCOME
(EXPENSE) 28,771 25,598
------------ ------------

OTHER INCOME 684 280

LONG-TERM INTEREST EXPENSE (Note 7) (6,467) (5,853)

LONG-TERM INTEREST EXPENSE - Affiliate (Note 11) (1,205) -
------------ ------------

INCOME BEFORE TAXES 21,783 20,025
------------ ------------

TAXES (Note 9)
Current - 55
Future (1,456) 1,946
------------ ------------
(1,456) 2,001
------------ ------------

NET INCOME AND COMPREHENSIVE INCOME 23,239 18,024
------------ ------------

PARTNERS' DEFICIT, BEGINNING OF YEAR (14,627) (532)
------------ ------------
DISTRIBUTIONS DECLARED
To General Partner (4) (3)
To Ordinary Unitholders (20,455) (15,113)
To Exchangeable Unitholders (17,567) (17,003)
------------ ------------
(38,026) (32,119)
------------ ------------

PARTNERS' DEFICIT, END OF YEAR $ (29,414) $ (14,627)
------------ ------------
------------ ------------

See accompanying notes to the consolidated financial statements.


Spectra Energy Facilities LP
Consolidated Balance Sheets
--------------------------------------------------------------------------

--------------------------------------------------------------------------
As at
(in thousands of Canadian dollars) December 31, December 31,
ASSETS 2007 2006
--------------------------------------------------------------------------
CURRENT ASSETS
Cash and short term investments $ 5,159 $ 6,433
Accounts receivable 29,219 36,936
Accounts and notes receivable - affiliate
(Note 11) 232 1,360
Taxes receivable 204 377
Prepaid expenses and deposits 613 357
Future income tax assets (Note 9) 396 60
Other asset held for resale (Note 5) - 276
------------ ------------
35,823 45,799
------------ ------------

PROPERTY, PLANT AND EQUIPMENT (Note 6)
Cost 659,754 613,674
Accumulated depreciation (135,299) (105,491)
------------ ------------
524,455 508,183
------------ ------------

DEFERRED FINANCING CHARGES (Note 7) - 513
GOODWILL 80,855 80,855
------------ ------------
TOTAL ASSETS $ 641,133 $ 635,350
------------ ------------
------------ ------------

--------------------------------------------------------------------------
LIABILITIES AND PARTNERS' EQUITY
--------------------------------------------------------------------------
CURRENT LIABILITIES
Accounts payable and accrued
liabilities $ 13,997 $ 10,958
Accounts payable - affiliate (Note 11) 12,347 3,692
Distributions payable 3,169 3,169
------------ ------------
29,513 17,819
------------ ------------

LONG-TERM DEBT
Credit facility (Note 7) - 141,609
Due to affiliate (Note 11) 152,989 -
------------ ------------
152,989 141,609
------------ ------------
LONG-TERM LIABILITIES (Note 8) 17,940 16,193
------------ ------------

FUTURE INCOME TAX LIABILITIES (Note 9) 32,496 36,747
------------ ------------
Commitments and Contingencies (Note 13)

PARTNERS' EQUITY
Partners' capital (Note 10) 419,209 419,209
Contributed surplus 18,400 18,400
Partners' deficit (29,414) (14,627)
------------ ------------
408,195 422,982
------------ ------------

TOTAL LIABILITIES AND PARTNERS' EQUITY $ 641,133 $ 635,350
------------ ------------
------------ ------------

See accompanying notes to the consolidated financial statements.

On behalf of the Board of Directors of Spectra Energy Facilities Management
Inc. as general partner and on behalf of Spectra Energy Facilities
Management LP, manager of Spectra Energy Facilities LP

Douglas J. Haughey Bruce E. Pydee
Director Director


Spectra Energy Facilities LP
Consolidated Statements of Cash Flows
--------------------------------------------------------------------------

--------------------------------------------------------------------------
For the years ended December 31
(in thousands of Canadian dollars) 2007 2006
--------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income $ 23,239 $ 18,024
Add (deduct) items not involving cash:
Future income taxes (1,456) 1,946
Depreciation of property, plant and 29,808 21,237
equipment
Accretion of asset retirement obligation 1,052 1,026
Asset impairment 1,086 -
Amortization of deferred financing charges 171 191
Net working capital changes other than cash
and short term investments (Note 12) 12,551 (2,112)
------------ ------------
Net cash provided by operating activities 66,451 40,312
------------ ------------
INVESTING ACTIVITIES
Maintenance capital expenditures (6,687) (3,291)
Expansion capital expenditures (42,560) (2,716)
Change in accounts payable related to 8,517 1,226
capital assets acquired
Acquisition of WGSI (Note 4) - (142,523)
------------ ------------
Net cash used in investing activities (40,730) (147,304)
------------ ------------
FINANCING ACTIVITIES
Payment of deferred financing fees (69) (234)
Net proceeds from the issuance of Ordinary LP - 117,671
units (Note 11)
Payment to SEMHP for exercise of over-allotment - (14,000)
option (Note 11)
Distributions declared (38,026) (32,119)
Change in distributions payable - 2,261
Credit facility (payments) advances (142,300) 36,000
Loan from affiliate 153,400 -
Capital lease payments - (1,071)
------------ ------------
Net cash (used in) provided by financing
activities (26,995) 108,508
------------ ------------
INCREASE (DECREASE) IN CASH AND SHORT TERM
INVESTMENTS (1,274) 1,516

CASH AND SHORT TERM INVESTMENTS,
BEGINNING OF YEAR 6,433 4,917
------------ ------------

CASH AND SHORT TERM INVESTMENTS,
END OF YEAR $ 5,159 $ 6,433
------------ ------------
------------ ------------

SUPPLEMENTAL CASH FLOW INFORMATION (Note 12)

See accompanying notes to the consolidated financial statements.


Spectra Energy Facilities LP

Notes to the Consolidated Financial Statements

For the years ended December 31, 2007 and 2006

1. Organization and Business

Spectra Energy Facilities LP (the "Partnership") is a limited partnership established under the laws of the Province of Alberta. The Partnership through its subsidiaries operates and manages natural gas processing plants and related natural gas gathering pipelines located throughout the Western Canadian Sedimentary Basin.

Spectra Energy Income Fund (the "Fund") is an unincorporated open-ended trust established under the laws of the Province of Alberta by a Trust Indenture on November 2, 2005 as amended and restated on December 20, 2005. The Fund is a mutual fund trust for the purposes of the Income Tax Act (Canada). The Fund indirectly owns a 53.80% interest in the Partnership.

The general partner of the Partnership is Spectra Energy Facilities Inc. ("SEF Inc." or "GP"), a corporation incorporated under the laws of Canada. As general partner, GP has the authority to manage the business and affairs of the Partnership and has unlimited liability for the obligations of the Partnership. GP is entitled to an allocation of 0.01% of income or loss of the Partnership for each fiscal year.

The Partnership itself is not subject to income tax however the Partnership consolidates corporate entities that are subject to corporate income taxes.

2. Significant Accounting Policies

Accounting Principles

The Partnership prepares its financial statements in accordance with Canadian generally accepted accounting principles ("GAAP"). The consolidated financial statements are presented in Canadian dollars, unless otherwise stated.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and notes. These include the recoverability of assets and the amounts recorded for depreciation, accretion, asset retirement obligation costs which depend on estimates of the operating lives of the assets and future cash flows from those assets, and cost recovery estimates related to revenues. Although these estimates are based on management's best available knowledge at the time, actual results may differ.

Basis of Presentation

The Partnership is considered to be a continuation of the business acquired from Spectra Energy Midstream Holdings Partnership ("SEMHP"). Accordingly, the Partnership follows the continuity of interest method of accounting. Under the continuity of interest method of accounting, the Partnership's acquisition of the issued and outstanding shares of Spectra Energy Midstream Corporation ("Spectra Midstream") from SEMHP were recorded at their net book value as of the purchase date and the equity of the Partnership represents the equity of the assets at that date. The consolidated financial statements include the accounts of the Partnership, its wholly-owned subsidiaries, and its investments in joint working interests. The joint working interests of the Partnership are its interests in the Brazeau River, Boundary Lake, and Gordondale West facilities. These joint working interests are recorded using the proportionate consolidation method, whereby its proportionate share of the assets, liabilities, revenues and expenses of the joint working interest are recorded in its financial statements.

Revenue Recognition

The Partnership recognizes revenue on a fee-for-service basis when the service has been performed as third party product is gathered and treated in accordance with the applicable agreements.

Cash and Short Term Investments

Short term investments, consisting of money market instruments with original maturities of three months or less, are considered to be cash equivalents and are recorded at cost, which approximates current market value.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. The Partnership capitalizes all construction-related direct labour and material costs, as well as indirect construction costs. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects that do not extend the useful life or increase the expected output is expensed as incurred.

Management uses estimated expected future net cash flows to measure the recoverability of its investment in these assets. If, in future periods, there are changes in the estimates or assumptions incorporated into the impairment review analysis, the changes could result in a reduction to the book value of these assets.

Depreciation is calculated on a straight line basis over the estimated remaining useful lives of the capital assets over periods of up to twenty five years.

Deferred Financing Charges

Deferred financing charges represent the costs associated with arranging the Credit Facility in 2005, as well as the new interim credit facility. The costs are being amortized using the effective interest rate method over the four-year term of the Credit Facility. The unamortized portion of these costs are now netted against the balance of the new interim credit facility after the implementation of the new accounting standards for financial instruments as described in Note 3 below. If the Credit Facility is cancelled prior to the expiry of the term, then the remaining balance of the deferred financing charges will be expensed at that time.

Goodwill

Impairment testing of goodwill is performed annually and consists of a two-step process. The first step involves a comparison of the fair value of a reporting unit with its book value. Within the Partnership, there are no reporting units below the consolidated level. If the carrying amount of the reporting unit exceeds its fair value, the second step of the process involves a comparison of the fair value and book value of the goodwill of that reporting unit. If the book value of the goodwill of a reporting unit exceeds the fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess. Additional impairment tests are performed between the annual reviews if events or changes in circumstances make it more likely than not that the fair value of the reporting unit is below its book value.

During the years ended December 31, 2007 and 2006, the fair value was determined to exceed the book value, and therefore, there were no goodwill impairment charges.

Asset Retirement Obligations

The Partnership provides for future asset retirement obligations associated with the retirement of property, plant and equipment when those obligations result from the acquisition, construction, development or normal operation of the assets. The obligations are measured initially at fair market value, discounted using a credit adjusted risk free interest rate and the resulting costs capitalized as part of the carrying amount of the related asset. The asset retirement cost is depreciated over the life of the asset. In subsequent periods, the liability increases due to the passage of time based on the time value of money until the obligation is settled and reflects changes in the amount or timing of the underlying future cash flows.

For the operating assets acquired upon the acquisition of Westcoast Gas Services Inc. ("WGSI"), management has determined that these operating assets do not have a determinate life and therefore, a liability for asset retirement obligations has not been recorded for these assets.

Income Taxes

The liability method of tax allocation is used in accounting for income taxes. Under this method, future income tax assets and liabilities are determined based on differences between the financial reporting and tax bases of assets and liabilities, and measured using the substantively enacted tax rates and laws that will be in effect when the differences are expected to reverse.

Segment Information

The Partnership operates thirteen raw gas processing plants and related gathering systems in five geographically distinct areas. Due to the similar nature, management and reporting of each of the facilities, the operations of the Partnership are deemed to be one segment and therefore, no further breakdown has been provided.

3. Change in Accounting Policies

On January 1, 2007 the Partnership adopted new Handbook Sections 1530, 3855, 3861, and 3865, entitled "Comprehensive Income", "Financial Instruments - Recognition and Measurement", "Financial Instruments - Disclosure and Presentation", and "Hedges", respectively. Under these new standards, all financial assets should be measured at fair value with the exception of loans, receivables and investments that are intended to be held to maturity and certain equity investments, which should be measured at amortized cost. Similarly, all financial liabilities should be measured at fair value when they are held for trading or they are derivatives.

Gains and losses on financial instruments measured at fair value will be recognized in the income statement in the periods in which they arise, with the exception of gains and losses arising from:

- financial assets held for sale, for which unrealized gains and losses are deferred in other comprehensive income until sold or impaired; and

- certain financial instruments that qualify for hedge accounting.

Other comprehensive income comprises revenues, expenses, gains and losses that are recognized in comprehensive income, but are excluded from net income. Unrealized gains and losses on qualifying hedging instruments, translation of self-sustaining foreign operations, and unrealized gains or losses on financial instruments held for sale will be included in other comprehensive income and reclassified to net income when realized. Comprehensive income and its components are a required disclosure under the new standards.

There has been no significant impact, other than the presentation of deferred financing charges, on the consolidated financial statements of the Partnership as a result of the adoption of these new standards. As a result of the new standards, deferred financing charges are now netted against the credit facility balance on the balance sheet.

The Partnership's financial instruments are comprised of cash, short term investments, accounts receivable, accounts payable, distributions payable, the credit facility, and the long term financing provided by Westcoast Energy Inc. ("WEI").

Cash and short term investments are classified as held-for-trading and are measured at fair value. Accounts receivable is measured at amortized cost consistent with the "loan and receivable" classification. The financial liabilities are all measured at amortized cost consistent with the "other" classification. The fair value of these financial instruments approximate carrying value due either to their short term to maturity or, as with the credit facility and the long term financing provided by WEI, they bear interest at floating market rates.

The Partnership is exposed to various risks related to its financial instruments as follows:

Commodity Price Risk

The Partnership does not own the product that it processes and, thus, there is no direct exposure to commodity price risk as it relates to the Partnership's cash flows from its revenues. The pricing of the services provided is covered by contractual arrangements over varying terms.

The Partnership is subject to price fluctuations for electricity consumed in the operation of its facilities. In order to minimize this risk, a subsidiary of the Partnership has entered into a fixed price electricity purchase contract for the calendar year 2008.

Interest Rate Risk

The Partnership's credit facility, as well as the long term financing provided by WEI, bear interest at variable rates and, as such, are exposed to interest rate fluctuations. There is minimal mitigation of interest rate exposure.

Currency Risk

All of the Partnership's operations are conducted in Canadian dollars and, thus, there is minimal exposure to foreign exchange fluctuations.

Credit Risk

Management monitors the creditworthiness of the customers on a regular basis and carries insurance coverage consistent with companies engaged in similar commercial operations with similar type properties.

The Partnership also adopted Section 1506 - Accounting Changes the only impact of which is to provide disclosure of when an entity has not applied a new source of GAAP that has been issued but is not yet effective. This is the case with Section 3862 - Financial Instruments Disclosures, Section 3863 - Financial Instruments Presentations and Section 1535 - Capital Disclosures, which are required to be adopted for fiscal years beginning on or after October 1, 2007. The Partnership will adopt these standards on January 1, 2008 and it is expected the only affect on the Partnership will be incremental disclosures, including the significance of financial instruments for the entity's financial position and performance; and the nature, extent and management of risks arising from financial instruments to which the company is exposed.

4. Acquisition of Westcoast Gas Services Inc.

On September 29, 2006, the Partnership indirectly acquired all of the outstanding common shares of WGSI from WEI. WGSI owned interests in four raw gas processing plants and related gas gathering systems (the "Fort St. John facilities") in northeastern British Columbia. The Partnership paid gross cash consideration of $145,223 thousand, including $223 thousand in costs. The gross purchase price in respect of the acquisition was settled by the use of $39,000 thousand from the issue of long-term debt, $103,671 thousand of net proceeds from the issue of 8,951,000 ordinary limited partnership units to the Fund, and $2,552 thousand from the general funds of the Partnership. The net earnings of WGSI for the period from the date of acquisition, September 29, 2006, to December 31, 2007 have been included in the consolidated statements of operations of the Partnership for the years ended December 31, 2006 and 2007.

The acquisition has been accounted for using the purchase method, whereby the purchase consideration was allocated to the estimated fair values of the assets acquired and liabilities assumed at the effective date of the purchase. The allocation of the purchase cost for the acquisition was finalized during 2007 and is as follows:



(in thousands of Canadian dollars)

Net assets acquired $ 145,223
Less: Cash acquired (2,700)
---------
Net non-cash assets acquired $ 142,523
---------
---------
Allocation:
Accounts receivable 7,326
Prepaid expenses and deposits 413
Net property, plant & equipment 165,132
Accounts payable and accrued liabilities (3,130)
Accounts payable - affiliate (199)
Other taxes payable (110)
Long term payable - affiliate (1,644)
Future income tax liabilities (25,265)
---------
Net cash consideration $ 142,523
---------
---------


5. Other Asset Held for Resale

In December, 2006, the Partnership acquired a property as part of an employee relocation program in the amount of $276 thousand. The Partnership sold the property in 2007 for proceeds which approximated its book value.

6. Property, Plant and Equipment



--------------------------------------------------------------------------
(in thousands of Canadian dollars) 2007 2006
--------------------------------------------------------------------------
Cost
Natural gas gathering systems $ 90,285 $ 71,776
Processing plants 569,469 541,898
--------- ---------
Total Cost 659,754 613,674
--------- ---------
Accumulated Depreciation
Natural gas gathering systems (17,006) (13,440)
Processing plants (118,293) (92,051)
--------- ---------
Total Accumulated Depreciation (135,299) (105,491)
--------- ---------
Net Property, Plant and Equipment $ 524,455 $ 508,183
--------------------------------------------------------------------------


During 2007 continued declines in gas volumes processed at the Boundary Lake Plant, in which the Partnership owns a 50% interest, and the resultant decline in revenues, triggered an impairment review of that facility. As a result of the review, a pre-tax impairment provision of $283 thousand was recorded in 2007, representing the excess of the carrying amount of the facility over its fair value. Fair value was determined based on the present value of estimated future cash flows from net operating revenue generated by the facility.

During 2007, it was determined that compression facilities were no longer required to support production at the Sunrise facility. This caused an impairment review of the assets at this location. As a result of the review, a pre-tax impairment provision of $803 thousand was recorded in 2007, representing the excess of the carrying amount of the facility over its fair value. Fair value was determined based on the present value of estimated future cash flows from net operating revenue generated by the facility.

7. Long-Term Debt

On December 20, 2005, the Partnership entered into a credit facility with a syndicate of financial institutions (the "Credit Facility"). The Credit Facility, which expires in December 2009, consists of a $200 million four year revolving facility that is extendible for further one year periods. The Credit Facility bears interest at rates that vary depending on the consolidated debt to EBITDA ratio of the Partnership and which may be based on the lender's Canadian prime rate or US base rate, Canadian bankers' acceptance or the LIBOR drawing rate plus a margin. The Partnership may drawdown the Credit Facility in either Canadian or US Dollars. The Credit Facility is unsecured and guaranteed by certain partners and subsidiaries of the Partnership. The Partnership was in full compliance with all covenants of the Credit Facility as at December 31, 2007.

The liability reported on the balance sheet at December 31, 2007 represents the face value of the loan, net of deferred interest. Although the balance as at December 31, 2007 is $Nil, the Credit Facility remains open. Therefore, the deferred financing charges related to this Credit Facility have been netted against the interim credit facility, as described below.

On August 9, 2007, the Trustees of Spectra Energy Commercial Trust (the "CT"), with those CT Trustees appointed by WEI as the sponsor of the Fund abstaining, approved a financing arrangement with WEI whereby the Partnership will have access to a new credit facility in the amount of $200 million at a lower borrowing cost compared to its current bank credit facility. This arrangement will replace the Partnership's current bank credit facility and will provide the Partnership with access to adequate liquidity sources. Until this arrangement becomes effective, the Partnership will continue to have access to its current bank credit facility, as well as to an interim credit facility provided by WEI. The interim credit facility is an uncommitted facility in the amount of $200 million, and will expire in October, 2011, and is extendible for further one year periods. The credit facility bears interest at rates that vary depending on the consolidated debt to EBITDA ratio of the Partnership and which may be based on Canadian prime rate, US base rate, CDOR fee, or LIBOR drawing rate, plus a margin. The Partnership may draw down the credit facility in either Canadian or US Dollars. The liability reported on the balance sheet at December 31, 2007 represents the amount borrowed from WEI under the interim credit facility, net of deferred financing charges for both the original Credit Facililty and the new credit facility, as the set up of the new credit facility had not been completed as at that date.

The Partnership paid $704 thousand as arrangement fees and legal fees for the initial set up of the Credit Facility. These costs are deferred and are being amortized using the effective interest rate method over the term of the Credit Facility of four years. In the fourth quarter of 2007, the Partnership paid $69 thousand for legal fees related to the set up of the new credit facility to be provided by WEI. These costs will be amortized using the effective interest rate method over the term of the new credit facility beginning in 2008 when the new credit facility has been set up. The unamortized portion of these costs are now netted against the balance of the interim credit facility after the implementation of the new accounting standards for financial instruments as described in Note 3 above. For the year ended December 31, 2007, amortization expense of $171 thousand (2006 - $191 thousand) has been included in interest expense.

There exists a Demand Operating Loan Agreement for $10 million between the Partnership and a Chartered Canadian bank that took effect on December 20, 2005. As at December 31, 2007, no drawings had occurred against the operating loan.

8. Long-Term Liabilities

The fair value of asset retirement obligations have been calculated using a range of discount rates (from 5.8% to 8.2%) that were in effect when the original liabilities were estimated and an inflation factor of 2.3%. The total estimated cash flows required to settle the asset retirement obligations were $99,627 thousand as at December 31, 2007. The actual costs are currently expected to be incurred between 2010 and 2039.

Changes to the Partnership's asset retirement obligation for the years ended December 31, 2007 and 2006 are as follows:



--------------------------------------------------------------------------
(in thousands of Canadian dollars) 2007 2006
--------------------------------------------------------------------------
Opening Balance $ 13,880 $ 12,854

Accretion 1,052 1,026

Additions 1,051 -
--------- ---------

Closing Balance $ 15,983 $ 13,880
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The gathering systems acquired with the purchase of the Fort St. John facilities assets can be extended to serve exploration growth in the northwestern area of the Western Canadian Sedimentary Basin and, as well, are integrated with the large diameter gathering systems in the area. Therefore, management has determined that, for the operating assets acquired upon the acquisition of the Fort St. John facilities, these assets do not have a determinate life and therefore, a liability for these asset retirement obligations has not been recorded for these assets.

The balance of the long-term liabilities is primarily comprised of a provision established for specific environmental remediation.

9. Income Taxes

The Partnership itself is not subject to income tax; however, the Partnership consolidates corporate entities that are subject to corporate income taxes. In respect of the assets and liabilities of the Partnership where income is taxed directly in the hands of the Partners, the net book value for accounting purposes of these net assets exceeds their tax base by an amount of $60,714 thousand at December 31, 2007 (December 31, 2006 - $58,942 thousand).

Future income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of the Partnership's future tax liabilities and assets related to consolidated corporate subsidiaries are as follows:



--------------------------------------------------------------------------
(in thousands of Canadian dollars) 2007 2006
--------------------------------------------------------------------------

Future Tax Liabilities
Property, plant and equipment $ (33,858) $ (39,249)
Other (445) (433)

Future Tax Assets
Asset retirement obligation 1,507 1,487
Environmental remediation liability 181 258
Loss carryforwards 543 1,282
Valuation allowance (28) (32)
--------- ---------
Net Future Tax Liabilities $ (32,100) $ (36,687)
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At December 31, 2007, the corporate subsidiaries of the Partnership had estimated non-capital losses available to be carried forward of $1,469 thousand for income tax purposes which expire as follows:



--------------------------------------------------------------------------
(in thousands of Canadian dollars) Estimated Losses
--------------------------------------------------------------------------

2014 $ 38

2015 12

Thereafter 1,419
---------

Total $ 1,469
--------------------------------------------------------------------------


In addition, at December 31, 2007, the corporate subsidiaries of the Partnership had estimated capital losses available of $213 thousand which can be carried forward indefinitely.

The reconciliation of taxes attributable to net income before taxes computed at the statutory tax rates to tax expense is:



--------------------------------------------------------------------------
(in thousands of Canadian dollars) 2007 2006
--------------------------------------------------------------------------
Combined Canadian federal and provincial
Statutory income tax rates, including surtaxes 33.30% 34.70%

Statutory income tax applied to accounting
income $ 7,253 $ 6,948
Increase (decrease) in income taxes
resulting from
Income tax attributed to the Partners (3,531) (3,751)
Resource allowance deduction - (134)
Future income tax rate adjustments (3,550) (1,619)
Adjustments to tax pool balances (1,508) 267
Other permanent differences (120) 290
--------- ---------
Total Taxes Attributable to Net Income $ (1,456) $ 2,001
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10. Partners' Capital

The Partnership is authorized to issue two classes of partnership interests, ordinary limited partnership units ("LP Units") and exchangeable limited partnership units ("Exchangeable LP Units").



--------------------------------------------------------------------------
(in thousands of Canadian dollars,
except unit amounts) Units
--------------------------------------------------------------------------
ORDINARY LIMITED PARTNERSHIP UNITS
Balance, December 31, 2005 14,000,000 $ 140,000
Issued to Spectra Energy Commercial Trust 1,400,000 14,000
---------- ---------
Balance, March 31, 2006 15,400,000 154,000
Issued to Spectra Energy Commercial Trust 8,951,000 103,671
---------- ---------
Balance, December 31, 2006 and
December 31, 2007 24,351,000 $ 257,671
---------- ---------
---------- ---------

EXCHANGEABLE LIMITED PARTNERSHIP UNITS
Balance, December 31, 2005 20,913,750 $ 175,538
Reduction of carrying value upon exercise
of over-allotment option in first
quarter of 2006 (Note 11) - (14,000)
---------- ---------
Balance, December 31, 2006 and
December 31, 2007 20,913,750 $ 161,538
---------- ---------
---------- ---------
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11. Related Party Transactions

On January 13, 2006, pursuant to an agreement with SEMHP entered into on December 20, 2005, an over-allotment option was exercised and the proceeds of $14,000 thousand were used by the Fund to acquire additional LP Units resulting in the Fund indirectly owning a 42.41% interest in the Partnership. The Partnership paid to SEMHP cash equal to the proceeds from the over-allotment option which reduced the carrying value of the Exchangeable LP Units.

On August 22, 2006, the Fund received gross proceeds of $108,755 thousand from the issuance of subscription receipts of the Fund. On September 29, 2006 the subscription receipts were converted to Fund units and the net proceeds of $103,671 thousand, after deducting underwriters' fees and other costs, were used by the Fund to acquire additional LP Units, resulting in the Fund indirectly owning a 53.8% interest in the Partnership. The Partnership used the net proceeds from the Fund, as well as additional borrowings under its credit facility, to indirectly acquire all of the outstanding shares of WGSI from WEI.

A subsidiary of the Partnership has entered into a fixed price electricity purchase contract for the calendar year 2008. Payment of this contract has been guaranteed by WEI.

The Partnership had the following balances receivable from and due to affiliates and related parties reflected in current assets, current liabilities and long term liabilities.



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As at
December 31, December 31,
(in thousands Canadian of dollars) 2007 2006
--------------------------------------------------------------------------
Due from affiliates - current $ 232 $ 1,360

Due to affiliates - current $ 12,347 $ 3,692

Due to affiliate - long term $ 152,989 $ -
--------------------------------------------------------------------------


Due from affiliates at December 31, 2007 of $232 thousand represents primarily costs paid on behalf of the Fund, as well as fees due from WEI for natural gas processing by the Fort St. John facilities.

Due from affiliates at December 31, 2006 of $1,360 thousand represents certain costs associated with the acquisition of WGSI due from WEI, as well as fees due from WEI for natural gas processing by the Fort St. John facilities. The balance owing for these costs and fees has been received during the first quarter of 2007.

The Partnership has entered into various management, administration and governance agreements with Spectra Energy Corp and its affiliated companies. The Partnership receives management, administrative and governance services and pays a base fee and reimburses reasonable direct costs. During the year ended December 31, 2007, the fees were $14,019 thousand (2006 - $8,275 thousand). At December 31, 2007, $1,918 thousand (December 31, 2006 - $2,160 thousand) remains outstanding.

The remaining balance in the current portion of Due to affiliates relates to amounts owing to affiliate companies for services provided and short-term advances. These services include charges for legal, human resources, IT, infrastructure, information management, environmental health and safety, controllers and taxes as well as charges for corporate governance. During the year ended December 31, 2007, total charges of $5,769 thousand (2006 - $4,007 thousand) were recognized as part of General and Administrative Expenses. The balance owing for these services at December 31, 2006 has been repaid during the first quarter of 2007.

The long term portion of Due to affiliate at December 31, 2007 of $152,989 thousand represents interim financing under an uncommitted credit facility from WEI to replace the existing Credit Facility, net of deferred financing charges. The interim credit facility is an uncommitted facility in the amount of $200 million, and will expire in October, 2011, and is extendible for further one year periods. The credit facility bears interest at rates that vary depending on the consolidated debt to EBITDA ratio of the Partnership and which may be based on Canadian prime rate, US base rate, CDOR fee, or LIBOR drawing rate, plus a margin. The Partnership may draw down the credit facility in either Canadian or US Dollars.

The Partnership also had the following material transactions with companies related through common or joint control and significantly influenced investees:



--------------------------------------------------------------------------
(in thousands of For the Years Ended December 31
Canadian dollars) 2007 2006
--------------------------------------------------------------------------
Processing Gathering Processing Gathering
Fees Fees Fees Fees
Revenue Paid Revenue Paid

Westcoast Energy Inc. $ 8,567 $ 5,820 $ 2,144 $ 1,177
--------------------------------------------------------------------------


These transactions are in the normal course of operations and are recorded at exchange amounts established and agreed between the related parties. These transactions were related to the Fort St. John facilities, which were acquired on September 29, 2006. As a result, the amounts noted in the table above for 2006 represent the three months and two day period ended December 31, 2006.

12. Supplemental Cash Flow Information



Working capital changes other than cash

--------------------------------------------------------------------------
(in thousands of Canadian dollars) 2007 2006
--------------------------------------------------------------------------
Accounts receivable $ 7,718 $ 941
Accounts and notes receivable - affiliate 1,128 78
Prepaid expenses and deposits (255) 238
Accounts payable and accrued liabilities 1,969 (829)
Accounts payable - affiliate 1,482 (2,261)
Interest payable - affiliate - (36)
Income and other taxes 173 (58)
Other assets and liabilities attributable
to operating activities 336 (185)
--------- ---------
Net working capital changes other than cash $ 12,551 $ (2,112)
--------------------------------------------------------------------------


Interest and Tax Payments

--------------------------------------------------------------------------
(in thousands of Canadian dollars) 2007 2006
--------------------------------------------------------------------------
Interest paid $ 7,645 $ 4,780
Income taxes paid $ - $ -
--------------------------------------------------------------------------


13. Commitments and Contingencies

The Partnership and its subsidiaries, in the course of its operations, are subject to environmental and other claims, lawsuits and contingencies. Accruals are made in instances where it is probable that liabilities will be incurred and where such liabilities can be reasonably estimated. Although it is possible that liabilities may be incurred in instances for which no accruals have been made, the Partnership has no reason to believe that the ultimate outcome of these matters would have a material impact on its financial position, results of operations or cash flows.

The Partnership is committed to the purchase of electricity for its operational facilities in the amount of $1,996 thousand during the fiscal year ending December 31, 2008.

14. Guarantees and Indemnifications

The Partnership's Credit Facility, as described in Note 7, is unsecured and guaranteed by certain partners and subsidiaries of the Partnership. The interim credit facility provided by WEI, as described in Note 7, is unsecured and guaranteed by certain partners and subsidiaries of the Partnership.

The Partnership and each of its wholly-owned subsidiaries have entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These indemnification agreements typically cover environmental, tax, litigation, and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. Typically, claims may be made by third parties under these indemnification agreements for various period of time depending on the nature of the claim. The maximum potential exposure of the Partnership under these indemnification agreements can range from a specific dollar amount to an unlimited amount depending on the nature of the claim and the particular transaction. The Partnership is unable to estimate the total maximum potential amount of the future payments under these indemnification agreements due to several factors, including uncertainty as to whether claims will be made under these indemnities.

As of December 31, 2007, the Partnership had no material liabilities recorded for the above mentioned guarantees and indemnifications.

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