Inter Pipeline Fund

Inter Pipeline Fund

February 24, 2005 15:59 ET

Inter Pipeline Fund Announces Record 2004 Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: INTER PIPELINE FUND

TSX SYMBOL: IPL.UN
TSX SYMBOL: IPL.DB

FEBRUARY 24, 2005 - 15:59 ET

Inter Pipeline Fund Announces Record 2004 Results

CALGARY, ALBERTA--(CCNMatthews - Feb. 24, 2005) - Inter Pipeline Fund
("Inter Pipeline") (TSX:IPL.UN) is pleased to release its financial and
operating results for the twelve and three month periods ended December
31, 2004.

2004 Highlights

- 2004 cash flow, cash distributions and net income at record levels:

- cash flow increased 69% to $150 million

- cash distributions increased 45% to $116 million

- net income increased 430% to $72 million

- Payout ratio of 77% of cash flow from operations

- Natural gas liquids (NGL) extraction business contributed more than
$53 million in cash flow since acquisition in July, 2004

- Total return to unitholders of more than 27%

Fourth Quarter Highlights

- Fourth quarter cash flow increased 129% to $56 million

- Quarterly payout ratio of 60%

- Completed $380 million long-term debt private placement and doubled
the size of revolving credit facility to $400 million

- Record volumes transported on the Cold Lake pipeline system, and
record propane-plus volumes extracted at the Cochrane NGL extraction
plant

Cash Flow From Operations

In 2004, cash flow from operations increased 69% to $150.2 million
compared to $88.8 million in 2003. Fourth quarter cash flow increased
129% to $55.9 million compared to $24.4 million in the same period last
year. This growth is primarily the result of Inter Pipeline's $715
million acquisition of a NGL extraction business from Williams Energy
(Canada) Inc. Also contributing to the increase in cash flow were higher
operating margins on the conventional gathering business and lower
financing charges.

"This has been a defining year for Inter Pipeline," commented David W.
Fesyk, President and Chief Executive Officer. "Our record financial
performance and growth in 2004 demonstrates that Inter Pipeline has
emerged as a leader in the energy infrastructure sector."

Since closing the NGL extraction acquisition on July 28, 2004, the
extraction business has contributed in excess of $300 million to revenue
and more than $53 million to cash flow. Strong ethane and propane-plus
("C3+") volumes, combined with higher than expected prices on C3+
volumes produced at the Cochrane extraction plant contributed to these
results.

Cash Distributions

Cash distributions to unitholders during the year totaled $115.6
million, or $0.73 per unit, representing 77% of cash flow from
operations. In the fourth quarter, Inter Pipeline declared total cash
distributions of $0.1875 per unit representing 60% of cash flow from
operations. Higher than historical average frac-spreads in the last half
of the year contributed significantly to the low payout ratios in 2004.

Inter Pipeline has increased cash distributions to unitholders for a
third consecutive year. Monthly cash distributions are now $0.0625 per
unit, or $0.75 on an annualized basis. This regular monthly cash
distribution rate is expected to be maintained subject to review from
time to time by the Board of Directors of Inter Pipeline's general
partner, Pipeline Management Inc.

Operations

Throughput volumes on the Cold Lake pipeline system averaged 259,900 b/d
in 2004, up from 246,000 b/d in 2003. In the fourth quarter, Cold Lake
throughputs averaged 294,900 b/d, representing a 21% increase over the
same period of 2003. Higher volumes are reflective of increasing
production by Cold Lake producers.

Inter Pipeline's four conventional pipeline gathering systems averaged
213,800 b/d for the year and 213,200 b/d during the fourth quarter. On a
year-over-year basis, conventional volumes realized a modest 2.5%
decline. Despite the volume decrease, Inter Pipeline has been able to
improve the profitability of the conventional gathering business through
diligent toll management, operating cost reductions and facility
reconfigurations. In addition Inter Pipeline entered into a new oil
storage and marketing agreement with Nexen Marketing which contributes
to conventional system cash flow. In 2004, conventional gathering
margins increased 17% to $1.01 per barrel compared to $0.86 per barrel
in 2003.

The NGL extraction business was a significant contributor to Inter
Pipeline's record financial performance. In the fourth quarter, this
business processed record natural gas volumes averaging 4.4 Bcf per day,
and produced 151,200 b/d of NGLs, comprised of 95,200 b/d of ethane and
56,000 b/d of C3+.

Financing Activity

In October 2004, Inter Pipeline completed a $379.8 million debt private
placement of long-term unsecured notes and established a new $400
million revolving credit facility. These financing initiatives have
enabled Inter Pipeline to enhance the stability of its cash flow while
providing the financial flexibility to react quickly to new growth
opportunities.

Inter Pipeline continued to apply undistributed cash flow to reduce
outstanding debt. During the fourth quarter, debt was reduced by $24
million to $531 million. Lower debt levels, improved financial terms and
additional equity issuances have reduced financing charges by 44%,
year-over-year.

Conference Call

Inter Pipeline will hold a conference call on Friday, February 25 at
9:00 a.m. (MST) / 11:00 a.m. (EST) to discuss its 2004 financial and
operating results.

To participate in the conference call, please dial 877-323-2093 or
416-695-9706. A recording of the call will be available for replay until
March 4, 2005, by dialing 888-509-0082 or 416-695-5275. Pass codes are
not required.

Inter Pipeline will issue its 2004 annual report in late March.



Selected Financial and Operating Highlights

-----------------------------------------------------------------------
Three Months Ended Twelve Months Ended
(millions of dollars, December 31, December 31,
except where noted) 2004 2003 2004(1) 2003
-----------------------------------------------------------------------
Average Daily Volume (000 b/d)
Pipeline
Conventional 213.2 222.0 213.8 219.2
Cold Lake Pipeline(2) 294.9 244.3 259.9 246.0
Extraction Production(2)
(000 b/d)
Ethane 95.2 n/a 90.2 n/a
Propane Plus 56.0 n/a 53.1 n/a

Revenue
Pipeline 46.5 45.5 181.8 176.8
Extraction 188.9 n/a 300.3 n/a

Net Income 29.5 1.7 72.0 13.6

Cash Flow From Operations(3) 55.9 24.4 150.2 88.8

Cash Distributions(3) 33.7 22.3 115.6 79.6
Per Unit 0.1875 0.1800 0.7300 0.7200

Payout Ratio(3) 60.3% 91.4% 77.0% 89.6%

Capital Expenditures
Growth 3.0 5.0 18.3 13.7
Sustaining 0.9 1.0 2.7 2.2

1. Results for the Extraction Business are for the period
July 28, 2004 to December 31, 2004.
2. Volumes reported on a 100% basis.
3. Please refer to the "Non-GAAP Financial Measures"
section of the MD&A.


Inter Pipeline Fund

Inter Pipeline is a major Canadian petroleum transportation and natural
gas liquids extraction business based in Calgary, Alberta. Inter
Pipeline operates approximately 4,900 kilometres of petroleum pipelines
and 1.3 million barrels of storage in western Canada. These systems
transport approximately 470,000 barrels per day of oil sands bitumen,
conventional crude oil and gas plant condensate.

In addition, Inter Pipeline is one of North America's largest natural
gas liquids extraction businesses with ownership in three major
extraction facilities located in southern Alberta. These facilities are
capable of processing in excess of 6 billion cubic feet of natural gas
per day.

Inter Pipeline's Class A Units and convertible debentures trade on the
Toronto Stock Exchange under the symbols IPL.UN and IPL.DB, respectively.

Permitted Investors

Only persons who are residents of Canada, or if partnerships, are
Canadian partnerships, in each case for purposes of the Income Tax Act
(Canada) are entitled to purchase and own Class A Units and debentures
of Inter Pipeline.

Disclaimer

Certain information set forth above may contain forward-looking
statements that involve risks and uncertainties. Such information,
although considered reasonable by Inter Pipeline at the time of
preparation, may later prove to be incorrect and actual results may
differ materially from those anticipated in the statements made. For
this purpose, any statements that are contained herein that are not
statements of historical fact may be deemed to be forward-looking
statements.

MANAGEMENT'S DISCUSSION AND ANALYSIS FOR 2004

The following management's discussion and analysis provides a detailed
explanation of Inter Pipeline Fund's operating results for the year
ended December 31, 2004 as compared to the year ended December 31, 2003.
This discussion and analysis should be read in conjunction with the
Annual Information Form and other information filed by the Partnership
at www.sedar.com.

OVERVIEW

Inter Pipeline Fund (the "Partnership") achieved excellent results in
2004. The Partnership generated a total unitholder return of 27.4% and
delivered record revenue, net income, cash flow from operations and cash
distributions. The payout ratio of 77.0% for the year, representing the
amount of cash flow from operations paid to unitholders, reflects the
strong performance of the Partnership in 2004.

The Partnership achieved record results with respect to several key
financial metrics: revenue increased 172% to $482.4 million, net income
grew by 430% to $72.0 million and cash flow from operations was $150.2
million, 69% higher than in 2003. Strong financial performance allowed
the Partnership to increase cash distributions to unitholders for the
third consecutive year. On an annualized basis, cash distributions are
now $0.75 per unit compared to $0.72 per unit in 2003 and $0.68 per unit
in 2002.

Two key factors contributed to the strong financial and operating
results. First, was the Partnership's acquisition of the natural gas
liquids ("NGL") extraction business from Williams Energy (Canada), Inc.
This $715 million acquisition consisted of a 100% interest in both the
Cochrane and Empress II extraction plants and a 50% interest in the
Empress V extraction plant (collectively the "Extraction Business").
Secondly, the Partnership's crude oil pipeline business achieved record
throughput in 2004, delivering an average of 473,700 b/d. This
throughput level was primarily driven by increased deliveries on the
Cold Lake Pipeline System, in which the Partnership has an 85% interest.

2004 HIGHLIGHTS

- Acquired NGL extraction business from Williams Energy (Canada), Inc.
for $715 million.

- Increased monthly cash distributions $0.0025 per unit to $0.0625 as of
September 30, 2004. Total cash distributed was $115.6 million, $36.0
million higher than in 2003.

- Completed a private debt placement of $379.8 million in 8 and 10 year
unsecured notes.

- Replaced the previous $200 million unsecured revolving credit facility
with a $400 million facility on more favorable terms.

- Expanded the Bow River Pipeline System by increasing southbound
capacity by 17,000 b/d.

- Executed an Oil Storage and Marketing Agreement with Nexen Marketing.

- Completed construction of new storage and blending facilities on the
Cold Lake Pipeline System to allow shipment of a new blended oil product
known as DilSynBit.

- Strong environmental performance; one reportable hydrocarbon release
of .080m3 for all operations.

STRATEGIC OUTLOOK

Inter Pipeline's two businesses, Pipeline and the Extraction Business,
have strong fundamentals and are well positioned to provide stable and
predictable cash flow into the foreseeable future. Both businesses
contain long life energy infrastructure assets, and each has long-term
positive exposure to a significant North American energy development.
The Pipeline Business has positive exposure to the Alberta oil sands
development, and the Extraction Business has potential positive exposure
to Arctic natural gas developments in Alaska and the Mackenzie Delta.

Pipeline Business

The Cold Lake Pipeline System is well positioned to benefit from growth
in Alberta oil sands production. In the Cold Lake production area there
are roughly 200 billion barrels of oil in place, including 44 billion in
areas under active development by Cold Lake producers. Within these
active developments it is estimated that 2.2 billion barrels remain
recoverable using existing technology. At current production levels,
remaining recoverable reserves would have an approximate life of 20
years. The expansion of production operations into new areas of active
development and/or the introduction of new oil recovery technology could
significantly increase recoverable reserve estimates for the Cold Lake
oil sands region.

The Cold Lake Pipeline System has capacity available to meet future
delivery requirements of producers in the Cold Lake area. The system
currently has an installed capacity of 435,000 barrels per day. Existing
shippers have reserved 355,000 barrels per day of capacity under a long
term Transportation Services Agreement ("TSA"). In addition, the Cold
Lake Pipeline System can be expanded to achieve a throughput capacity of
705,000 barrels per day with the installation of relatively low cost
pumping facilities.

The TSA provides the Partnership with cash flow stability from its
investment in the Cold Lake Pipeline System. The 355,000 barrels per day
reservation by existing shippers is under a take or pay obligation which
provides the Partnership with a guaranteed payment regardless of actual
volume shipped. The shippers also pay a flow-through of substantially
all operating costs and a structured return on certain new facilities
required to meet pipeline system growth. The TSA also provides for a 3.3
million acre reserve dedication area in which any new production
developed by existing shippers must be delivered into the Cold Lake
Pipeline System.

The Partnership also operates four conventional gathering pipeline
systems located in Alberta and Saskatchewan. These systems consist of
approximately 4,000 kilometres of pipeline within a 22 million acre
service area. In recent years, the Partnership's conventional gathering
systems have experienced gradual throughput losses as the result of
natural production declines at connected field facilities. Despite these
declines, the Partnership has been able to improve the profitability of
its conventional gathering operations through toll increases, operating
cost reductions and the reconfiguration of facilities to accommodate
changing oil delivery patterns.

To further enhance the profitability of its conventional gathering
operations, the Partnership entered into a new oil storage and marketing
agreement with Nexen Marketing in July of 2004. This agreement allows
the Partnership to collect fixed fees for Nexen's use of certain oil
storage and transfer facilities owned by the Partnership. The
Partnership will benefit from an equal sharing of marketing profits
generated through the use of these facilities, with no direct exposure
to commodity prices.

Extraction Business

The Extraction Business has strong fundamentals. The location of the
Partnership's extraction plants at two of the three major transmission
export points for natural gas from Alberta ensures a long term
availability of feedstock. In effect, the entire Western Canadian
Sedimentary Basin is the gathering area for natural gas processed at the
Partnership's extraction plants. In addition, the possibility exists for
new gas developments in the Arctic region to be transported through the
TransCanada Pipeline Alberta system, and thus through the Partnership's
NGL extraction plants.

There is approximately 6 Bcf/d of new natural gas that may be shipped
from the Arctic regions through Alberta. If Arctic gas is shipped via
pipeline, expectations are that the Arctic gas will first fill the
existing export pipeline capacity in Alberta prior to the construction
of additional pipelines to transport Arctic gas to the United States.
This new gas will have the effect of increasing gas flows from the
Alberta export points. With extraction plants located on both the east
and west export points from Alberta, the Partnership is uniquely
positioned to process this additional Arctic gas if it should be shipped
on the TransCanada Alberta System.

In addition to potential Arctic gas opportunities, there exist a number
of low cost, high return efficiency opportunities at the Partnership's
Cochrane extraction plant. These projects can either reduce operating
costs, increase NGL production, or both. In addition there are higher
cost "deep cut" project opportunities that would significantly increase
ethane extraction for sale to existing customers. The Partnership plans
to consider all potential projects, with particular emphasis on
increasing ethane extraction capability to further supply the Alberta
demand for ethane.

Financial Stability

The Partnership's financial position supports ongoing stable and
predictable cash distributions to unitholders. In 2004, the Partnership
completed a $379.8 million U.S. private debt placement at attractive
long-term interest rates. This new long-term debt provides a high degree
of stability in the carrying cost requirements associated with the
assets of the Partnership. With this new debt in place, the amount of
floating rate capital on the Partnership's balance sheet is only 5.5% of
the total capital structure.

The cash flow profile of the Partnership is predominately contract and
tariff based. The Extraction and Pipeline Businesses principally derive
cash flow from a combination of cost of service and fee based contracts.
Under cost of service contracts there is no exposure to either
throughput volume risk or commodity price risk. Under fee based
contracts there is no exposure to commodity price risk. The only
commodity price exposure risk assumed by the Partnership applies to
profit sharing associated with propane-plus sales at the Cochrane plant.
This profit share is exposed to a frac-spread risk, which is the
difference between the selling price of the propane-plus and the cost of
natural gas required to make-up the heat content removed in the
extraction process. In 2004, this profit share component represented 16%
of total Partnership EBITDA.

In 2004, the Partnership was able to increase its distributions from
$0.72 to $0.75 cents per unit, on an annualized basis. This increase is
supported by strong business performance from: the Extraction Business,
which benefits from its cost of service and fee based contracts; the
Pipeline Business, which is entirely cost of service and fee based; and
prudent refinancing activities. In addition, the Extraction Business has
benefited from recent strengthening of frac-spreads. As a result, in
2004 only 77.0% of cash flow from operations was paid to unitholders in
the form of distributions. Undistributed cash has been applied to the
Partnership's short term debt, and is available to stabilize cash
distributions in the future, should the frac-spread environment weaken
and become lower than expected.

The Partnership remains committed to maintaining its investment grade
credit rating, which is currently rated BBB by Standard & Poor's.
Management strongly believes that an investment grade credit rating is
critical to the future success of the Partnership's financing strategies.

Growth

The Partnership will continue to seek opportunities to grow. The
Partnership's growth strategy includes both organic investment and
acquisitions. Organic investments are those which serve to optimize
existing businesses, such as pipeline expansions and extraction
efficiency enhancements. Any acquisitions will be complementary to the
existing businesses and incremental to cash flow. Energy infrastructure
assets that have cost of service or fee based contractual arrangements
similar to those employed within the existing businesses are of
particular interest to the Partnership.



SELECTED CONSOLIDATED FINANCIAL INFORMATION

Three Months Ended Year Ended
December 31 December 31
-----------------------------------------------------------------------
(millions, except per 2002
unit and % amounts) 2004 2003 2004 2003 (b)
-----------------------------------------------------------------------
Revenues
Pipeline Business (1) $ 46.5 $ 45.5 $ 181.8 $ 176.8 $ 95.9
Extraction Business(2) $ 188.9 $ - $ 300.3 $ - $ -

Net income(2) $ 29.5 $ 1.7 $ 72.0 $ 13.6 $ 20.6
Per unit - basic
and diluted $ 0.17 $ 0.01 $ 0.46 $ 0.13 $ 0.28

Cash flow from
operations (a)(1)(2) $ 55.9 $ 24.4 $ 150.2 $ 88.8 $ 53.6
Per unit (a) $ 0.33 $ 0.20 $ 0.97 $ 0.86 $ 0.73

Cash distributions
(a)(1)(2)(4) $ 33.7 $ 22.3 $ 115.6 $ 79.6 $ 49.9
Per unit $0.1875 $0.1800 $ 0.7300 $0.7200 $0.6800

Payout ratio (a) 60.3% 91.4% 77.0% 89.6% 93.1%

Total assets(1)(2) $1,743.0 $ 985.4 $ 750.8
Long-term debt(1)(2) $ 530.8 $ 102.0 $ 107.0
Convertible Debentures(3) $ 32.5 $ 100.1 $ 128.2
Total partners' equity $1,064.9 $ 758.0 $ 488.7
Partnership units
outstanding, end
of year 180.1 128.8 73.9
Total enterprise value (a) $2,213.0 $1,201.4 $ 689.5

(a) Please refer to the "Non-GAAP Financial Measures" section of
this MD&A
(b) Restated

(1) The incremental change in amounts from 2002 to 2003 is primarily the
result of the acquisition of an additional 70% interest in the Cold
Lake Pipeline Limited Partnership from EnCana Corporation on
January 2, 2003.
(2) The increase in amounts from 2003 to 2004 is the result of the
acquisition of the Extraction Business on July 28, 2004 discussed
below.
(3) $71.2 million of Convertible Debentures were converted into Class A
units during 2004.
(4) Cash distributions are calculated based on the number of units
outstanding at each record date.


Year Ended December 31, 2004

For the year ended December 31, 2004, Inter Pipeline's cash flow from
operations increased $61.4 million to $150.2 million, up from $88.8
million in 2003. This increase was primarily due to the immediate
contribution made by the acquired Extraction Business. The Extraction
Business contributed $53.6 million to cash flow from operations
commencing from the closing of the acquisition on July 28, 2004. Also
contributing to the increase was a higher overall margin on the
Partnership's Pipeline Business. Included in the cash flow from
operations is a $7.2 million acquisition fee paid to Pipeline Management
Inc. (the "General Partner") on the purchase of the Extraction Business,
which compares to the Cold Lake Pipeline System acquisition fee of $4.2
million paid in the prior year. During 2004, 77.0% of cash flow from
operations was distributed to unitholders, as compared to 89.6% in 2003.

The increase in cash flow from operations from the acquired Extraction
Business supported the Partnership's announcement of an increase in
monthly distributions of $0.0025 per unit beginning with unitholders of
record on September 30, 2004. Therefore, the Partnership made monthly
distributions in 2004 of $0.06 per unit for each month from January to
August and $0.0625 for September to December for a total of $0.73 per
unit for the year (annualized $0.75 per unit). This compares with the
$0.72 per unit distributed in 2003.

The total cash distributed in 2004 of $115.6 million was $36.0 million
higher than the $79.6 million distributed in 2003. This increase in
total cash distributed is mainly due to a materially larger number of
issued Partnership units. During 2004, there was an increase of 51.3
million outstanding Partnership units due primarily to a July 28, 2004
equity issuance of 38.0 million Class A units, and the conversion of
$71.2 million of 10% Convertible Extendible Unsecured Subordinated
Debentures (the "Debentures") into 11.9 million new Class A units. The
remaining 1.4 million of new units resulted from: 1) the General
Partner's acquisition of Class B units in order to maintain its required
0.1% interest in the Partnership; 2) exercises of Unit Incentive
Options; and 3) units issued under the Distribution Reinvestment and
Optional Unit Purchase Plans.

Fourth Quarter Ended December 31, 2004

Cash flow from operations was $55.9 million in the fourth quarter of
2004, which is a $31.5 million increase over the $24.4 million generated
in the same period of 2003. This increase is primarily due to the
acquisition of the Extraction Business. The Extraction Business provided
$34.3 million and the Pipeline Business contributed $34.3 million to
cash flow from operations during the fourth quarter of 2004. Cash flow
from operations in the fourth quarter of 2003 was derived solely from
the Pipeline Business.

Cash distributions declared in the quarter were $33.7 million or $0.1875
per unit. This compares to $22.3 million or $0.1800 per unit for the
fourth quarter of 2003. The payout ratio in the fourth quarter of 2004
is therefore 60.3% versus 91.4% in the comparable quarter in 2003.
Higher than historical average frac-spreads in the last half of the year
contributed significantly to the low payout ratios in 2004.

Approximately $3.9 million was spent on capital expenditures in the
three months ended December 31, 2004 as compared to $6.0 million in the
same quarter of 2003.



RESULTS OF OPERATIONS

PIPELINE OPERATIONS

Volumes and Transportation Revenues
The average throughput statistics for the respective periods are
as follows:

Year Ended
December 31
-------------
Pipeline System (000's b/d) 2004 2003
------------------------------------------------------------------------
Conventional Gathering
Bow River 144.4 150.4
Central /Valley/Mid Saskatchewan 69.4 68.8
------------------------------------------------------------------------
213.8 219.2
------------------------------------------------------------------------
------------------------------------------------------------------------

Cold Lake Pipeline (100% basis) 259.9 246.0
------------------------------------------------------------------------
------------------------------------------------------------------------


Total transportation revenues of $181.8 million in 2004 were $5.0
million higher than the $176.8 million earned in 2003. Revenues from the
Partnership's conventional gathering systems were $108.5 million in the
year, which is $6.8 million higher than 2003. The volume decrease of
5,400 b/d was more than offset by mainline toll increases of 2.0% and
3.5% effective January 1, 2004 and July 1, 2004, respectively, as well
as revenues earned from the Nexen Agreement beginning in the third
quarter of 2004. The average revenue per barrel in 2004 was $1.39 vs.
$1.27 per barrel in 2003.

Revenues from the Partnership's 85% interest in the Cold Lake Pipeline
System were $73.3 million for 2004, down $1.8 million from 2003. This
corresponds with an approximate $2.1 million decrease in operating
expenses. Operating expenses are virtually 100% recoverable from the
shippers and the recoveries are recorded as revenue. The TSA is
supported with an annual minimum ship or pay commitment of $52.1 million
($61.3 million - 100% basis) in 2004 and thereafter reduces to
approximately $30.9 million ($36.3 million - 100% basis) annually
through to the end of December 2011. Although the Cold Lake volumes have
increased to record levels in 2004, by exceeding the prior year's
volumes shipped by 13,900 b/d, they are still below the ship or pay
minimum amounts. Therefore, capital fees are consistent with ship or pay
obligations and continue to provide stable and predictable cash flows to
the Partnership. The remaining revenues are comprised primarily of
operating fee recoveries of $16.3 million ($19.2 million - 100% basis).

The Cold Lake Pipeline System DilSynBit Project was completed in
October, 2004 with revenues beginning to accrue to the Partnership at
that time. The DilSynbit Project will provide the ability to ship up to
60,000 b/d of a new blended oil sands product known as DilSynBit on the
Cold Lake Pipeline System.

Operating Costs

The Pipeline Business continued to experience operating cost savings in
2004. Consolidated pipeline operating costs of $45.5 million in 2004
were $5.5 million lower than 2003.

The main factor contributing to reduced operating costs was a reduction
in power expense of $2.3 million, primarily due to price decreases. The
average Alberta market power price for 2004 was $54.59 per mega-watt
hour ("MW.h") versus $62.99 per MW.h in 2003. The decrease in power
prices was further enhanced by the effects of price swap agreements
entered into by the Partnership for 5.0 mega-watts at an average price
of $46.95 per MW.h for the period January 1, 2004 to December 31, 2005.

Other factors contributing to the decrease include a $1.0 million
reduction in certain one-time repair and maintenance expenditures, which
were not incurred in 2004. In addition, contract manpower costs
decreased by $0.7 million due to cost reduction initiatives. The
Partnership also experienced cost savings of $0.6 million in 2004
compared to 2003 reflective of the synergies achieved when the
Partnership migrated all pipeline system control functions to the
Partnership's control centre in Sherwood Park, Alberta, which was
acquired as part of the January 2003 Cold Lake Pipeline System
acquisition.

EXTRACTION OPERATIONS

The Acquisition

The Extraction Business was acquired for cash from Williams Energy
(Canada), Inc. on July 28, 2004 for $715 million plus closing
adjustments. The purchase price allocation has been amended since
September 30, 2004 based on the adjustment to actual of certain closing
amounts. The working capital adjustment is still being finalized and
therefore the purchase price allocation is likely to be amended. The
purchase price allocation including acquisition costs and closing
adjustments is as follows:



(millions)
------------------------------------------------------------------------
Cash $ 3.7
Working capital deficiency (0.8)
Intangible assets - Customer contracts and patent 296.7
Property, plant & equipment 422.3
Asset retirement obligation (8.5)
------------------------------------------------------------------------
Total assets acquired $ 713.4
------------------------------------------------------------------------
------------------------------------------------------------------------


Description of the Assets

The Extraction Business processes pipeline quality gas exported on the
TransCanada Alberta System, removing higher value NGLs. The Extraction
Business is comprised of three facilities:

- 100% ownership of the 100,000 b/d Cochrane Extraction Plant. The
Cochrane plant is capable of processing up to 2.5 Bcf/d of natural gas
and produces ethane and propane-plus (a mix of propane, butanes and
condensate). The Cochrane Extraction Plant also owns a small fuel gas
gathering system. As a by-product of ethane extraction the Cochrane
plant produces a food grade CO2 stream.

- 100% ownership of the 65,000 b/d Empress II Extraction Plant. The
Empress II plant is capable of processing up to 2.6 Bcf/d of natural gas
and produces ethane and propane-plus.

- 50% ownership of the 30,000 b/d Empress V Extraction Plant. The
Empress V plant is capable of processing up to 1.1 Bcf/d of natural gas
and produces ethane and propane-plus. BP Canada Energy owns the
remaining 50% of the Empress V Extraction Plant.

The majority of the Extraction Business property, plant and equipment
are depreciated over 30 years on a straight-line basis reflecting the
long useful life of these assets.

Description of the Contracts

At all three extraction plants, 100% of the propane-plus is sold to BP
Canada Energy Resources Company, and 100% of the ethane is sold to
either Nova Chemicals Corporation or Dow Chemical Canada Inc.

The ethane and propane-plus are sold under long-term contracts with an
average remaining life of twelve years. These contracts are either cost
of service, fee based or profit share:

- Cost of service contracts provide for a fixed capital payment plus a
flow through of actual operating costs of the facility, regardless of
the number of barrels produced in the facility.

- Fee based contracts are based on a payment for every barrel of product
produced at the facility. These payments include a component for
operating costs.

- Profit share contracts provide payments that vary based on the
difference between the commodity price of the propane-plus produced and
the cost of natural gas required to make-up the heat content removed in
the extraction process ("frac-spread").

The majority of the Extraction Business' cash flow is stable and is
supported by long-term cost of service or fee based contracts. The only
production exposed to a profit share is the propane-plus production at
the Cochrane Extraction plant. All three extraction plants have the
ability to re-inject the propane-plus barrels in the instance where the
frac-spread does not cover the operating cost of producing the
propane-plus barrels. This re-injection of the propane-plus at the
Cochrane extraction plant allows the Extraction Business to limit the
downside associated with the frac-spread exposure. There is no limit to
the upside associated with the frac-spread.

During the period August 1 through December 31, 2004, the actual market
frac-spread was $0.365 US/US Gallon. This frac-spread is based on a
barrel of propane-plus produced at the Cochrane Extraction Plant, the
Mont Belvieu, Texas NGL prices and the AECO natural gas prices. The
frac-spread realized by Inter Pipeline during this same period,
including the production hedged and unhedged, was $0.370 US/US Gallon.
This compares to the fifteen year historical average frac-spread of
$0.227 US/US Gallon. In 2004 the propane-plus sales at the Cochrane
plant, which are the only Partnership operations exposed to the
frac-spread, contributed approximately 16% of total Partnership EBITDA.



Volumes and Extraction Revenues

July 28, 2004 - December 31, 2004
-------------------------------------
(000's b/d) Ethane Propane Plus Total
------------------------------------------------------------------------
Cochrane 50.0 28.7 78.7
Empress V (100% basis) 15.6 10.1 25.7
Empress II 24.6 14.3 38.9
------------------------------------------------------------------------
Total 90.2 53.1 143.3
------------------------------------------------------------------------
------------------------------------------------------------------------


These three plants together processed approximately 4.1 Bcf/d of gas
during the period from July 28, 2004 to December 31, 2004.

The Extraction Business has generated $300.3 million in revenues since
it was acquired on July 28, 2004. Of the six major sales contracts, five
contracts have been re-negotiated and amended in 2004. Hedge
arrangements were entered into in September 2004 to mitigate the
frac-spread risk at the Cochrane plant. See the Off-Balance Sheet
Arrangements section for a further explanation.

Shrinkage and Operating Expenses

The shrinkage gas cost was $191.2 million for the period from July 28,
2004 to December 31, 2004. Shrinkage gas represents gas bought to
replace the value of the heat content extracted from the gas processed
at the gas plants. Operating and maintenance costs were $14.6 million
while fuel and power costs to produce the two revenue streams at the
three extraction facilities were $40.9 million.

CORPORATE

General and Administrative

The Partnership's general and administrative expenses totaled $10.4
million during 2004, which is a $2.8 million increase as compared to
$7.6 million the prior year. This increase is primarily attributable to
the costs associated with the Extraction Business acquisition, increased
staff levels, higher insurance premiums, and costs related to growth
initiatives.

Non-Cash Compensation

During 2004, the Partnership incurred non-cash compensation expense of
$10.6 million related to its Unit Incentive Option Plan ("UIOP")
compared to $3.7 million in 2003. New grants and an increase in the
number of vested options, offset by exercises and cancellations,
resulted in a net increase in the number of eligible vested options
outstanding. This was further impacted by an increase in the
Partnership's Class A unit price from $7.76 per unit at December 31,
2003 to $9.16 per unit at December 31, 2004.

The non-cash compensation expense amount will likely rise and fall from
one reporting period to the next. It is primarily based on the number of
vested options outstanding multiplied by the difference between the
market price of the Class A unit at the end of the quarter versus the
exercise price of the options at the end of the same period, less what
has been recorded as an expense to date. Unit Incentive Options are
granted at various times in the year with one third of the grant vesting
immediately upon the grant, and the remaining two thirds vesting as to
one third on each of the subsequent two anniversary dates.

Depreciation and Amortization

The Partnership's depreciation and amortization of its operating and
intangible assets totaled $64.1 million in 2004, which is $9.5 million
higher than the $54.6 million charged in 2003. This increase is
attributable to the deprecation and amortization associated with the
operating and intangible assets of the Extraction Business, which were
$10.3 million since July 28, 2004.



Financing Charges

Year Ended
December 31
-----------------
(millions) 2004 2003
------------------------------------------------------------------------
Credit facility interest expense $ 9.7 $ 14.9
Interest on loan payable to General Partner 4.1 -
Debentures interest expense 4.9 12.0
------------------------------------------------------------------------
Cash related financing charges 18.7 26.9
Amortization of deferred financing costs 3.0 11.8
Accretion of discount on Debentures 0.5 1.2
------------------------------------------------------------------------
Total financing charges $ 22.2 $ 39.9
------------------------------------------------------------------------
------------------------------------------------------------------------


The Partnership incurred $9.7 million of total credit facility interest
expense during the year, compared to $14.9 million in the prior year.
The interest rate for the year ranged from a weighted average bankers
acceptance rate of 3.11% to a weighted average prime rate of 3.97% (2003
- 5.24% for bankers acceptances and 4.87% for prime rate). The weighted
average principal outstanding on the credit facilities was $232.3
million in 2004 (2003 - $241.2 million).

Inter Pipeline Fund borrowed $443 million on July 28, 2004, to partially
fund the acquisition of the Extraction Business. This bridge debt
facility and the outstanding balance on a $200 million unsecured
revolving credit facility were replaced by a combination of a $379.8
million loan payable to the General Partner and a new $400 million
revolving credit facility. Details of the loan payable to the General
Partner are provided below in the Liquidity section.

Debenture holders converted $71.2 million of Debentures into 11.9
million Class A units during 2004. Inter Pipeline Fund, therefore, only
incurred $4.9 million of interest expense in respect of its Debentures
during 2004 as compared to $12.0 million in 2003. Issue costs for the
Debentures are being amortized over their five year term adjusted for
conversions. The difference between the amount amortized over the five
year term and the amount adjusted for conversions is being included in
equity as these costs relate to the equity component of the Debentures.

The underwriting costs related to the General Partner's issuance of the
$379.8 million note issuance are being deferred and amortized over the
terms of the notes. The costs associated with the creation of the $400
million unsecured revolving credit facility have been deferred and are
being amortized over one year.

Excess cash, primarily from undistributed cash flow from operations, has
been applied to reduce debt.

Management and Acquisition Fees

Pipeline Management Inc. (the "General Partner") was paid a management
fee equivalent to 2% of "Operating Cash," as defined in the Partnership
Agreement. The fees of $3.4 million for 2004 are higher than the $2.4
million paid for 2003. This increase is due primarily to the addition of
the Extraction Business' Operating Cash beginning July 28, 2004.

During the year, pursuant to the terms of the Partnership Agreement, the
General Partner was also paid an acquisition fee of $7.2 million being
1% of the $715 million purchase price of the Extraction Business as
required by the Partnership Agreement. The General Partner was paid an
acquisition fee of $4.2 million in January of 2003 related to the
purchase of EnCana Corporation's 70% interest in the Cold Lake Pipeline
Limited Partnership.

Capital Expenditures

Of the $21.0 million capital expenditures made during the year, $14.2
million relates to the Partnership's 85% share of the Cold Lake Pipeline
System DilSynBit project. Actual final costs for the project were $18.7
million, compared to the previously announced $16 million, with the
Partnership's 85% interest being $15.9 million. The cost overruns were
due to certain scope changes, weather related issues and steel cost
escalation. The DilSynBit project was completed during October, 2004
with revenues beginning to accrue to the Partnership at that time.

The Partnership incurred costs of $3.1 million on the Bow South
Expansion. $3.7 million was spent on various other capital projects
during the year.



SUMMARY OF QUARTERLY RESULTS

2003
--------------------------------------------
First Second Third Fourth
(millions, except per Quarter Quarter Quarter Quarter
unit and % amounts) (b) (b) (b)
------------------------------------------------------------------------
Revenue
Pipeline Business $ 43.6 $ 42.5 $ 45.2 $ 45.5
Extraction Business(1) $ - $ - $ - $ -
Net income $ 2.0 $ 3.4 $ 6.4 $ 1.7
Per unit - basic and diluted $ 0.02 $ 0.04 $ 0.06 $ 0.01
Cash flow from operations(a)(1) $ 17.4 $ 23.6 $ 23.4 $ 24.4
Per unit - basic and diluted $ 0.20 $ 0.25 $ 0.21 $ 0.20
Cash distributions (a)(1)(2) $ 16.9 $ 20.0 $ 20.4 $ 22.3
Per unit (a) $ 0.18 $ 0.18 $ 0.18 $ 0.18
Payout ratio(a) 97.1% 84.7% 87.2% 91.4%
Partnership units outstanding
Weighted average 84.5 94.9 112.0 121.7
End of period 94.0 111.2 113.3 128.8


2004
--------------------------------------------
First Second Third Fourth
(millions, except per Quarter Quarter Quarter Quarter
unit and % amounts) (1)
------------------------------------------------------------------------
Revenue
Pipeline Business $ 43.3 $ 44.0 $ 48.1 $ 46.5
Extraction Business(1) $ - $ - $ 111.4 $ 188.9
Net income $ 9.1 $ 14.5 $ 18.8 $ 29.5
Per unit - basic and diluted $ 0.07 $ 0.10 $ 0.12 $ 0.17
Cash flow from operations(a)(1) $ 27.9 $ 27.7 $ 38.7 $ 55.9
Per unit - basic and diluted $ 0.21 $ 0.20 $ 0.23 $ 0.33
Cash distributions (a)(1)(2) $ 24.4 $ 25.1 $ 32.5 $ 33.7
Per unit(a) $ 0.18 $ 0.18 $0.1825 $0.1875
Payout ratio(a) 87.5% 90.6% 84.0% 60.3%
Partnership units outstanding
Weighted average 133.6 138.9 166.1 179.4
End of period 138.1 139.4 178.0 180.1


(a) Please refer to the "Non-GAAP Financial Measures" section of this
MD&A
(b) Restated

(1) The incremental change in the third quarter of 2004 is due to the
acquisition of the Extraction Business on July 28, 2004.
(2) Cash distributions are calculated based on the number of units
outstanding at each record date.



LIQUIDITY AND CAPITAL RESOURCES

Year Ended
December 31
-----------------
(millions, except for % amounts) 2004 2003
------------------------------------------------------------------------

Cash and cash equivalents $ 4.4 $ 3.8
------------------------------------------------------------------------
------------------------------------------------------------------------

Working capital, excluding cash $ 22.0 $ 16.4
------------------------------------------------------------------------
------------------------------------------------------------------------

Variable rate debt
Revolving credit facility $ 400.0 $ 210.0
Revolving credit facility - unutilized (249.0) (108.0)
------------------------------------------------------------------------
Revolving credit facility outstanding 151.0 102.0
Less variable rate debt swapped to fixed (62.0) (63.0)
------------------------------------------------------------------------
Total variable rate debt outstanding 89.0 39.0
------------------------------------------------------------------------

Fixed rate long-term debt
Loan payable to General Partner 379.8 -
Debentures 32.5 100.1
Add variable rate debt swapped to fixed 62.0 63.0
------------------------------------------------------------------------
Total fixed rate long-term debt outstanding 474.3 163.1
------------------------------------------------------------------------

Total debt and Debentures outstanding $ 563.3 $ 202.1
------------------------------------------------------------------------
------------------------------------------------------------------------

Senior debt to total capitalization 33% 11%
Total debt to total capitalization 35% 22%
------------------------------------------------------------------------
------------------------------------------------------------------------


Accounts receivable are collectable for both the Pipeline and Extraction
Businesses on the 25th of the following month pursuant to either
shipping regulations or contracts. This is consistent with general oil
and gas industry practice. Pursuant to the rules and regulations of
shipping oil on the Conventional Pipeline systems the Partnership has
the right to take the shippers oil in kind to settle any outstanding
receivable balance. The majority of contracts related to the Cold Lake
Pipeline System and the Extraction Business are with investment grade
counter parties. Therefore, management believes the risk of
non-collection of accounts receivable to be low.

On October 28, 2004, the General Partner completed a private placement,
in which it issued $379.8 million in notes to a combination of American
and Canadian institutional investors with the following terms:

- $91.2 million of 5.80 percent notes due 2012; and

- $288.6 million of 6.10 percent notes due 2014.

The proceeds from the note issuance were immediately loaned to the
Partnership by the General Partner to partially repay the $443 million
acquisition term bridge facility used to acquire the Extraction
Business. The General Partner was involved in this financing structure
as interest payments to the U.S. from a corporation are not subject to
withholding taxes. If the financing had not been structured in this
manner a 10% withholding tax would be applied.

The General Partner received an advanced tax ruling from the Canada
Revenue Agency confirming that there would be no withholding tax
requirements on interest payments to an American investor if it was paid
by a Canadian corporation (in this case, the General Partner). The
advanced tax ruling also indicated that to be in accordance with the
Income Tax Act (Canada) the "on-loan" to the Partnership would require a
nominal prescribed premium on the interest rate charged. Therefore, this
"on loan" to the Partnership from the General Partner has the identical
repayment terms and commitments, except for a nominal interest rate
increase of 0.05%. Inter Pipeline Fund has guaranteed the notes issued
by the General Partner to the note holders.

The Partnership has replaced its $200 million unsecured revolving credit
facility with a $400 million unsecured revolving credit facility at
generally more favorable terms. This expanded facility provides the
Partnership with flexibility to react quickly to growth opportunities.
As at December 31, 2004, $249 million of this facility was unutilized.

Of the total debt outstanding at year end, only $89.0 million is at a
variable rate of 3.44% with the remaining $441.8 million of fixed term
debt (excluding Debentures) having rates ranging from 5.41% to 6.31%.

Standard & Poor's continues to provide a credit rating for the
Partnership of "BBB".

The Partnership's contractual obligations due for the next five years
and thereafter are as follows:



Payments Due by Period
-----------------------------------------
Less than 1 to 3 4 to 5 After 5
(millions) Total one Year Years Years Years
------------------------------------------------------------------------
Credit facility $151.0 $ - $151.0 $ - $ -
Loan payable to General
Partner 379.8 - - - 379.8
Debentures 32.5 - 32.5 - -
Operating leases 9.5 1.3 3.9 2.2 2.1
------------------------------------------------------------------------
Total obligations $572.8 $ 1.3 $187.4 $ 2.2 $381.9
------------------------------------------------------------------------
------------------------------------------------------------------------

The Partnership is not committed to any material construction projects
at this time.


DISTRIBUTIONS TO UNITHOLDERS

The Limited Partnership Agreement defines a concept of Distributable
Cash which is required to be paid by the General Partner to unitholders.
The General Partner has the discretion to manage and control the
business of the Partnership and specifically, may establish cash
reserves that are determined to be necessary or appropriate for the
proper management of the Partnership. Changes to any such reserves may
be made by the General Partner at any time. Distributable Cash as
defined will fluctuate from time to time as a result of many factors,
including any such changes in reserves made by the General Partner in
the exercise of its discretion.

The definition of Distributable Cash includes different components. The
following table generally describes the sources and uses of cash leading
to cash distributions.



Year Ended
December 31
----------------------
(millions, except per unit and % amounts) 2004 2003
------------------------------------------------------------------------
Pipeline revenue, excluding accretion of
discount on Annual Service Contract
Recovery Amounts $ 181.8 $ 176.8
Extraction revenue 300.3 -
Shrinkage gas expense (191.2) -
Operating expense (101.0) (51.0)
General and administrative expense (10.4) (7.6)
Management fees expense (3.4) (2.4)
Acquisition fees expense (7.2) (4.2)
Credit facility interest expense (9.7) (14.9)
Loan payable to General Partner interest
expense (4.1) -
Interest on Debentures (4.9) (12.0)
Cold Lake Pipeline Limited Partnership
distribution of pre-2003 earnings - 4.1
------------------------------------------------------------------------
Cash flow from operations (a) 150.2 88.8
Net change in non-cash working
capital (16.4) (28.2)
------------------------------------------------------------------------
Cash provided by operating activities $ 133.8 $ 60.6
------------------------------------------------------------------------
------------------------------------------------------------------------

Cash distribtutions (a) $ 115.6 $ 79.6
------------------------------------------------------------------------
------------------------------------------------------------------------

Per unit $ 0.73 $ 0.72
------------------------------------------------------------------------
------------------------------------------------------------------------

Payout ratio(a) 77.0% 89.6%
------------------------------------------------------------------------
------------------------------------------------------------------------

Growth capital expenditures (a) $ 18.3 $ 13.7
Sustaining capital expenditures (a) $ 2.7 $ 2.2
------------------------------------------------------------------------
Total capital expenditures $ 21.0 $ 15.9
------------------------------------------------------------------------
------------------------------------------------------------------------
(a) Please refer to the Non-GAAP Financial Measures section of this
MD&A.


The 2004 payout ratio includes the one time $7.2 million acquisition fee
expense as well as the distribution of approximately $2.3 million paid
to the new unitholders of the 38.0 million units issued on July 28,
2004, which were eligible for the July 30, 2004 distribution record
date. The earnings from the acquired Extraction Business began to accrue
to the Partnership on July 28, 2004.

It is the intention of the General Partner of the Partnership to provide
unitholders with a stable flow of cash distributions. In this regard,
the General Partner has excluded from cash distributions certain
earnings of prior years, cash received from issuances of equity,
proceeds on the sale of assets and an amount equivalent to certain
Annual Service Contract Recovery Amounts. These amounts have been
reinvested in the business to effectively manage the balance sheet,
particularly debt levels, and remain available within the Partnership's
credit facilities should they ever be needed to maintain the monthly
distributions.

The strong frac-spread environment in the second half of 2004 has
allowed the Extraction Business to produce more cash flow than projected
in reliance on historic frac-spreads. This additional cash flow has been
applied to reduce short-term debt. The Partnership may draw on these
undistributed amounts in the future should frac-spreads move below
historic levels.



OUTSTANDING UNIT DATA

The Partnership units outstanding as at December 31, 2004 are
as follows:


(millions) Class A Class B Total
------------------------------------------------------------------------
Units outstanding 179.9 0.2 180.1
Units reserved for issuance upon exercise
of vested Unit Incentive Options 2.1 - 2.1
------------------------------------------------------------------------
Units reserved for issuance upon conversion
of Debentures 5.4 - 5.4
------------------------------------------------------------------------

Approximately $5.9 million of the remaining Debentures have been
converted into 1.0 million Class A units subsequent to year end.


FINANCIAL INSTRUMENTS AND OFF-BALANCE SHEET ARRANGEMENTS

The Partnership utilizes derivative financial instruments to manage its
exposure to changes in power costs, interest rates, foreign currencies
and commodity prices. A derivative must be designated and effective to
be accounted for as a hedge. The gain or loss incurred on these
instruments is recognized in income in the same period as the hedged
transactions are settled.

Inter Pipeline's risk management policies are intended to minimize the
volatility of Inter Pipeline's exposure to commodity price risk and to
assist with stabilizing cash flow from operations. The Partnership
attempts to accomplish this primarily through the use of financial
instruments. Inter Pipeline is prohibited from using hedging instruments
for speculative purposes. All hedging policies are authorized and
approved by the Board of Directors.

The Partnership has four "off-balance sheet" financial instruments:
power price swap agreements, commodity price swap agreements, foreign
currency exchange contracts and interest rate swap agreements, all of
which are being accounted for as hedges.

PIPELINE BUSINESS

Power Prices

The Partnership has entered into power price swap agreements in respect
of 5.0 MW per hour for the period from January 1, 2004 through December
31, 2006 at an average price of $48.23 per MW.h. The mark-to-market
value of these contracts at December 31, 2004 is nil, due to the fact
that current market prices approximate the average price per the
agreements (December 31, 2003 - $0.2 million).

EXTRACTION BUSINESS

The following three financial instruments are used collectively to
mitigate the frac-spread risk.

Commodity Prices

The Partnership established a hedge program to sell certain quantities
of NGL products at fixed prices to third party counter parties and buy
related quantities of natural gas at fixed prices from third party
counter parties in order to manage commodity price ("frac spread") risk
in its Extraction Business. Contracts outstanding at December 31, 2004
to hedge NGL revenues fix NGL prices at amounts ranging from US$0.757 to
US$0.884 per US gallon for the period from December 2004 to September
2005 for quantities ranging from 1,358 to 13,666 barrels of NGL per day.
Contracts outstanding at December 31, 2004 to hedge natural gas
purchases fix natural gas prices at amounts ranging from $6.650 to
$7.462 per gigajoule for the period from December 2004 to September 2005
for quantities ranging from 5,161 to 49,032 gigajoules per day. The
mark-to-market value of the NGL and natural gas contracts at December
31, 2004 resulted in an unrealized gain of US$2.3 million and an
unrealized loss of $6.1 million, respectively. The Partnership was not
involved in this line of business in 2003.

Foreign Currency

The NGL price swap agreements are calculated based on US dollar prices.
Therefore, at December 31, 2004, the Partnership had outstanding foreign
exchange contracts to sell between US$5.2 and US$15.7 million Canadian
dollars at fixed rates ranging from US$0.764 to US$0.769 per Canadian
dollar in order to convert notional US dollar amounts related to the
hedged NGL revenues for the period December 2004 to March 2005. The
mark-to-market value of these contracts at December 31, 2004 results in
an unrealized gain of $1.6 million. There were no foreign currency
exchange contracts in place in 2003.

CORPORATE

Interest Rates

$62 million of the outstanding debt at December 31, 2004 is subject to a
continuing swap agreement, in which the floating rate bank debt has been
exchanged for an average fixed rate of 6.1%. The fair market value of
the remaining interest rate swap agreements aggregates to an unrealized
loss of $6.3 million at December 31, 2004 compared to $5.9 million at
December 31, 2003.

TRANSACTIONS WITH RELATED PARTIES

No revenue was earned from related parties for the years ended December
31, 2004 and 2003.

The Partnership has entered into a support agreement that enables the
Partnership to request the General Partner and its affiliates to provide
certain personnel and services to the General Partner to fulfill its
obligations to administer and operate the Partnership's business. Such
services are incurred in the normal course of operations and amounts
paid for such services are at fair value for the services provided.
Amounts due to/from the General Partner related to these services are
non-interest bearing and have no fixed repayment terms. Management fees
of $3.4 million and acquisition fees of $7.2 million were paid to the
General Partner in 2004 (2003 - $2.4 million and $4.2 million,
respectively). No amounts were paid in 2004 under the support agreement.

As described above in the Liquidity section, the Partnership has entered
into a loan agreement with the General Partner for $379.8 million.

CRITICAL ACCOUNTING ESTIMATES

The preparation of the Partnership's Consolidated Financial Statements
requires management to make judgements, estimates and assumptions about
future events, when applying generally accepted accounting principles
("GAAP"), that have a significant impact on the financial results
reported. These judgments, estimates, and assumptions are subject to
change as the future events occur or new information becomes available.
Readers should also refer to Note 1 of the Consolidated Financial
Statements for a list of the partnership's significant accounting
policies.

Intangible Assets

The TSA intangible asset is the estimated value, using a discounted cash
flow analysis, of the shipping agreements entered into with the Founding
Shippers on the Cold Lake Pipeline System as valued on January 2, 2003.
Although, the ship or pay portion of the TSA expires on December 31,
2011, the term of the TSA extends until the Partnership gives notice
that it forecasts it will earn less than $1 million of capital fees in
the year. After December 31, 2011 the Shippers may contract with a third
party to transport their dedicated petroleum after giving the
Partnership notice of at least 20 months prior to the effective date and
meeting certain conditions. The Partnership has the right to match any
new service offer from a third party. Therefore, this intangible asset
is being amortized on a straight line basis over the estimated service
life of 30 years of the Cold Lake Partnership's property, plant and
equipment to which the TSA relates as management believes it is likely
the contracts will be renewed into the future. Should the useful life of
the Cold Lake Pipeline System assets change or the likelihood of the
renewal of the TSA change, the amortization of the remaining balance
would change accordingly.

The Extraction Business Customer Contracts intangible asset represents
the estimated value of the contracts as at July 28, 2004 when the
Extraction Business was acquired. Although the contracts expire over a
period ranging from five years to twenty years this intangible asset is
being amortized over the estimated useful life of 30 years of the
Extraction facilities as management believes it is likely the contracts
will be renewed into the future. Should the useful life of the
Extraction facilities assets change or the likelihood of the renewal of
the Customer Contracts change the amortization of the remaining balance
would change accordingly.

Property, Plant and Equipment ("PP&E")

Included in PP&E are estimates of the life of the assets, whether or not
an impairment in their value has been incurred and depreciation methods.
Due to the value of the assets being depreciated the resulting
depreciation is a material amount in determining net income of the
Partnership.

GAAP requires that if the undiscounted value of the estimated future net
cash flows, combined with any estimated residual value, are less than
the carrying value of the asset, an impairment must be recognized in the
financial statements as a charge to earnings. Our Pipelines Business has
a long record of strong and stable cash flows and based on management's
estimates of future cash flows we have determined the carrying value of
the Pipeline Business PP&E to be appropriate. The estimated net future
cash flows of the recently acquired Extraction Business also support the
current carrying value of the Extraction Business PP&E.

The Conventional Pipeline Systems PP&E are being depreciated on a
declining balance method with rates ranging from 15 to 25 years. This
method was chosen by management at the inception of the Partnership to
attempt to match what was estimated to be the natural decline in the
reserve life of the areas that the pipelines serve. With the recently
announced Bow South Expansions, which may extend the useful life of the
Bow River Pipeline System as it evolves to a certain degree of a
transmission line versus a gathering line, management is analyzing
whether the Conventional PP&E should adopt the straight line method for
2005. The Cold Lake Pipeline System PP&E is being depreciated on a
straight line basis over 30 years, consistent with the intangible
assets. Although management believes the asset life could exceed 30
years as is typical with these types of assets, management felt 30 years
to be a conservative time period.

The newly acquired Extraction Business PP&E are being depreciated on a
straight line basis over 30 years, consistent with the intangible
assets. Although management believes the asset life could exceed 30
years as is typical with these types of assets, management felt 30 years
to be a conservative time period.

Asset Retirement Obligation

The accounting for asset retirement obligations is for the legal
obligations associated with the retirement of a tangible long-lived
asset that results from the acquisition, construction or development
and/or the normal operations of a long-lived asset. The retirement of a
long-lived asset includes its other than temporary removal from service,
including its sale, abandonment, recycling or disposal in some manner
but not its temporary idling. The fair value of a liability for an asset
retirement obligation is recognized in the period in which it is
incurred if a reasonable estimate of fair value can be made. The
liability accretes to its full value over time through charges to
income, or until the Partnership settles the obligation. In addition,
the asset retirement cost, equal to the estimated fair value of the
asset retirement obligation, is capitalized as part of the cost of the
related long-lived asset and depreciated over the asset's useful life.

The PP&E of the Pipeline Business consist primarily of underground
pipelines and above ground equipment and facilities. No amount has been
recorded for asset retirement obligations relating to these assets as it
is not possible to reasonably estimate the fair value of the liability
due to the indeterminate timing and scope of the asset retirements. As
the timing and scope of retirements become determinable for certain or
all assets, the fair value of the liability and the cost of retirement
will be recorded at that time. Pipeline operations will be charged with
any costs associated with the future site restoration of the pipeline
assets. The potential costs of future site restoration will be a
function of several factors, including regulatory requirements at the
time of abandonment, the size of the pipeline and the pipeline's
location. Abandonment requirements can vary considerably, ranging from
emptying the pipeline, to removal of the pipeline and reclamation of the
right-of-way.

The PP&E of the Extraction Business consist mainly of three extraction
plants. The Partnership's asset retirement obligation represents the
expected cost to be incurred upon the termination of operations and
closure of these active plant facilities. The amount of $8.5 million
will be accreted up over time at a rate of 5.3% per annum to its
estimated future value of $112.4 million.

Environmental Liabilities

Included in accrued liabilities is an amount for future environmental
liabilities on an undiscounted basis. Management has identified a number
of environmental projects that the Partnership is obligated to remediate
in the future, which were not accrued for in the past. Although the
existence of the obligation was known, an estimate of the amount was not
reasonably determinable due to difficulties in estimating the impact of
future regulatory requirements, future technology available and the
extent and nature of remediation required. Therefore, in the past, an
amount was only booked when the obligation existed and an amount could
be reasonably estimated. Under new accounting guidance adopted by the
Partnership (see "Generally Accepted Accounting Principles" below), an
accrual must be made when an obligation exists, and the entity should
make estimates using the regulations and technology available today.
Therefore, an undiscounted amount has been accrued in these financial
statements using management's best knowledge of sites requiring
remediation and the plans that would be put in place to clean up these
sites. The actual cash outlay to complete the remediation plans could
take place over a time period that may be in excess of 20 years.

Unit Based Compensation

Under the Partnership's UIOP, options to purchase Class A units may be
granted to directors, officers, employees, and consultants of the
General Partner. Options issued are accounted for in accordance with the
fair value method of accounting for unit-based compensation, and as such
the cost is charged to earnings and an offsetting amount added to the
Partners' equity accounts, based on an estimate of the fair value
determined by the difference between the market value and the adjusted
exercise price of the vested options. Consideration paid to the
Partnership upon the exercise of the options is credited to Partners'
equity.

The expense amount will change depending on number of vested options
outstanding and the difference in the fair value and the exercise price
at the reporting date. There is no direct-cash outlay related to the
UIOP expense.

CHANGES IN ACCOUNTING POLICIES

Generally Accepted Accounting Principles

In July 2003, the Canadian Institute of Chartered Accountants ("CICA")
issued a new Handbook section 1100 "Generally Accepted Accounting
Principles", which establishes standards for financial reporting in
accordance with generally accepted accounting principles ("GAAP"). It
defines primary sources of GAAP and requires that an entity apply every
relevant primary source. Industry practice is not included as a primary
source of GAAP and is also not included in the discussion of other
sources of GAAP. This section became effective for the Partnership
January 1, 2004, with the result that an amount of $4.0 million was
accrued for environmental liabilities at December 31, 2004.

General Standards of Financial Statement Presentation

In July 2003, the CICA issued a new Handbook section 1400 "General
Standards of Financial Statement Presentation" which clarifies what
constitutes "fair value presentation in accordance with GAAP" as
discussed in the new Handbook section 1100 "Generally Accepted
Accounting Principles". This section became effective for the
Partnership January 1, 2004, but does not have an impact on the
Partnership's reported results.

Impairment of Long Lived Assets

In November 2002, the CICA issued a new Handbook section 3063
"Impairment of Long-Lived Assets". This section establishes standards
for the recognition, measurement and disclosure of the impairment, if
any, of long-lived assets by following a two step process. The first
step determines when an impairment is recognized, and the second
measures the amount of the impairment. The provisions of this new
section became effective for the Partnership January 1, 2004 but do not
have an impact on the Partnership's Consolidated Financial Statements.

Asset Retirement Obligations

In January 2003, the CICA issued a new Handbook section 3110 "Asset
Retirement Obligations", which established the standards for the
recognition, measurement and disclosure of asset retirement obligations
and the related asset retirement costs. This new section focuses on the
recognition and measurement of liabilities for legal 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 section requires the recognition
of all legal obligations associated with the retirement, whether by
sale, abandonment, recycling or other disposal of an asset. This
liability must be recognized at its fair value in the period in which it
is incurred and the corresponding retirement costs are capitalized into
the carrying amount of the related asset. In subsequent periods, the
liability is adjusted for the accretion of the discount and any changes
in the amount or timing of the underlying future cash flows required for
its settlement. The asset retirement cost would be amortized to income
on a systematic and rational basis. Entities are required to disclose
certain key information about the liability. The provisions of this new
section became effective for the Partnership January 1, 2004. The impact
of this new standard has been outlined in note 12 of the Partnership's
Consolidated Financial Statements.

Financial Instruments

In January 2004, the CICA issued amendments to Handbook section 3860
"Financial Instruments". Under the new provisions of this section,
entities will now be required to account for certain financial
instruments that may be settled in cash or by an issuer's own equity
instruments at the issuer's discretion, as liabilities. The new
recommendations are effective for years beginning on or after November
1, 2004. The Partnership adopted these recommendations early and
implemented them for the year ended December 31, 2003.

Hedging Relationships

In November 2001 the Accounting Standards Board ("AcSB") of the CICA
issued an Accounting Guideline ("AcG") 13 "Hedging Relationships" that
specifies the circumstances in which hedge accounting is appropriate,
including the identification, documentation, designation and
effectiveness of hedges, and the discontinuance of hedge accounting. In
June 2003, the AcSB amended the guideline to clarify certain of the
requirements and provide additional application guidance. In December
2003 the AcSB released an implementation guide. In summary, the criteria
for a hedging relationship to satisfy hedge accounting conditions, at
inception of the hedging relationship, are as follows:

- The entity should have identified the nature of the risk(s) in
accordance with its strategy and have designated that hedge accounting
will be applied to the hedge relationship;

- The entity should have formal documentation of its risk management
objective and strategy, the hedging relationship, the method for
assessing the effectiveness of the relationship and the method for
accounting for the relationship; and

- The entity should have reasonable assurance that the relationship will
be effective.

This guidance is effective for years beginning on or after July 1, 2003.
The Partnership has been following this guidance for its 2004 hedging
activities.

Disclosure of Guarantees

In February 2003, the CICA issued AcG 14 "Disclosure of Guarantees",
which requires a guarantor to disclose significant additional
information about guarantees it has provided, without regard to whether
it will have to make any payments under the guarantees. AcG 14 applies
to agreements that contingently require the guarantor to make payments
to the guaranteed party based on another entity's failure to perform
under an obligation agreement. A guarantee includes an indirect
guarantee of the indebtedness of another party.

AcG 14 is effective for interim and fiscal years beginning on or after
January 1, 2003. The Partnership has disclosed its guarantees.

Variable Interest Entities

In June 2003, the CICA issued AcG 15 "Consolidation of Variable Interest
Entities" which requires enterprises to identify variable interest
entities in which they have an interest, determine whether they are a
primary beneficiary of such entities and if so consolidate them. For the
Partnership, the guideline's disclosure requirements are effective as of
January 1, 2004 with consolidation requirements being effective January
1, 2005. Giving consideration to the Partnership's current business
relationships, this guideline has no impact on the Partnership's
Consolidated Financial Statements.

BUSINESS RISKS

Management has summarized below, what it considers to be important
business risks which could potentially have a material impact on the
operations and financial results of the Partnership. The Partnership's
2004 Annual Information Form (the "AIF") contains a thorough description
of these and other risk factors associated with the Partnership's
business. The AIF should be read in conjunction herewith and is
incorporated by reference.

Pipeline Business Risks

Demand for Crude Oil

Over the long term, the Partnership's business will depend, in part, on
the level of demand for crude oil in the geographic areas in which
deliveries are made by its pipeline systems and the ability and
willingness of shippers having access or rights to utilize the pipelines
to supply such demand. The Partnership cannot predict the impact of
future economic conditions, fuel conservation measures, alternative fuel
requirements, government regulation or technological advances in fuel
economy and energy generation devices, all of which could reduce the
demand for crude oil.

Crude Oil Reserves

Future throughput on the Partnership's pipeline systems will depend on
the replacement of crude oil reserves in their service areas which is
dependent upon the success of producers operating in those areas in
exploiting their existing reserve bases and exploring for and developing
additional reserves. The reserves required to maintain the long term
profitability of the Partnership's pipeline systems supply cannot be
assured. While reserve additions and increased recovery rates
historically have tended to offset natural declines in crude oil
production in the areas serviced by the Partnership's pipeline systems,
the additions to conventional reserves in western Canada in recent years
have generally not been sufficient to offset natural declines in
production. If future reserve additions and increased recovery rates do
not offset natural declines in crude oil production in its services
areas, throughput on the Partnership's pipeline systems may be reduced.

Crude Oil Prices

A period of sustained low crude oil prices could lead to a decline in
drilling activity and production levels or the shutting-in or
abandonment of marginal wells. Crude oil price declines, without
compensating reductions in costs of production, may reduce or eliminate
the profitability of production in the service area of the Partnership's
pipeline systems. Drilling activity, production levels and shut-in or
abandonment decisions may also be affected by the availability of
capital to producers for drilling, allocation by producers of available
capital to drilling for oil as compared to natural gas, current or
projected crude oil price volatility, overall supply and demand
expectations and light-to-heavy oil price differentials. The
Partnership's conventional gathering business is particularly dependent
on producers' continuing crude oil exploration and development activity
in the service areas and on technological improvements increasing
recovery rates to offset natural declines in crude oil production.
Absent the continuation of drilling activities and technology
improvements applied in their service areas, the volumes of crude oil
transported on the Partnership's pipeline systems will decline over time
as reserves are depleted.

Supply Contracts

Except in the case of the Cold Lake Pipeline System, the Partnership's
transportation revenues have been and will continue to be derived
primarily from contracts or arrangements of 30 days duration or less
with producers in the geographic areas served by its pipeline systems.
There can be no assurance that such contracts will continue to be
renewed or, if renewed, will be renewed upon favourable terms to the
Partnership. The Partnership's supply contracts with producers in the
areas served by its conventional gathering systems are based on
market-based toll structures negotiated from time to time with
individual producers rather than the cost of service recovery-fixed rate
of return structures applicable to some other pipelines. The
Partnership's conventional gathering business is and will continue to be
subject to market competitive factors.

The Cold Lake Pipeline System is operated pursuant to long-term
contracts with shippers who have committed to utilizing the Cold Lake
Pipeline System and paying for such usage over the term of the contract.
The minimum annual toll revenues from the Cold Lake Pipeline System are
derived from the "ship-or-pay" provisions of the agreement dated October
5, 2000 between the Cold Lake Partnership and the Cold Lake Founding
Shippers (the TSA) which arrangements continue until 2011. The minimum
annual fee under these "ship-or-pay" provisions declines effective May
1, 2005 pursuant to the TSA. Although volumes that are shipped by the
Cold Lake Founding Shippers from the reserves dedication area while
under the TSA are generally committed to the Cold Lake Pipeline System,
the Cold Lake Founding Shippers may utilize alternative transportation
sources after 2011 (if certain minimum volume levels are maintained)
subject to the Cold Lake Partnership's right to match the alternative
proposal. Consequently, there is no assurance that the level of volumes
or revenues received from the Cold Lake Founding Shippers following the
end of the "ship-or-pay" period will be sustained. Further, the Cold
Lake Partnership can supplement its revenues by marketing excess
capacity on the Cold Lake Pipeline System to third parties, but there
can be no assurance that the Partnership will be successful in doing so.

Competition

The Partnership's conventional gathering pipelines are subject to
competition from trucking as well as other pipelines near their service
areas. Further, competing pipelines could be constructed in areas
serviced by the Pipelines. There can be no assurance that competition
from truck and/or other pipelines will not result in a reduction in
throughput on the Partnership's conventional gathering business.

Dependence on Connected Facilities

The Partnership's pipelines are connected to various third party
mainline systems such as the Enbridge, Express and Terasen pipelines as
well as refineries in the Edmonton area. Operational disruptions or
apportionment on those third party systems or refineries may prevent the
full utilization of the Pipeline assets.

Extraction Business Risks

Natural Gas Supply

The production of NGLs from the NGL extraction plants is largely
dependent on the quantity and composition of the NGLs within the natural
gas streams that supply the NGL extraction plants. The quantity and
composition of NGLs may vary over time. Factors such as an increased
level of natural gas processing conducted at field processing plants
upstream of the NGL extraction plants, or processing completed at any
new extraction plant constructed upstream of the NGL extraction plant or
changes in the quantity and composition of the natural gas produced from
the reservoirs that supply the NGL extraction plants could have a
material affect on NGL production from the NGL extraction plants.

Natural Gas Reserves

The volumes of natural gas processed at the NGL extraction plants depend
on the throughput of the Foothills/Northern Border System and
TransCanada Alberta System from which the NGL extraction plants source
their natural gas supply. Without reserve additions or other new sources
of gas supply, throughputs will decline over time as reserves are
depleted in the areas these pipeline systems service. Natural gas
producers in these service areas also may not be successful in exploring
for and developing additional reserves, or commodity prices may not
remain at a level that encourages gas producers to explore for and
develop additional reserves or to produce existing marginally economic
reserves. In addition, the pipeline systems that service the NGL
extraction plants may also face competition from other existing or
proposed natural gas transmission systems that are not or will not be
connected to the NGL extraction plants, resulting in unprocessed natural
gas bypassing the NGL extraction plants. Also, in order to continue to
be entitled to extract NGLs from natural gas being transported on the
natural gas transmission systems straddled by the NGL extraction plants,
the Partnership will be required to continue to negotiate extraction
agreements with the various natural gas shippers holding the rights to
such NGLs from time to time, and there is no assurance that the
Partnership will be able to renew contracts of the Extraction Business
to extract NGLs on economic terms or at all.

Dependence on Connected Facilities

The Partnership's straddle plants are connected to various third party
trunkline systems including the TransCanada Alberta System,
Foothills/Northern Border System, Kerrobert Pipeline, Co-Ed Pipeline and
AEGS. Operational disruptions or apportionment on those third party
systems and/or disruptions may prevent the full utilization of the
acquired straddle plants.

Competition

The Extraction Business is subject to competition from other extraction
plants that are in the general vicinity of the NGL extraction plants or
that may be constructed "upstream" of the NGL extraction plants. The
Extraction Business is also subject to competition from field processing
facilities that extract NGLs from the natural gas streams before
injection into the TransCanada Alberta or Foothill/Northern Border
Systems.

To the extent that other existing or newly constructed extraction or
field processing plants are successful in securing natural gas supply
currently processed at the NGL extraction plants, or are successful in
removing significant amounts of NGLs from the gas supply "upstream" of
the NGL extraction plants, this will adversely affect the Partnership's
revenues and operating results.

Similarly, there is no assurance that new sources of natural gas supply
that may be developed in frontier areas such as Alaska and the Mackenzie
Delta in the Northwest Territories will be transported via the natural
gas transmission systems straddled by the NGL extraction plants or that
new extraction plants will not be constructed "upstream" of the NGL
extraction plants to process that natural gas.

Commodity Price; Frac-Spread

The Partnership's exposure to commodity price risk applies to the profit
share component of the propane-plus production at the Cochrane
Extraction Plant. The Partnership is exposed to the relative price
differential between the NGL produced and the shrinkage gas used to
replace the heat content removed during extraction of the NGL from the
natural gas stream. The amount of profit made from this portion of the
Extraction Business will increase or decrease as the difference between
the price of the applicable NGL and the price of natural gas varies.

Extraction Rights

One of the elements affecting the amount of profit made from the
Extraction Business is the cost of the compensation the Partnership will
need to provide under extraction rights agreements with gas shippers
under which the Extraction Business obtains the right to extract NGLs
from the natural gas throughput of the facilities. This compensation is
typically comprised of the obligation to supply shrinkage gas (or
sometimes to pay for shrinkage), and frequently there is also a fee or
premium paid to the supplier for the extraction right. Currently, the
cost of supplying shrinkage gas is the most significant element in the
extraction rights compensation. Although historically it has been
possible to obtain extraction rights for moderate fee premiums, it is
possible that the fee premiums associated with extraction rights
contracts could increase, which would adversely affect the margin and
profits of the Extraction Business. A reduction in the margin and
profits of the Extraction Business could materially and adversely affect
the business, financial condition, liquidity, results of operations and
Distributable Cash of the Partnership, thereby resulting in a decrease
in cash distributions to unitholders.

Reliance on Dow Chemical, NOVA Chemicals and BP Canada Energy

Dow Chemical Canada Inc., NOVA Chemicals Corporation and BP Canada
Energy Resources Company are the principal customers of the Extraction
Business and represent the vast majority of the accounts receivable of
the Extraction Business. BP Canada Energy also operates the Empress II
and Empress V plants. If for any reason these parties were unable to
perform their obligations under the various agreements with the
Partnership, the revenue and distributions of the Partnership, or the
operations of the Empress II and V facilities could be negatively
impacted.

Common Risks to Both the Pipeline and Extraction Businesses

Regulatory Intervention and Changes in Legislation

The NGL extraction facilities and pipelines can be subject to common
carrier and common processor applications and to rate setting by
regulatory authorities in the event agreement on fees or tariffs cannot
be reached with producers, shippers and other customers. To the extent
that producers, shippers or other customers believe processing fees or
tariffs are too high, they may seek rate relief through regulatory means.

Although the fees charged to customers of the Pipeline or the Extraction
businesses have not been set or restricted by any regulatory agency, an
application to the AEUB for the setting of fees could result in a
reduction of fees and decreased revenues to the Partnership. Income tax
laws relating to the oil and natural gas industry or the Partnership,
environmental and applicable operating legislation, and legislation and
regulatory rules governing the oil and natural gas industry, including
rights to NGLs and their extraction may be changed in a manner which
adversely affects the operations or financial results of the Partnership.

Environmental Costs and Liabilities

The operations of the Partnership are subject to Canadian federal,
Alberta and Saskatchewan laws and regulations relating to environmental
protection and Canadian federal, Alberta and Saskatchewan provincial
laws and regulations relating to operational safety. Operation of
certain of the Pipeline and Extraction businesses assets has spanned
several decades. While the remediation of releases or contamination
during such period may have met then-current environmental standards,
such remediation may not meet current or future environmental standards
and historical contamination may exist for which the Partnership may be
liable. The Partnership has completed internal environmental reviews
that have attempted to identify locations of historic contamination and
several locations have been remediated. These reviews may not have
identified all locations of historic contamination. The remaining
identified but unremediated sites will be addressed in a prioritized
manner utilizing industry practices with some locations having
multi-year restoration plans.

It is possible that other developments, such as increasingly strict
environmental and safety laws, regulations and enforcement policies
thereunder, and claims for damages to property or persons resulting from
the Partnership's operations and previously undiscovered locations of
historical contamination, could result in substantial costs and
liabilities to the Partnership. If, at any time, regulatory authorities
deem any one of the acquired NGL extraction plants unsafe, they may
order it shut down. If the Partnership was not able to recover such
resulting costs through insurance or increased tolls, distributions to
Class A unitholders could be adversely affected.

While the Partnership maintains insurance in respect of damage caused by
seepage or pollution in amounts it considers prudent and in accordance
with industry standards, certain provisions of such insurance may limit
the availability thereof in respect of certain occurrences unless they
are discovered within fixed time periods (typically 10 days under the
Partnership's current insurance policies). If the Partnership is unaware
of a problem or is unable to locate the problem within the relevant time
period, insurance coverage may not be available.

Abandonment Costs

The Partnership is responsible for compliance with all laws, regulations
and relevant agreements regarding the abandonment of the Pipeline
Systems assets (including, indirectly, its proportionate share of costs
relating to the Cold Lake Pipeline Limited Partnership) and the
Extraction Businesses plant assets at the end of their economic lives
which abandonment costs may be substantial. Abandonment costs are a
function of regulatory requirements at the time of abandonment, the
characteristics (such as diameter, length and location) of the pipeline
or the size and complexity of the straddle plant.

The General Partner may, in the future, determine it prudent to
establish and fund one or more reclamation trusts to address anticipated
abandonment costs. The payment of the costs of abandonment of the
Pipeline Business assets and Extraction Business assets, or the
establishment of reserves for that purpose, would decrease Distributable
Cash, thereby resulting in a decrease in cash distributions to
unitholders.

Leverage

Borrowings made by the General Partner on behalf of the Partnership
introduce leverage into the Partnership's business which increases the
level of financial risk in the operations of the Partnership and, to the
extent interest rates are not fixed, increases the sensitivity of
distributions by the Partnership to interest rate variations.

NON-GAAP FINANCIAL MEASURES

Certain financial measures referred to in this MD&A, namely "cash flow
from operations", "cash flow from operations per unit", "Distributable
Cash", "cash distributions", "EBITDA", "payout ratio", "growth capital
expenditures" and "sustaining capital expenditures" are not measures
recognized by Canadian generally accepted accounting principles
("GAAP"). These non-GAAP financial measures do not have standardized
meanings prescribed by GAAP and therefore may not be comparable to
similar measures presented by other entities. Investors are cautioned
that these non-GAAP financial measures should not be construed as
alternatives to other measures of financial performance calculated in
accordance with GAAP.

The following non-GAAP financial measures are provided to assist
investors in determining the ability of the Partnership to generate cash
and fund the monthly distributions. Management considers these non-GAAP
financial measures to be important indicators in assessing its
performance.

Cash flow from operations is reconciled from net income as seen on the
Consolidated Cash Flow Statement and is expressed before changes in
non-cash working capital.

Cash flow from operations per unit is calculated on a weighted average
basis using basic units outstanding during the year.

Distributable Cash is an amount calculated in accordance with the terms
of the Partnership Agreement.

Cash distributions are declared by the Board of Directors and are
currently paid on a monthly basis to unitholders.

EBITDA is reconciled from net income by adding back depreciation and
amortization, financing charges, non-cash compensation expense,
acquisition fees, and future income taxes and is calculated on an
annualized basis.

Payout ratio is calculated by expressing cash distributions for the year
as a percentage of cash flow from operations for the year.

Enterprise value is calculated by multiplying the year-end closing unit
price by the total number of Partnership units outstanding plus
long-term debt plus the debt portion of the Debentures.

Total unitholder return is calculated by taking the difference between
the end of the year market price and the beginning of the year market
price and dividing it by the beginning of the year market price. To this
return yield is added the yield obtained by dividing the cash
distributions per unit for the year by the beginning of the year market
price to obtain the overall return.

Growth capital expenditures are generally defined as expenditures that
are related to system expansions, business growth and/or revenue
increases.

Sustaining capital expenditures are generally defined as expenditures
that involve an enhancement to existing assets without any associated
increase in revenues, or new assets that provide support to operations
without any associated increase in revenue.

ADDITIONAL INFORMATION

Additional information relating to the Partnership, including the
Partnership's Annual Information Form, is available on SEDAR at
www.sedar.com.

Dated at Calgary, Alberta this 24th day of February, 2005.

Disclaimer

This Management's Discussion and Analysis ("MD&A") highlights
significant business results and statistics for Inter Pipeline Fund's
year ended December 31, 2004. This information may contain
forward-looking statements that involve risks and uncertainties. Such
information, although considered reasonable by the General Partner of
Inter Pipeline Fund at the time of preparation, may prove to be
incorrect and actual results may differ materially from those
anticipated. For this purpose, any statements that are not statements of
historical fact may be deemed to be forward-looking statements.
Forward-looking statements often contain terms such as "may", "will",
"should", "anticipate", "expects" and similar expressions. Such risks
and uncertainties include, but are not limited to, risks associated with
operations, such as loss of markets, regulatory matters, environmental
risks, industry competition and the ability to access sufficient capital
from internal and external sources. Inter Pipeline Fund assumes no
obligation to update forward-looking statements should circumstances or
management's estimates or opinions change.

The MD&A has been reviewed and approved by the Audit Committee and the
Board of Directors of the General Partner.



Inter Pipeline Fund

CONSOLIDATED BALANCE SHEETS

As at December 31 2004 2003
------------------------------------------------------------------------
(thousands of dollars)

ASSETS
Current Assets
Cash $ 4,412 $ 3,826
Accounts receivable (note 20) 115,471 31,866
Prepaid expenses and other deposits 5,592 2,796
Current portion of Annual Service Contract
Recovery Amounts (note 5) 2,349 6,369
------------------------------------------------------------------------
Total Current Assets 127,824 44,857

Investment in Annual Service Contract
Recovery Amounts (note 5) - 2,230
Intangible and other assets (note 6) 379,562 90,334
Property, plant and equipment (note 7) 1,232,817 843,476
Deferred financing charges (note 8) 2,748 4,511
------------------------------------------------------------------------
Total Assets $ 1,742,951 $ 985,408
------------------------------------------------------------------------
------------------------------------------------------------------------

LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Distributable cash payable (note 9) $ 11,255 $ 7,727
Accounts payable and accrued liabilities
(notes 4 and 17) 90,125 16,907
------------------------------------------------------------------------
Total Current Liabilities 101,380 24,634
Long-term debt (note 10) 530,800 102,000
Convertible Debentures (note 11) 32,510 100,117
Asset Retirement Obligation (notes 2 and 12) 8,743 -
Environmental liabilities (note 4) 3,580 -
Future income taxes 1,007 669
------------------------------------------------------------------------
Total Liabilities 678,020 227,420
------------------------------------------------------------------------
Commitments and Contingencies (notes 4, 18 and 19)

Partners' Equity
Conversion feature on Convertible
Debentures (note 11) 1,395 4,478
Partners' Equity (note 13) 1,063,536 753,510
------------------------------------------------------------------------
Total Partners' Equity 1,064,931 757,988
------------------------------------------------------------------------
Total Liabilities and Partners' Equity $ 1,742,951 $ 985,408
------------------------------------------------------------------------
------------------------------------------------------------------------

Subsequent Events (notes 11 and 13)

See accompanying notes to the consolidated financial statements.


Inter Pipeline Fund

CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY

Years ended December 31 2004 2003
------------------------------------------------------------------------
Class A Class B
Limited Unlimited
Liability Liability
Partnership Partnership
Units Units Total Total
------------------------------------------------------------------------
(thousands of dollars)

Balance, beginning
of year $ 752,755 $ 755 $ 753,510 $ 482,848
Environmental
liabilities (note 4) (3,971) (4) (3,975) -
Net income for the year 71,909 72 71,981 13,588
Cash distributions
declared (115,478) (116) (115,594) (79,568)
Issuance of Partnership
units
Conversion of
Debentures (notes 11
and 13) 71,168 71 71,239 30,618
Issued under Dividend
Reinvestment and
Optional Unit
Purchase Plan
(note 13) 2,848 3 2,851 1,979
Issued under Unit
Incentive Option
Plan (note 14) 9,254 9 9,263 643
Equity issuances, net
of issue costs (note 13) 271,618 272 271,890 299,892
Amortization of
Convertible Debenture
issue costs (3,633) (4) (3,637) -
Unit-based compensation
(note 14) 6,002 6 6,008 3,510
------------------------------------------------------------------------
Balance, end of year $ 1,062,472 $ 1,064 $ 1,063,536 $ 753,510
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


Inter Pipeline Fund

CONSOLIDATED STATEMENTS OF NET INCOME

Years ended December 31 2004 2003
------------------------------------------------------------------------
(thousands of dollars)

REVENUES
Transportation revenue $ 181,814 $ 176,842
Extraction revenue 300,257 -
Accretion of discount on Annual Service
Contract Recovery Amounts (note 5) 288 586
------------------------------------------------------------------------
482,359 177,428
------------------------------------------------------------------------

EXPENSES
Shrinkage gas 191,176 -
Operating 100,958 51,024
General and administrative 10,393 7,610
Non-cash compensation expense (note 14) 10,639 3,739
Depreciation and amortization 64,057 54,612
Financing charges (note 15) 22,230 39,946
Management fee to General Partner 3,437 2,360
Acquisition fee to General Partner (note 2) 7,150 4,225
Future income taxes 338 324
------------------------------------------------------------------------
410,378 163,840
------------------------------------------------------------------------

NET INCOME $ 71,981 $ 13,588
------------------------------------------------------------------------
------------------------------------------------------------------------

Net income per Partnership unit (note 13)
Basic and Diluted $ 0.46 $ 0.13
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


Inter Pipeline Fund

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years ended December 31 2004 2003
------------------------------------------------------------------------
(thousands of dollars)

OPERATING ACTIVITIES
Net income $ 71,981 $ 13,588
Depreciation and amortization 64,057 54,612
Amortization of deferred financing charges
(note 15) 3,011 11,806
Accretion of discount on Debentures (note 15) 478 1,196
Non-cash compensation expense 10,639 3,739
Future income taxes 338 324
Accretion of discount on Annual Service
Contract Recovery Amounts (288) (586)
Cold Lake Pipeline Limited Partnership
distribution of pre-2003 earnings - 4,081
------------------------------------------------------------------------
Cash flow from operations 150,216 88,760
Net change in non-cash working capital (16,427) (28,169)
------------------------------------------------------------------------
Cash provided by operating activities 133,789 60,591
------------------------------------------------------------------------

INVESTING ACTIVITIES
Annual Service Contract Recovery Payment (note 5) 6,539 7,638
Expenditures on property, plant and equipment (20,997) (15,909)
Proceeds on sale of assets 910 77
Acquisition of the Extraction Business (note 2) (713,416) -
Assumption of cash on Extraction Business
acquisition (note 2) 3,677 -
Acquisition of Cold Lake Pipeline Limited
Partnership interest (note 3) - (427,218)
Assumption of cash on Cold Lake Pipeline
Limited Partnership acquisition and
change to proportionate consolidation - 16,599
Net change in non-cash working capital (1,211) 3,062
------------------------------------------------------------------------
Cash used in investing activities (724,498) (415,751)
------------------------------------------------------------------------

FINANCING ACTIVITIES
Cash distributions declared (115,594) (79,568)
Increase (decrease) in long-term debt,
net of repayments 428,800 (5,000)
Issuance of Partnership units,
net of issue costs 273,814 301,002
Cash received under Distribution Reinvestment
and Optional Unit Purchase Plan 999 899
Issuance of units under Unit Incentive
Option Plan 4,633 415
Deferred financing charges (note 8) (4,886) -
Net change in non-cash working capital 3,529 (10,423)
------------------------------------------------------------------------
Cash provided by financing activities 591,295 207,325
------------------------------------------------------------------------
Increase (decrease) in cash 586 (147,835)
Cash, beginning of year 3,826 151,661
------------------------------------------------------------------------
Cash, end of year $ 4,412 $ 3,826
------------------------------------------------------------------------
------------------------------------------------------------------------
Cash interest paid on bank loans
and Debentures $ 15,047 $ 28,187
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


Inter Pipeline Fund
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2004 and 2003
(tabular amounts in thousands of dollars, except per unit amounts)


Structure of the Partnership

Inter Pipeline Fund (the "Partnership") was formed as a limited
partnership under the laws of Alberta pursuant to an agreement dated
October 9, 1997 (the "Partnership Agreement"). Pursuant to the
Partnership Agreement, the General Partner is required to maintain a
0.1% interest in the Partnership. The Partnership is dependent on the
General Partner for the administration and management of all matters
relating to the operation of the Partnership. The Partnership is
comprised of two industry operating segments: Pipeline Business and
Extraction Business, as discussed below in the Segment Reporting policy.

Under the Partnership Agreement, the General Partner is entitled to
recover all direct and indirect expenses, including general and
administrative expenses, incurred on behalf of the Partnership. The
General Partner also receives an annual base fee equal to 2% of the
Partnership's annual "Operating Cash" as defined in the Partnership
Agreement. In addition, the General Partner is entitled to earn an
annual incentive fee of between 15% and 35% of the Partnership's annual
Distributable Cash in excess of $1.01 per unit to $1.19 per unit
respectively; an acquisition fee of 1.0% of the purchase price of any
assets acquired by the Partnership (excluding the pipeline assets
originally acquired); and a disposition fee of 0.5% of the sale price of
any assets sold by the Partnership.

The Partnership currently distributes, on a monthly basis, Distributable
Cash to holders of the Class A limited liability partnership units
("Class A units") and Class B unlimited liability partnership units
("Class B units") (collectively the "Partnership units"). Distributable
Cash is defined in the Partnership Agreement and generally means net
income of the Partnership, adjusted for non-cash items and further
adjusted for certain reserves, and is intended to allow the Partnership
to retain cash as required to meet its ongoing liquidity and capital
requirements.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The consolidated financial statements, which have been prepared in
accordance with Canadian generally accepted accounting principles, have
in management's opinion been properly prepared within reasonable limits
of materiality and the framework of the accounting principles described
below. Amounts are stated in Canadian dollars unless otherwise
indicated. Certain of the prior year's comparative figures have been
reclassified to conform with the current year's presentation.

The consolidated financial statements include the accounts of the
Partnership and its subsidiaries. The Partnership's investment in the
Cold Lake Pipeline Limited Partnership (the "Cold Lake Partnership") and
its general partner, Cold Lake Pipeline Ltd. are accounted for using the
proportionate consolidation method whereby the Partnership's 85%
proportionate share of assets, liabilities, revenues and expenses are
included in the accounts.

Segment Reporting

The Partnership determines its reportable segments based on the nature
of its operations, which is consistent with how the business is managed.
The Pipeline Business is primarily the transportation, storage and
processing of hydrocarbons. The Extraction Business consists of
processing natural gas to extract natural gas liquids including ethane
("C2") and a mixture of propane, butane and pentanes-plus ("C3+ mix").
The Partnership does not have any geographic segments as all operations
are in western Canada.

Revenue Recognition

Pipeline Business

Revenues associated with the transportation, storage and processing of
hydrocarbons on the conventional gathering systems are recognized as the
service is provided. The Cold Lake Partnership recognizes its capital
fee revenues based on services provided to each founding shipper with an
adjustment, if necessary, to reflect each shipper's minimum
"Ship-or-Pay" revenue commitment. In addition, the Cold Lake Partnership
recognizes an operating fee equivalent to substantially all of the Cold
Lake Partnership's operating costs.

Extraction Business

The Partnership recognizes revenue when the earnings process is
complete. This is generally when products are shipped to the customer in
accordance with the terms of the sales contract, title or risk of loss
has been transferred, and pricing is either fixed or determinable.

Investment in Annual Service Contract Recovery Amounts

The carrying value of the Partnership's investment in Annual Service
Contract Recovery Amounts is the present value of the future payments
discounted using a 5% per annum factor. An amount reflecting the
accretion of the interest component of the present value is included in
income. The carrying value of the investment is tested for impairment by
reviewing the financial reports and other public information of its
counterparties, to determine their financial ability to pay the
committed amounts. The Partnership reflects its remaining investment in
the Annual Service Contract Recovery Amounts as a short-term investment
with future receipts recorded as interest earned on the principal and a
recovery of the principal.

Intangible and other assets

Transportation Services Agreement

The Transportation Services Agreement ("TSA") is amortized on a
straight-line basis over the estimated service life of thirty years of
the Cold Lake Partnership's pipeline facilities and equipment to which
the TSA relates. The carrying value of the investment in this Agreement
is tested for impairment by reviewing the financial reports and other
public information of its counterparties, to determine their financial
ability to pay the committed amounts.

Customer contracts

The Extraction Business intangible assets consist of customer contracts
for the sales of C2 and C3+ mix. The contracts include fee-based
contracts, cost of service contracts and profit-sharing arrangements.
The value of these contracts is estimated to be realized over an average
period of thirty years, which is the period over which amortization is
being charged using the straight-line method.

Patent

A patent that is an operational process utilized in one of the
extraction facilities is being amortized over its remaining term of 14
years.

Property, plant and equipment

Pipeline facilities and equipment

Expenditures on the conventional gathering system's expansion and
betterments are capitalized. Maintenance and repair costs, as well as
pipeline integrity verification and repair costs, are expensed as
incurred. Depreciation of pipeline facilities and equipment commences
when the pipelines are placed in commercial operation and is provided on
a declining balance basis over their estimated service lives, which
range from 15 to 25 years. The service life for pipeline systems is
determined with reference, together with other factors, to the estimated
remaining life of the crude oil reserves expected to be gathered on the
particular pipeline systems.

The Cold Lake Partnership's property, plant and equipment consist of
pipelines and related facilities. Depreciation of the capital costs less
estimated salvage value is calculated on a straight-line basis over the
estimated service life of the assets which is 30 years.

Deferred receipt facilities expenditures

Expenditures incurred to design and construct crude petroleum receipt
facilities on the properties of third party operators, to be owned and
operated by the respective third party operators, have been capitalized
as they provide a benefit to the Partnership over the life of the
contracts with the third party operators. Such expenditures are referred
to as deferred receipt facilities expenditures. The costs are amortized
on a straight-line basis over a three-year period to coincide with the
initial three-year term of the agreements with the third party
operators. Amortization commences when the facilities begin commercial
operations.

Extraction plants and equipment

Plant, property and equipment of the Extraction business are comprised
primarily of three extraction plants and the equipment within them.
Expenditures on the plants' expansion or betterments are capitalized,
while maintenance and repair costs are expensed as incurred.
Depreciation of the extraction plants and additions thereto is charged
once the assets are placed in commercial operation, and is calculated
using the straight-line basis over the estimated useful life of the
assets which is thirty years.

Deferred financing charges

The commitment fees and associated underwriting costs related to the
Partnership's long-term debt are initially deferred and then are
amortized over the term of the related facility. When a facility is
repaid and cancelled, any associated unamortized costs are fully written
off in the same period as the cancellation.

The issue costs related to the Partnership's issuance of 10% Convertible
Extendible Unsecured Subordinated Debentures (the "Debentures") have
been deferred and are being amortized over the five year term of the
Debentures.

Convertible Debentures

The Debentures are classified as a liability with the exception of the
portion relating to its conversion feature which is classified as an
equity component, resulting in the carrying value of the Debentures
being less than their face value. This discount is being accreted over
the term of the Debentures utilizing the effective interest rate method
and the 11% interest rate implicit in the Debentures. The equity
component is reclassified to Partners' Equity at the time of conversion
of the Debentures into Class A units with the related interest expensed
as incurred and issue costs amortized over the term of the Debentures.

Asset Retirement Obligations

The accounting for asset retirement obligations is for the legal
obligations associated with the retirement of a tangible long-lived
asset that results from the acquisition, construction or development
and/or the normal operations of a long-lived asset. The retirement of a
long-lived asset is its other than temporary removal from service,
including its sale, abandonment, recycling or disposal in some manner
but not its temporary idling.

The fair value of a liability for an asset retirement obligation is
recognized in the period in which it is incurred if a reasonable
estimate of fair value can be made. The liability accretes to its full
value over time through charges to income, or until the Partnership
settles the obligation. In addition, the asset retirement cost, equal to
the estimated fair value of the asset retirement obligation, is
capitalized as part of the cost of the related long-lived asset, and
depreciated over the asset's useful life.

Pipeline Business

The property, plant and equipment of the Pipeline Business consist
primarily of underground pipelines and above ground equipment and
facilities. No amount has been recorded for asset retirement obligations
relating to these assets as it is not possible to reasonably estimate
the fair value of the liability due to the indeterminate timing and
scope of the asset retirements. As the timing and scope of retirements
become determinable for certain or all assets, the fair value of the
liability and the cost of retirement will be recorded. Pipeline
operations will be charged with any costs associated with the future
site restoration of the pipeline assets. The potential costs of future
site restoration will be a function of several factors, including
regulatory requirements at the time of abandonment, the size of the
pipeline and the pipeline's location. Abandonment requirements can vary
considerably, ranging from emptying the pipeline to removal of the
pipeline and reclamation of the right-of-way.

Extraction Business

The property, plant and equipment of the Extraction Business consist
mainly of three extraction plants. The Partnership's asset retirement
obligation represents the expected cost to be incurred upon the
termination of operations and closure of these active plant facilities.

Environmental liabilities

Liabilities for loss contingencies, including environmental remediation
costs, arising from claims, assessments, litigation, fines and
penalties, and other sources are recorded when it is probable that a
liability has been incurred and the amount of the assessment and/or
remediation cost can be reasonably estimated. Recoveries from third
parties which are likely of realization are separately recorded and are
not offset against the related environmental liability.

Income taxes

Under existing tax legislation, the Partnership is not subject to income
taxes directly. The limited partners and the General Partner are subject
to tax on their proportionate interests of the taxable income allocated
by the Partnership.

Future income taxes

The Partnership's future income tax liability arises due to its
proportionate consolidation of its 85% ownership in Cold Lake Pipeline
Ltd., the General Partner of the Cold Lake Partnership. Its future
income tax is based on differences between the accounting basis and tax
basis of the Cold Lake Pipeline Ltd's investment in the Cold Lake
Partnership. This is offset by Cold Lake Pipeline Ltd's accumulated
losses. The future tax liability is calculated using the substantively
enacted tax rates and laws that will be in effect when these temporary
timing differences are expected to reverse as required by the liability
method of accounting for income taxes. The effect of future changes in
income tax rates will be recognized in net income in the period in which
the change occurs.

Unit-based compensation

Under the Partnership's Unit Incentive Option Plan, options to purchase
Class A units are granted to directors, officers, employees and
consultants of the General Partner. Options issued are accounted for in
accordance with the fair value method of accounting for unit-based
compensation, and as such the cost is charged to earnings and an
offsetting amount added to the Partners' Equity accounts, based on an
estimate of the fair value determined by the difference between the
market value and the adjusted exercise price of the vested options.
Consideration paid to the Partnership upon the exercise of options is
credited to Partners' Equity.

Measurement uncertainty

The amounts recorded for depreciation of property, plant and equipment,
amortization of deferred receipt facilities expenditures and the
projections of future site restoration and abandonment costs are based
on estimates. By their nature, these estimates are subject to
measurement uncertainty and the effect on the financial statements of
changes in such estimates in future years could be significant.

Financial instruments

Financial instruments of the Partnership consist of cash, accounts
receivable, prepaid expenses and other deposits, Investment in Annual
Service Contract Recovery Amounts, Distributable Cash payable, accounts
payable and accrued liabilities, long-term debt and Debentures (see note
9). There are no material differences between the carrying amounts of
these financial instruments reported on the balance sheet and their
estimated fair values, with the exception of the Debentures.

Upon adoption of the new Accounting Guideline, Hedging Relationships,
the Partnership formally documents all relationships between derivative
financial instruments and hedged items, as well as the risk management
objective and strategy. The Partnership assesses, on an ongoing basis,
whether the derivative financial instruments continue to be effective in
offsetting changes in fair values or cash flows of the hedged
transactions. There was no impact on the consolidated financial
statements as a result of this.

The Partnership utilizes derivative financial instruments to manage its
exposure to market risks relating to power prices, commodity prices and
interest rates. The Partnership's policy is not to utilize derivative
financial instruments for speculative purposes, and procedures are in
place with respect to the required documentation and approvals required
for the use of derivative financial instruments.

Derivative contracts accounted for as hedges are not recognized in the
Consolidated Balance Sheets. Gaines or losses incurred on these
contracts are recognized in income in the same period as the hedged
transactions are settled. Should the hedges cease to be effective, the
fair value of the derivative financial instruments will be recognized as
a deferred asset or liability on the Consolidated Balance Sheets and the
recognition of the changes in fair value will be recognized in income.

2. ACQUISITION OF EXTRACTION BUSINESS

On July 28, 2004, the Partnership acquired interests in three natural
gas liquids ("NGL") extraction plants for $715 million less closing
adjustments and acquisition costs of $6.2 million, for a net cash
consideration paid of $713.4 million. The purchase was financed through
$443 million of long-term debt (note 10) and a portion of the proceeds
from the issuance of 38.0 million Class A units (note 13). Concurrent
with this transaction, an acquisition fee of $7.2 million was paid to
Pipeline Management Inc, the General Partner, pursuant to the terms of
the Partnership Agreement.

The acquisition was accounted for by the purchase method as at the
closing date of July 28, 2004. The Partnership allocated the Purchase
Price as follows:



Cash $ 3,677
Working capital deficiency (836)
Intangible assets - Customer contracts and patent 296,715
Property, plant and equipment 422,367
Asset retirement obligation (note 12) (8,507)
------------------------------------------------------------------------
$ 713,416
------------------------------------------------------------------------
------------------------------------------------------------------------


The working capital adjustment is still being finalized and therefore
the purchase price allocation is likely to be amended.

3. ACQUISITION - COLD LAKE PIPELINE LIMITED PARTNERSHIP

On January 2, 2003, the Partnership acquired an additional 70% interest
in the Cold Lake Partnership for total cash consideration of $427.2
million, inclusive of $2.7 million of acquisition costs and working
capital adjustments. In addition, an acquisition fee of $4.3 million was
paid to the General Partner pursuant to the terms of the Partnership
Agreement. With its resultant 85% interest in the Cold Lake Partnership,
the Partnership assumed the operating responsibilities for the Cold Lake
Pipeline system. At this date, the Partnership allocated the purchase
price of its 70% interest and its accumulated equity account reflecting
its 15% interest to the following assets and liabilities:



70% Interest 15% Interest
Acquired Acquired
January 2, October 5,
2003 2000
------------------------------------------------------------------------
Cash $ 14,242 $ 2,357
Working Capital (7,064) (1,600)
Investment in Annual Service Contract
Recovery Amounts 31,302 -
Intangible asset - Transportation
Services Agreement 86,918 6,629
Property, plant and equipment 302,104 64,737
Future income taxes (284) (61)
Annual Service Contract Recovery Obligation - (15,651)
------------------------------------------------------------------------
427,218 56,411
Distributions of pre-2003 earnings - 4,081
------------------------------------------------------------------------
$ 427,218 $ 60,492
------------------------------------------------------------------------
------------------------------------------------------------------------


In 2003, the Partnership received a $4.1 million cash distribution from
the Cold Lake Partnership related to its share of 2002 earnings. This
amount has been excluded from the related purchase price allocation as
the Partnership has included it in Cash Available for Distribution to
its unitholders.

4. ENVIRONMENTAL LIABILITIES

In 2004, the Partnership adopted a new Accounting Policy for recognition
of Environmental Liabilities, as required by the new accounting standard
in section 1100 of the CICA Handbook "Generally accepted accounting
principles." This new standard states that industry practice is not
considered to be a source of GAAP, and where a company's policy using
industry practice conflicts with GAAP, that policy should be changed to
conform with GAAP. Upon adoption of this new accounting policy, the
Partnership has recognized an estimate for environmental obligations.
Prior to the adoption, these types of liabilities had not been
recognized due to industry practice, and instead amounts incurred for
environmental remediation programs were expensed in the period incurred.
The impact of this adoption was to decrease Partners' Equity by $4.0
million, increase Accounts payable and accrued liabilities by $0.4
million and increase Environmental liabilities by $3.6 million. The
maximum of the estimated range of costs that could be incurred in the
future related to environmental liabilities is $10.1 million.

5. INVESTMENT IN ANNUAL SERVICE CONTRACT RECOVERY AMOUNTS

In 2004, the Partnership received net payments of $6.5 million (2003 -
$7.6 million), related to its net investment in the Annual Service
Contract Recovery Amounts. As at December 31, 2004, the following Annual
Service Contract Recovery Amounts remain to be paid by the Cold Lake
Partnership to the Partnership in priority to the distribution of its
earnings:



2005 $ 2,402
Less discount calculated at 5% per annum (53)
------------------------------------------------------------------------
$ 2,349
------------------------------------------------------------------------
------------------------------------------------------------------------

6. INTANGIBLE AND OTHER ASSETS

December 31, December 31,
2004 2003
------------------------------------------------------------------------
Accumulated
Depreciation Net Book Net Book
Cost & Amortization Value Value
------------------------------------------------------------------------
Transportation
Services Agreement $ 93,548 $ (6,441) $ 87,107 $ 90,334
Customer contracts 287,988 (4,000) 283,988 -
Patent 8,727 (260) 8,467 -
------------------------------------------------------------------------
$ 390,263 $ (10,701) $ 379,562 $ 90,334
------------------------------------------------------------------------
------------------------------------------------------------------------


7. PROPERTY, PLANT AND EQUIPMENT

December 31, December 31,
2004 2003
------------------------------------------------------------------------
Accumulated
Depreciation Net Book Net Book
Cost & Amortization Value Value
------------------------------------------------------------------------
Pipeline
facilities
and equipment $ 1,118,953 $ (318,907) $ 800,046 $ 828,850
Extraction plants
and equipment 422,416 (5,792) 416,624 -
Pipeline linefill 10,384 - 10,384 10,384
Spare parts 3,379 - 3,379 -
Deferred receipt
facilities
expenditures 5,575 (3,191) 2,384 4,242
------------------------------------------------------------------------
$ 1,560,707 $ (327,890) $1,232,817 $ 843,476
------------------------------------------------------------------------
------------------------------------------------------------------------


Pipeline facilities and equipment and deferred receipt facilities
expenditures include costs of $2.2 million (2003 - $3.9 million) and nil
amounts (2003 - $0.1 million), respectively, related to construction in
progress for which no depreciation or amortization has been recorded in
the current period.



8. DEFERRED FINANCING CHARGES

December 31, December 31,
2004 2003
------------------------------------------------------------------------
Accumulated Net Book Net Book
Cost Amortization Value Value
------------------------------------------------------------------------
Loan Payable to
General Partner $ 1,878 $ (27) $ 1,851 $ -
$400 million Unsecured
Revolving Credit
Facility 575 (96) 479 -
$443 million Unsecured
Non-Revolving Credit
Facility 2,434 (2,434) - -
Convertible Debentures 6,021 (5,603) 418 4,511
------------------------------------------------------------------------
$ 10,908 $ (8,160) $ 2,748 $ 4,511
------------------------------------------------------------------------
------------------------------------------------------------------------


9. DISTRIBUTABLE CASH PAYABLE

As at December 31, 2004, distributions of $11.3 million are payable,
representing 179,911,495 outstanding Class A units and 180,217
outstanding Class B units at $0.0625 per unit. (2003 - $7.7 million
payable representing 128,649,498 outstanding Class A units and 128,794
outstanding Class B units at $0.06 per unit).



10. LONG-TERM DEBT

December 31, December 31,
2004 2003
------------------------------------------------------------------------
Loan Payable to General Partner (a) $ 379,800 $ -
$400 million Unsecured Revolving Credit
Facility (b, c) 151,000 -
$200 million Unsecured Revolving Credit
Facility (b) - 102,000
------------------------------------------------------------------------
$ 530,800 $ 102,000
------------------------------------------------------------------------
------------------------------------------------------------------------


(a) On October 28, 2004, the Partnership borrowed $379.8 million from
the General Partner with the following terms:

- $91.2 million due 2012, 5.85%; and

- $288.6 million due 2014, 6.15%.

On this date, the General Partner had received $379.8 million by way of
a Private Placement note issuance to a combination of American and
Canadian institutional investors and immediately loaned the funds to the
Partnership. These proceeds were then used to partially repay the $443
million Unsecured Non-Revolving Facility used to acquire the Extraction
Business (note 2).

This loan to the Partnership from the General Partner has the identical
repayment terms and commitments as the notes payable by the General
Partner to the institutional note holders, except for a nominal interest
rate increase of 0.05% over the rates payable on the notes issued by the
General Partner. $1.9 million of financing costs were incurred by the
General Partner and charged to the Partnership, at which time they were
deferred (note 8).

Inter Pipeline Fund has ultimately guaranteed the notes issued by the
General Partner to the note holders. The guarantee would be exercised in
the event of default pursuant to the terms of the Note Purchase
Agreement.

(b) On October 29, 2004, the $200 million Unsecured Revolving Credit
Facility was replaced with a $400 million Unsecured Revolving Credit
Facility, which was utilized to repay a portion of the $443 million
Unsecured Non-Revolving Credit Facility. This facility enables funds to
be borrowed, repaid and reborrowed within the revolving period which
currently extends to October 24, 2005. The revolving period may be
extended for an additional 364 day period on an annual basis with the
agreement of the lenders. If the revolving period is not extended, the
facility converts to a non-revolving facility with a two-year maturity.
Amounts borrowed under this facility bear interest at a floating rate
based on bankers' acceptances plus 87.5 basis points provided the
Partnership maintains its current credit rating while fees on undrawn
amounts are equal to 17.5 basis points per annum. If the Partnership's
credit rating changes, the interest rate could increase by up to 87.5
basis points or reduce by up to 37.5 basis points.

(c) On July 28, 2004, the Partnership entered into a $443 million
Unsecured Non-Revolving Credit Facility which was fully utilized on that
date to partially fund the acquisition of the Extraction Business (note
2). This facility has a twelve month term and bears interest only on
drawn amounts at a floating rate based on bankers' acceptances plus 87.5
basis points. On October 28, 2004, this facility was fully repaid with
proceeds from the loan from the General Partner and the new $400 million
Unsecured Revolving Credit Facility. (see (a) and (e))

(d) On July 28, 2004, a $50 million Unsecured Demand Credit Facility for
letters of credit was obtained to be available for use by the Extraction
Business. No funds had ever been drawn on this facility and it was
cancelled on October 28, 2004.

(e) The Partnership also had a $10 million Demand Revolving Credit
Facility which was available from January 1, 2004 to October 28, 2004,
at which time it was cancelled.

(f) In 2004, the Partnership had a net increase of $428.8 million in its
long-term debt with the following summarizing its borrowings and
repayments for each of its credit facilities:



Borrowings Repayments
------------------------------------------------------------------------
Loan payable to General Partner
$91.2 million due 2012 $ 91,200 $ -
$288.6 million due 2014 288,600 -
Unsecured $400 million Revolving Credit
Facility 151,000 -
Unsecured $200 million Revolving Credit
Facility - (102,000)
$443 million Unsecured Non-Revolving Credit
Facility 443,000 (443,000)
------------------------------------------------------------------------
Total $ 973,800 $ (545,000)
------------------------------------------------------------------------
------------------------------------------------------------------------


(g) The Partnership had nil issued and outstanding letters of credit at
December 31, 2004 (2003 - nil).

11. 10% CONVERTIBLE EXTENDIBLE UNSECURED SUBORDINATED DEBENTURES

Effective December 18, 2002, the Partnership issued $138.0 million of
10% Convertible Extendible Unsecured Subordinated Debentures (the
"Debentures") for net proceeds of $132.5 million. The Debentures had an
initial maturity date of February 15, 2003, which was extended to
December 31, 2007, with the acquisition of the Cold Lake Partnership.

The Debentures bear interest at 10% per annum, payable semi-annually on
June 30 and December 31 of each year. The Debentures are not
collateralized and are subordinated to substantially all other
liabilities of the Partnership including the Partnership's credit
facilities.

The Debentures are convertible at the option of the holder into Class A
units at any time prior to December 31, 2007 at a conversion price of
$6.00 per Class A unit. The Debentures are not redeemable before
December 31, 2005. From January 1, 2006 to December 31, 2006, the
Debentures may be redeemed in whole or in part at the option of the
Partnership at a price equal to their principal amount plus accrued and
unpaid interest, provided that the market price of the Class A units is
not less than 125% of the $6.00 conversion price. Subsequent to December
31, 2006, the Debentures may be redeemed in whole or in part at the
option of the Partnership.

At the option of the Partnership, the repayment of the principal amount
of the Debentures may be settled with Class A units. The number of Class
A units to be issued upon redemption by the Partnership will be
calculated by dividing the principal by 95% of the market price. The
interest payable may also be settled with the issuance and sale of
sufficient Class A units to satisfy the interest obligation. At December
31, 2004, the Debentures outstanding had a fair market value of $48.7
million.



Discounted
Obligation,
net of Equity
accretion Component Total
------------------------------------------------------------------------
Balance at December 31, 2002 128,182 5,804 133,986
Conversions into Class A units in 2003 (29,261) (1,326) (30,587)
Accretion of discount 1,196 - 1,196
------------------------------------------------------------------------
Balance at December 31, 2003 $ 100,117 $ 4,478 $ 104,595
Conversions into Class A units in 2004 (68,085) (3,083) (71,168)
Accretion of discount 478 - 478
------------------------------------------------------------------------
Balance at December 31, 2004 $ 32,510 $ 1,395 $ 33,905
------------------------------------------------------------------------
------------------------------------------------------------------------


Subsequent to December 31, 2004, $5.9 million of the Debentures were
converted into 978,992 Class A units of the Partnership. To maintain its
required 0.1% interest in the Partnership, the General Partner acquired
989 Class B units at a price of $6.00 per Class B unit.

The determination of the equity component of the Partnership's
Debentures utilized the "Black Scholes model" based on the following key
assumptions:



Risk-free rate of return 4.06%
Expected volatility of Class A units trading value 20%
Expected cash yield of Class A units 10%
Expected term of conversion option to expiry 5 years


12. ASSET RETIREMENT OBLIGATIONS

The estimated costs for asset retirement obligations for the Extraction
Business include such activities as dismantling, demolition and disposal
of the facilities and equipment, as well as remediation and restoration
of the plant sites. The total undiscounted amount of estimated
expenditures expected to be incurred on closure of these active plants
is $112.4 million, which was calculated using an inflation rate of 2%
and an expected life of 40 years. A credit-adjusted risk-free rate of
6.7% was used to discount the estimated future cash flows. These
obligations are not expected to occur for many years and will be funded
from general partnership resources at that time.



The following table shows the movement in the liability for asset
retirement obligations:

2004
------------------------------------------------------------------------
Obligation at December 31, 2003 $ -
Additions to liabilities (note 2) 8,507
Accretion expense 236
------------------------------------------------------------------------
Obligation at December 31, 2004 $ 8,743
------------------------------------------------------------------------


At December 31, 2004, $0.4 million is included in accounts payable and
accrued liabilities for asset retirement obligations related to the
retirement of property, plant and equipment in the Pipeline Business.



13. PARTNERS' EQUITY

Units issued and outstanding
Authorized
Unlimited number of Class A limited liability units
Unlimited number of Class B unlimited liability units


Issued and Outstanding Class A Class B
Units Units Total
------------------------------------------------------------------------
Balance as at December 31, 2002 73,802,300 73,876 73,876,176
Issued on conversion of
debentures (note 11) 5,097,816 5,114 5,102,930
Equity issuance (a) 49,355,250 49,405 49,404,655
Issued under Distribution
Reinvestment and Optional Unit
Purchase Plan (c) 307,499 311 307,810
Issued under Unit Incentive
Option Plan (note 14) 86,633 88 86,721
------------------------------------------------------------------------
Balance as at December 31, 2003 128,649,498 128,794 128,778,292
Issued on conversion of
debentures (note 11) 11,861,304 11,916 11,873,220
Equity issuance (b) 37,950,000 37,989 37,987,989
Issued under Distribution
Reinvestment and Optional Unit
Purchase Plan (c) 372,580 385 372,965
Issued under Unit Incentive
Option Plan (note 14) 1,078,113 1,133 1,079,246
------------------------------------------------------------------------
Balance as at December 31, 2004 179,911,495 180,217 180,091,712
------------------------------------------------------------------------
------------------------------------------------------------------------


a) Issuance of units in 2003

On January 30, 2003 and February 24, 2003, the Partnership issued
16,135,000 and 2,420,250 Class A units, respectively, at a price of
$6.20 per Class A unit for net proceeds of $109.1 million. To maintain
the required 0.1% interest in the Partnership, the General Partner
acquired 18,574 Class B units at a price of $6.20 per Class B unit.

On June 26, 2003, the Partnership issued 17,000,000 Class A units at a
price of $6.35 per Class A unit for net proceeds of $102.4 million. To
maintain the required 0.1% interest in the Partnership, the General
Partner acquired 17,017 Class B units at a price of $6.35 per Class B
unit.

On November 10, 2003, the Partnership issued 13,800,000 Class A units at
a price of $6.75 per Class A unit for net proceeds of $88.3 million. To
maintain the required 0.1% interest in the Partnership, the General
Partner acquired 13,814 Class B units at a price of $6.75 per Class B
unit.

b) Issuance of units in 2004

On July 28, 2004 the Partnership issued 37,950,000 Class A units at a
price of $7.55 per Class A unit for net proceeds of $271.6 million. To
maintain the required 0.1% interest in the Partnership, the General
Partner acquired 37,989 Class B units at a price of $7.55 per Class B
unit.

c) Reinvestment and Optional Unit Purchase Plan

Pursuant to the Distribution Reinvestment and Optional Unit Purchase
Plan (the "Plan"), unitholders may elect to receive Class A units
instead of cash for payment of their distribution and/or purchase
additional units, at a price representing a 5% discount to the
weighted-average closing trading price for the 10 trading days
immediately preceding the distribution date. As a result, for 2004,
241,321 Class A units and 249 Class B units were issued with a value of
$1.9 million (2003 - 166,519 Class A units and 168 Class B units with a
value of $1.1 million), and a further $1.0 million in cash was received
for optional unit purchases of 131,259 Class A units (2003 - $0.9
million of cash received for 140,980 Class A units). To maintain the
required 0.1% interest in the Partnership, the General Partner acquired
136 Class B units (2003 - 143 Class B units) at the same discounted
price. Effective with the June, 2004 distributions, the 5% discount is
no longer available under the Plan with respect to purchasing additional
units, but remains in place for the reinvestment of distributions.


Calculation of Net Income per Partnership unit

Partnership units share equally on a pro rata basis in the allocation of
net income. The number of units outstanding is calculated using the
Treasury Stock method based on the weighted-average number of units
outstanding for the period as follows:




Years ended December 31
2004 2003
------------------------------------------------------------------------
Weighted-average units outstanding
- Basic 154,629,894 103,320,091
Effect of Debentures and unit options 1,536,916 20,951,040
------------------------------------------------------------------------
Weighted-average units outstanding
- Diluted (x) 156,166,810 124,271,131
------------------------------------------------------------------------
------------------------------------------------------------------------

(x) Net income per Partnership unit is anti-dilutive for both years
presented.


14. UNIT-BASED COMPENSATION PLAN

In 2003, the Board of Directors of the General Partner established a
Unit Incentive Option Plan (the "Plan") whereby 7,312,680 Class A units
have been reserved for issuance under the Plan. The exercise price of
the options is equal to the current market price at the date of grant,
subject to an incentive reduction. The options have a five-year term
with one third of the options vesting immediately on the date of grant
and one third on each of the first and second anniversary dates
thereafter.

The Plan provides for an incentive reduction in the exercise price of
the options by the amount by which the Partnership's total return per
unit in each calendar year exceeds a prescribed threshold return for
such calendar year. The threshold return is determined annually and is
equal to 350 basis points over the 10-year Canada bond rate multiplied
by the closing price of the units on the Toronto Stock Exchange (the
"TSX") at the beginning of the year. The total return is the sum of the
difference between the closing price of the units on the TSX at the end
of the year or on the date of exercise, and the exercise price on the
grant date, plus the cumulative dollar amount of distributions per unit
declared during the year.

Non-cash compensation expense of $10.6 million in 2004 was comprised of
$4.6 million due to option exercises (2003 - $0.2 million) and $6.0
million of a mark to market charge on exercisable options (2003 - $3.5
million).

The following table summarizes the status of the Partnership's Plan as
at December 31, 2004 and 2003, and changes during the years then ended:



Weighted-
Weighted- average
average adjusted
Number of exercise exercise
options price(x) price(xx)
------------------------------------------------------------------------
Options outstanding, January 1, 2003 - - -
Options granted 4,200,000 $ 6.42 $ 5.03
Options exercised (86,633) $ 6.20 $ 4.43
--------------------------------------------------
Options outstanding, December 31, 2003 4,113,367 $ 6.42 $ 5.05
Options granted 1,513,500 $ 8.17 $ 7.48
Options exercised (1,078,113) $ 6.39 $ 3.44
Options cancelled (195,674) $ 6.55 $ 3.86
--------------------------------------------------
Options outstanding, December 31, 2004 4,353,080 $ 7.04 $ 4.93
--------------------------------------------------
--------------------------------------------------
(x) The weighted-average exercise price based on the exercise price on
the date of grant.
(xx) The weighted-average exercise price adjusted for the incentive
reduction.


The following table summarizes information about unit options
outstanding at December 31, 2004:


Options outstanding

Weighted-
average Weighted-
remaining average
Range of adjusted Number of contractual exercise
exercise prices options life price(x)
------------------------------------------------------------
$2.93 - $3.97 2,176,542 3.1 years $ 3.11
$5.05 - $5.80 683,038 3.7 years $ 5.14
$6.20 - $8.82 1,493,500 4.7 years $ 7.49
------------------------------------------------------------
Total 4,353,080 3.8 years $ 4.93
------------------------------------------------------------
------------------------------------------------------------


Options exercisable

Weighted-
average
Range of adjusted Number of exercise
exercise prices options price(x)
---------------------------------------------
$2.93 - $3.97 1,181,524 $ 3.11
$5.05 - $5.80 381,014 $ 5.06
$6.20 - $8.82 487,798 $ 7.52
---------------------------------------------
Total 2,050,336 $ 4.52
---------------------------------------------
---------------------------------------------

(x) The weighted-average exercise price is shown for options
outstanding and exercisable at the end of the period, after
adjustment for the incentive reduction.



15. FINANCING CHARGES

2004 2003
------------------------------------------------------------------------
Interest expense (a, b) $ 9,674 $ 14,907
Interest on loan payable to General
Partner (note 10) 4,104 -
Interest on Debentures (note 11) 4,963 12,037
Amortization of deferred financing
charges (note 8),(c) 3,011 11,806
Accretion of discount on Debentures (note 11) 478 1,196
------------------------------------------------------------------------
Total financing expenses $ 22 230 $ 39,946
------------------------------------------------------------------------
------------------------------------------------------------------------


a) During 2004, the Partnership incurred $9.7 million in respect of
interest costs on its credit facilities (2003 - $14.9 million),
including $0.2 million in respect of fees on undrawn amounts (2003 -
$0.6 million), with its average interest rate for the year equating to
3.16% on average borrowings of $232.4 million (2003 - 5.2% on $241.2
million).

b) In 2004, the cash settlements on the interest rate swap contracts
were $2.4 million (2003 - $2.0 million).

c) The cost of arranging the Partnership's $460 million secured credit
facility, including commitment fees and legal fees, totaled $10.5
million and was charged to earnings during 2003 as these facilities were
cancelled on December 9, 2003.

16. SEGMENTED INFORMATION

The Partnership operates its business under the following principal
business segments:




2004
------------------------------------------------------------------------
Pipeline Extraction
Business Business Corporate Total
------------------------------------------------------------------------
Revenues 181,814 300,257 288 482,359
------------------------------------------------------------------------
Expenses
Shrinkage gas - 191,176 - 191,176
Operating 45,460 55,498 - 100,958
General and
administrative - - 10,393 10,393
Non-cash compensation
expense - - 10,639 10,639
Depreciation and
amortization 53,769 10,288 - 64,057
Financing charges - - 22,230 22,230
Management fee to
General Partner - - 3,437 3,437
Acquisition fee to
General Partner - - 7,150 7,150
Future income taxes - - 338 338
------------------------------------------------------------------------
99,229 256,962 54,187 410,378
------------------------------------------------------------------------

------------------------------------------------------------------------
Net income 82,585 43,295 (53,899) 71,981
------------------------------------------------------------------------
------------------------------------------------------------------------

------------------------------------------------------------------------
Expenditures on property,
plant and equipment (20,791) (206) - (20,997)
------------------------------------------------------------------------

Total Assets 968,660 774,291 - 1,742,951
------------------------------------------------------------------------
------------------------------------------------------------------------

Note: Prior to 2004, there was only one operating segment, the Pipeline
Business.


17. RELATED PARTY TRANSACTIONS

In 2004 and 2003, no revenue was earned from affiliates.

The Partnership has entered into a support agreement that enables the
Partnership to request the General Partner and its affiliates to provide
certain personnel and services to the General Partner to fulfill its
obligations to administer and operate the Partnership's business. Such
services are incurred in the normal course of operations and amounts
paid for such services are at fair value for the services provided.

Amounts due from/to the General Partner and its affiliates are
non-interest bearing and have no fixed repayment terms, with the
exception of the loan payable to the General Partner (note 10). At
December 31, 2004 and 2003 there were nil amounts owing to the
Partnership from the General Partner. At December 31, 2004, there were
amounts owed to the General Partner by the Partnership of $0.5 million
(December 31, 2003 - $0.7 million).

In addition, in 2004, there was $0.8 million incurred in the normal
course of operations for legal fees provided by a law firm at which a
Director is a Partner, (2003 - $0.3 million). At December 31, 2003,
there were no amounts included in accounts payable and accrued
liabilities owing to this related party (December 31, 2003 - nil).

18. COMMITMENTS

Minimum lease payments

The Partnership has entered into lease agreements for office space and
storage to April 30, 2013. The future minimum lease payments for this
and other lease agreements are:




2005 $ 1,350
2006 1,325
2007 1,281
2008 1,278
2009 1,294
Thereafter 2,949
-------------------------
$ 9,477
-------------------------
-------------------------


19. RISK MANAGEMENT

Frac spread risk management

In August 2004, the Partnership established a hedge program to sell
certain quantities of NGL products at fixed prices to third party
counter parties and buy related quantities of natural gas at fixed
prices from third party counter parties in order to manage commodity
price ("frac spread") risk in its extraction business. The NGL price
swap agreements are calculated based on US dollar prices. Therefore, the
Partnership has also entered into foreign exchange contracts to sell US
dollars in order to convert notional US dollar amounts related to the
hedged NGL revenues. Contracts outstanding at December 31, 2004 were as
follows:



Price Quantity
(US$/gallon) (bbl/day) Hedged Period
------------------------------------------------------------------------
NGL swaps 0.757 - 0.884 1,358 - 13,666 December 2004 -
September 2005
------------------------------------------------------------------------
Price Quantity
(Cdn$/GJ) (GJ/day) Hedged Period
------------------------------------------------------------------------
Natural gas
swaps 6.650 - 7.462 5,161 - 49,032 December 2004 -
September 2005
------------------------------------------------------------------------

Price Notional Amount
(US$/Cdn$) (US$) Hedged Period
------------------------------------------------------------------------
Foreign exchange
swaps 0.764 - 0.769 5,161 - 15,688 December 2004 -
March 2005
------------------------------------------------------------------------


The fair market value of the NGL, natural gas and foreign exchange swap
contracts at December 31, 2004 results in unrealized gains/(losses) of
US$2.3 million, $(6.1) million, and $1.6 million respectively. No
similar contracts were in place at December 31, 2003. The Partnership
has not recognized assets or liabilities associated with the swap
contracts because the hedging relationships meet the conditions for
hedge accounting.

The net settlements on the frac spread swap contracts recognized in
income were:



2004 2003
------------------------------------------------------------
NGL swaps $ (492) $ -
Natural gas swaps (1,028) -
Foreign exchange swaps 3,924 -
------------------------------------------------------------
Net settlement on frac spread swaps $ 2,404 $ -
------------------------------------------------------------
------------------------------------------------------------


Interest rate risk management

The Partnership has entered into a series of interest rate swap
agreements with a Canadian chartered bank to manage its interest rate
price risk exposure on floating rate bank loans. At December 31, 2004,
the swap agreements total $62 million (2003 - $63 million).



Fixed rate per annum Notional
Maturity date (excluding applicable margin) Balance
-----------------------------------------------------------------
September 30, 2006 5.41% $ 15,000
December 31, 2011 6.31% 15,000
December 31, 2011 6.30% 32,000
-----------------------------------------------------------------
$ 62,000
-----------------------------------------------------------------
-----------------------------------------------------------------


The fair market value of the outstanding swap contracts as at December
31, 2004, results in an unrecognized loss of $6.3 million (2003 - $5.9
million). The notional principal balance of the 6.30% swap amount is
reduced by $1 million per year for the term of the arrangement.

Power price risk management

The Partnership has two electricity price swap agreements, in respect of
5.0 million watts of electric power per hour ("MW.h") for the period
from January 1, 2004 to December 31, 2006 at an average price of $48.23
per MW.h. The fair market value of these contracts results in no
unrecognized gains or losses at December 31, 2004 as the average price
per the terms of the swap agreements approximates the market price
(December 31, 2003 - $0.2 million).

The net settlements on the electricity price swap contracts recognized
in income were $0.3 million (2003 - nil).

Credit risk management

Credit exposure on financial instruments arises from the possibility
that a counter-party in which the Partnership has an unrealized gain
fails to perform according to the terms of the contract. The Partnership
believes the risks of non-performance are minimal as the counter-party
on the interest rate, NGL, natural gas and foreign exchange swaps is a
major financial institution. The electricity price swaps are with
investment grade counter-parties.

20. MAJOR CUSTOMERS

In 2004, two customers of the Extraction Business accounted for 60%
(2003 - two customers of the Pipeline Business, 41%) of the
Partnership's consolidated revenue. The Partnership believes the
financial risk associated with these customers is minimal.


-30-

Contact Information