Inter Pipeline Fund
TSX : IPL.UN

Inter Pipeline Fund

August 11, 2005 13:34 ET

Inter Pipeline Fund Announces Second Quarter 2005 Results

CALGARY, ALBERTA--(CCNMatthews - Aug. 11, 2005) - Inter Pipeline Fund (TSX:IPL.UN) ("Inter Pipeline") announced today its financial and operating results for the three and six month period ended June 30, 2005.

Highlights

- Cash flow from operations(1) of $32.9 million, up $5.2 million over the same quarter last year

- Quarterly payout ratio(1) of 104%; year to date payout ratio(1) of 91% on target with anticipated full year payout ratio

- Transported 279,200 barrels per day (b/d) on the Cold Lake pipeline system, up 36,200 b/d, or 15% over the second quarter of 2004

- Announced 30,000 b/d of firm shipping commitments on Bow River pipeline system in support of latest capacity expansion project

- Received an upgraded outlook on Inter Pipeline's corporate credit rating from Standard & Poor's

(1) Please refer to the "Non-GAAP Financial Measures" section of the MD&A.

Cash Flow

In the second quarter of 2005, Inter Pipeline generated cash flow from operations ("cash flow") of $32.9 million, representing an increase of 18.5% over the same period last year. This increase was primarily the result of the cash flow contribution from Inter Pipeline's natural gas liquids (NGL) extraction business, which was acquired in July, 2004.

During the quarter, Inter Pipeline's NGL extraction business contributed $15.1 million to cash flow and the pipeline business generated $29.8 million. Corporate charges, including interest expense, totaled $12.0 million.

"Second quarter cash flow was impacted by seasonal factors which typically result in lower NGL extraction and pipeline throughput volumes during the spring and early summer months, " commented David Fesyk, President and Chief Executive Officer. "Our operations were also impacted by several severe weather incidents during the month of June."

Cash Distributions

Cash distributions to unitholders during the quarter totaled $34.2 million, or $0.1875 per unit, representing 104.2% of cash flow. This quarterly payout ratio is higher than expected primarily as a result of lower pipeline transportation and Cochrane throughput volumes.

Monthly cash distributions are currently $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.

Pipeline Business

Throughput volumes on the Cold Lake pipeline system averaged 279,200 b/d, during the second quarter, representing an increase of 36,200 b/d over delivery rates achieved in the second quarter of 2004. Producers in the Cold Lake region continue to advance plans to further expand oil sands production.

Throughput volumes on Inter Pipeline's four conventional oil pipeline systems averaged 198,400 b/d during the second quarter, compared to 214,000 b/d for the same period last year. Pipeline operations were adversely affected by severe wind and flooding conditions in southern Alberta during the quarter. These conditions directly impacted truck deliveries to Inter Pipeline's crude oil terminals. Harsh weather also disrupted production operations at several pipeline connected field sites, in part due to temporary power outages. Throughput volumes are expected to return to normal levels in the third quarter.

During the quarter, Inter Pipeline successfully completed an "open season" tendering process to solicit shipper support to expand capacity on the Bow River pipeline system. Inter Pipeline received firm shipping commitments totaling 30,000 b/d. This level of support will allow Inter Pipeline to proceed with a planned $8.5 million expansion to increase mainline capacity on the Bow River system. Oil shipments will originate at the crude oil storage hub at Hardisty, Alberta for southbound delivery to interconnecting carriers near the Montana border.

Extraction Business

Inter Pipeline's NGL extraction facilities produced an average of 128,900 b/d of NGL's in the quarter, comprised of 83,200 b/d of ethane and 45,700 b/d of propane plus. Lower than average production volumes were primarily the result of reduced natural gas throughput volumes at the Cochrane NGL extraction plant. Downstream demand for natural gas, particularly in the California utility market, typically decreases in the second quarter. Gas processing rates at the Cochrane facility are expected to recover with the commencement of the summer cooling season.

Production volumes were also impacted by a severe wind storm that caused a shut down of the Empress II and Empress V extraction facilities in June. Subsequent to quarter-end, repair work has been completed and these facilities are now fully operational. Inter Pipeline's cash flow during the quarter was not materially impacted by the storm-related disruption to operations at Empress.

Financing Activity

At quarter end, Inter Pipeline's outstanding debt balance, including convertible debentures, was $517.2 million, resulting in a total debt to total capitalization ratio of 33%. During the quarter, Standard & Poor's upgraded Inter Pipeline's BBB corporate credit rating to a stable outlook from a negative outlook.

Conference Call

Inter Pipeline will hold a conference call on Friday, August 12, 2005 at 9:00 a.m. (Mountain Time) / 11:00 a.m. (Eastern Time) to discuss its second quarter 2005 financial and operating results.

To participate in the conference call, please dial 800-446-4498 or 416-695-9721. A recording of the call will be available for replay until August 19, 2005, by dialing 888-509-0082 or 416-695-5275. Pass codes are not required.



Selected Financial and Operating Highlights

------------------------------------------------------------------------
Three Months Ended Six Months Ended
(millions of dollars, June 30, June 30,
except where noted) 2005 2004 2005 2004
------------------------------------------------------------------------
Extraction Production(1)
(000 b/d)
Ethane 83.2 n/a 91.6 n/a
Propane Plus 45.7 n/a 51.4 n/a
----- -----
Total Extraction 128.9 143.0

Pipeline Volumes (000 b/d)
Conventional 198.4 214.0 202.5 214.3
Cold Lake Pipeline(1) 279.2 243.0 291.0 245.0
----- ----- ----- -----
Total Pipeline 477.6 457.0 493.5 459.3

Revenue
Extraction $ 144.8 n/a $ 315.4 n/a
Conventional Pipeline $ 26.5 $ 26.2 $ 53.6 $ 52.3
Cold Lake Pipeline $ 15.1 $ 17.8 $ 30.1 $ 34.9

Net Income $ 13.1 $ 14.5 $ 35.7 $ 23.6

Cash Flow From
Operations(2) $ 32.9 $ 27.7 $ 75.1 $ 55.6

Cash Distributions(2) $ 34.2 $ 25.1 $ 68.2 $ 49.4
Per Unit $0.1875 $0.1800 $0.3750 $0.3600

Payout Ratio(2) 104.2% 90.4% 90.9% 88.9%

Capital Expenditures(2)
Growth $ 0.5 $ 5.8 $ 2.1 $ 8.9
Sustaining $ 1.1 $ 0.4 $ 2.6 $ 0.6

1. Volumes reported on a 100% basis.
2. 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.

Eligible 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.

All dollar values are expressed in Canadian dollars unless otherwise noted.

MANAGEMENT'S DISCUSSION AND ANALYSIS FOR THE SECOND QUARTER OF 2005

The following Management's Discussion and Analysis ("MD&A") provides a detailed explanation of Inter Pipeline Fund's ("Inter Pipeline") operating results for the three and six month periods ended June 30, 2005 as compared to the three and six month periods ended June 30, 2004. The MD&A should be read in conjunction with the unaudited interim consolidated financial statements of Inter Pipeline for the three and six month periods ended June 30, 2005 and 2004, the audited consolidated financial statements and MD&A for the years ended December 31, 2004 and 2003 and the Annual Information Form and other information filed by Inter Pipeline at www.sedar.com.

SECOND QUARTER 2005 RESULTS SUMMARY

- Cash flow from operations of $32.9 million, up $5.2 million over the same quarter last year

- Quarterly payout ratio of 104.2%; year to date payout ratio of 90.9% on target with the anticipated full year payout ratio

- Net income of $13.1 million, down $1.4 million from the same quarter a year ago

- Processed 128,900 barrels per day ("b/d") of natural gas liquids ("NGL")

- Cold Lake system volumes increased to 279,200 b/d, up 36,200 b/d from the comparable quarter in 2004

- Conventional system revenues increased $0.3 million despite volumes decreasing by 15,600 b/d when compared to the second quarter of 2004

- Announced 30,000 b/d of firm shipping commitments on the Bow River system

- Standard & Poor's upgraded Inter Pipeline's BBB corporate credit rating to a stable outlook from a negative outlook

PERFORMANCE OVERVIEW

Three Months Ended June 30

Inter Pipeline's 2005 second quarter results reflect the influence of seasonality in both its conventional pipeline and NGL extraction businesses.

The second quarter for the NGL extraction business is typically a time when there is lower demand for natural gas, and thus lower input volumes and related NGL production at Inter Pipeline's NGL extraction plants. This seasonality was magnified in the second quarter of 2005 by cooler, wetter weather than normal on the west coast of North America. This resulted in a lower natural gas demand on the west coast and related lower than expected natural gas flows through Inter Pipeline's Cochrane NGL extraction plant.

Natural gas that flows out the eastern export point of Alberta is processed at the Empress facilities, and gas that flows out the western export point is processed at the Cochrane facility. Given that Inter Pipeline's commercial arrangements at the Cochrane NGL extraction plant are volume based, lower gas volume results in lower cash flow from this plant. Cash flow from the Empress commercial arrangements does not fluctuate significantly with gas volumes. These lower volumes at the Cochrane NGL extraction facility did provide the opportunity to perform major maintenance at the plant. Additionally, all NGL extraction plants in the Empress area were shut down for a period of time beginning the evening of June 21, due to extreme winds that caused physical damage to the facilities. This shut down had a nominal impact on Inter Pipeline's cash flows.

The conventional pipeline business normally experiences lower second quarter throughput caused by lower overall crude oil production due to seasonal road bans and production facility maintenance. In 2005, this situation was exacerbated by severe weather in the month of June, which caused flooding and strong winds, further impacting producer facilities and throughput on Inter Pipeline's pipeline facilities. Despite this reduction in volumes, revenues were higher and cash flow from conventional pipeline operations increased $0.4 million over the same period in 2004. Although the Cold Lake volumes were substantially higher than the comparable quarter in 2004, they were still negatively impacted by longer than expected major turnaround projects by two of the shippers on the system. Weather did not play a significant role in the Cold Lake volume level. Cash flow from the Cold Lake operations was down $3.5 million compared to the second quarter of 2004 primarily due to the expected lower capital fee per barrel beginning January 1, 2005.

For the quarter ended June 30, 2005, Inter Pipeline's cash flow from operations increased $5.2 million to $32.9 million, up from $27.7 million in the three months ended June 30, 2004. This increase was primarily due to the contribution made by the NGL extraction business acquired in July, 2004. The NGL extraction, conventional, and Cold Lake pipeline businesses each contributed $15.1 million, $18.9 million and $10.9 million of cash flow from operations, respectively (Q2 2004 - $nil, $18.5 million and $14.4 million, respectively). These cash flow contributions were offset by corporate costs of $12.0 million (Q2 2004 - $5.2 million).

Inter Pipeline paid monthly cash distributions to unitholders in each of April, May, and June 2005 of $0.0625 per Partnership unit ("unit") for a total of $0.1875 per unit in the second quarter of 2005. This compares with cash distributions paid of $0.0600 per unit per month or $0.1800 per unit for the comparable period of 2004.

Total cash distributed in the second quarter of 2005 of $34.2 million was $9.1 million higher than the $25.1 million distributed in the three month period ended June 30, 2004. This represents a 104.2% payout ratio of cash flow from operations for the period ended June 30, 2005, as compared to a payout ratio of 90.4% for the same period of 2004. This increase in total cash distributed is mainly attributable to the issuance of 43.6 million new units since June 30, 2004 due to an equity offering, the conversion of 10% Convertible Extendible Unsecured Subordinated Debentures (the "Debentures"), the Distribution Reinvestment and Optional Unit Purchase Plan, and the exercise of Unit Incentive Options.

Inter Pipeline increased its debt level from March 31, 2005 by $9.0 million to fund operating working capital. This provides Inter Pipeline with a total debt to total capitalization ratio of 32.9% at quarter-end. Only $52.5 million, or 10.2% of the total $517.2 million of debt, is exposed to interest rate fluctuations.

Six Months Ended June 30

For the six months ended June 30, 2005, Inter Pipeline's cash flow from operations increased $19.5 million to $75.1 million, up from $55.6 million in the six months ended June 30, 2004. Again, this increase was primarily due to the contribution made by the NGL extraction business acquired in July, 2004. The NGL extraction, conventional and Cold Lake pipeline businesses each contributed $37.3 million, $39.1 million and $22.5 million of cash flow from operations, respectively (YTD 2004 - $nil, $38.3 million and $28.3 million, respectively). These cash flow contributions were offset by corporate costs of $23.8 million (YTD 2004 -$11.0 million).

Total cash distributed in the first six months of 2005 of $68.2 million was $18.8 million higher than $49.4 million distributed in the six month period ended June 30, 2004. This represents a 90.9% payout ratio of cash flow from operations for the period ended June 30, 2005, as compared to a payout ratio of 88.9% for the same period of 2004.

OUTLOOK

As expected, the second quarter of 2005 was impacted by the seasonal nature of both the NGL extraction and pipeline businesses. Although spring weather in 2005 was more extreme than normal, Inter Pipeline management is very confident that there will be no impact to monthly cash distributions. The pipeline and NGL extraction businesses continue to have strong fundamentals and are positioned to provide stable and predictable cash distributions into the foreseeable future.

Inter Pipeline continues to seek opportunities to enhance unitholder value through acquisitions and internal growth projects.



SELECTED CONSOLIDATED FINANCIAL INFORMATION

------------------------------------------------------------------------
As at and for the
Three Months Ended Six Months Ended
June 30 June 30
------------------------------------------------------------------------
(millions, except per
unit and % amounts) 2005 2004 2005 2004
------------------------------------------------------------------------
Revenues
NGL extraction(1) $ 144.8 n/a $ 315.4 n/a
Conventional pipeline $ 26.5 $ 26.2 $ 53.6 $ 52.3
Cold Lake pipeline $ 15.1 $ 17.8 $ 30.1 $ 34.9

Net income(1) $ 13.1 $ 14.5 $ 35.7 $ 23.6
Per unit - basic and
diluted $ 0.08 $ 0.10 $ 0.20 $ 0.17

Cash flow from
operations(1)(4) $ 32.9 $ 27.7 $ 75.1 $ 55.6
Per unit(4) $ 0.18 $ 0.20 $ 0.41 $ 0.41

Cash
distributions(1)(3)(4) $ 34.2 $ 25.1 $ 68.2 $ 49.4
Per unit $0.1875 $0.1800 $ 0.3750 $ 0.3600

Payout ratio(4) 104.2% 90.4% 90.9% 88.9%

Total assets(1) $1,668.7 $ 954.5

Long-term debt(1) $ 494.3 $ 87.0

Debentures(2) $ 22.9 $ 43.7

Total partners' equity $1,055.9 $ 794.0
Partnership units
outstanding, end of
period 183.0 139.4

Total enterprise value(4) $2,306.9 $1,238.8

(1) The increase in amounts from 2004 to 2005 is the result of the
acquisition of the extraction business on July 28,2004.
(2) $21.9 million of Debentures were converted into Class A units since
June 30, 2004.
(3) Cash distributions are calculated based on the number of units
outstanding at each record date.
(4) Please refer to the "Non-GAAP Financial Measures" section of this
MD&A.

RESULTS OF OPERATIONS

EXTRACTION OPERATIONS

Volumes and Extraction Revenues


Three Months Ended Six Months Ended
June 30, 2005 June 30, 2005
------------------------------------------------------------------------
Propane Propane
(000's b/d) Ethane -plus Total Ethane -plus Total
------------------------------------------------------------------------
Cochrane 42.2 20.9 63.1 46.6 24.3 70.9
Empress V (100% basis) 17.2 11.4 28.6 18.2 11.8 30.0
Empress II 23.8 13.4 37.2 26.8 15.3 42.1
------------------------------------------------------------------------
Total 83.2 45.7 128.9 91.6 51.4 143.0
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) There are no comparatives for the three or six months ended June
30, 2004 as the extraction business was acquired on July 28, 2004.


The three NGL extraction plants combined processed approximately 3.4 Bcf/d and 3.9 Bcf/d of gas during the three and six months ended June 30, 2005, respectively.

The second quarter is typically a "shoulder" season for natural gas flows from Alberta destined for the California market. The Cochrane NGL extraction plant processes gas exported from Alberta destined for the California and Pacific Northwest markets. Lower gas flows normally occur during the second quarter primarily because the temperature in California is between the cooling and heating season and because reservoir levels coming out of the winter are generally higher resulting in electric generation by water power rather than gas fired generation. Although gas volumes at Cochrane were forecast to be low during the second quarter, they were lower than expected due to the cooler weather and higher rainfall in the region. Historically, gas volumes exported from Alberta to California and the Pacific Northwest are lowest in the spring, increase in the summer months, decrease in the fall, and are highest in the winter months. During the second quarter, major maintenance work was undertaken at the Cochrane plant because of the lower gas flows.

The NGL extraction business generated $144.8 million in revenues in the second quarter of 2005 and $315.4 million on a year to date basis. As Inter Pipeline was not involved in the NGL extraction business in the first six months of 2004, there are no comparables to report for that period. Inter Pipeline continues to undertake a hedge program to mitigate the small portion of its cash flow that is subject to commodity prices (the "frac-spread"). That portion is only related to the propane-plus volumes at the Cochrane plant. See the Off Balance Sheet Arrangements section for further explanation.

During the period April 1 through June 30, 2005, the actual market frac-spread was $0.326 US/US gallon (YTD - $0.336). Market frac-spread, or gross margin, is defined as the difference between the weighted average propane-plus price at Mont Belvieu, Texas and the cost of AECO natural gas purchased for shrinkage make-up. The frac-spread realized by Inter Pipeline during the second quarter, including the production hedged and unhedged, was $0.281 US/US gallon (YTD - $0.274). This realized price is higher than the 15-year historical average frac-spread to December 31, 2004 of $0.227 US/US gallon. As at June 30, 2005, Inter Pipeline has hedged approximately 41% of estimated propane-plus frac spread exposure, for the period July 1, 2005 to December 31, 2005, at an average price of $0.265 US/US gallon.

Shrinkage and Operating Expenses

The shrinkage gas cost was $99.2 million for the period from April 1, 2005 to June 30, 2005 (YTD - $214.9 million). Shrinkage gas represents natural gas bought by Inter Pipeline to replace the value of the heat content extracted from the gas processed at the extraction plants, as NGL's are produced. Operating and maintenance costs were $8.8 million (YTD - $17.0 million), while fuel and power costs to produce NGL's at the three extraction facilities were $21.7 million (YTD - $46.1 million).

The Cochrane plant uses lower gas volume periods to undertake plant maintenance. During the second quarter of 2005 a number of gas turbine overhauls were performed in addition to a major overhaul of two extraction trains at Cochrane. The actual cost of the maintenance expense work was $3.0 million for the six months ended June 30, 2005, of which $2.5 million was incurred in the second quarter of 2005.

PIPELINE OPERATIONS

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



Three Months Ended Six Months Ended
June 30 June 30
------------------------------------------------------------------------
Pipeline System (000's b/d) 2005 2004 2005 2004
------------------------------------------------------------------------
Conventional
Bow River 134.6 146.0 136.8 146.0
Central /Valley/Mid
Saskatchewan 63.8 68.0 65.7 68.3
------------------------------------------------------------------------
198.4 214.0 202.5 214.3
------------------------------------------------------------------------
------------------------------------------------------------------------
Cold Lake Pipeline (100%
basis) 279.2 243.0 291.0 245.0
------------------------------------------------------------------------
------------------------------------------------------------------------


Conventional Pipeline System ("Conventional")

Total conventional revenues of $26.5 million in the second quarter of 2005 were $0.3 million higher than the $26.2 million earned in the three months ended June 30, 2004. The volume decrease in the quarter compared to the same quarter of 2004 of 15,600 b/d was due primarily to the extreme weather experienced in June, 2005. Flooding and strong winds impacted producers' facilities, which reduced overall receipts on the system. The financial impact of this decrease in volume was offset by mainline toll increases of 5.0% and 3.5% effective January 1, 2005 and July 1, 2004, respectively, as well as revenues earned from the Oil Storage and Marketing Agreement with Nexen Inc. entered into in July, 2004. The average revenue per barrel from the conventional systems in the second quarter of 2005 was $1.47 vs. $1.34 per barrel in the same three month period of 2004.

Year to date volumes decreased 11,800 b/d from the comparable six month period ended June 30, 2004, predominantly related to the weather issues incurred in the second quarter of 2005. The revenues for the six months ended June 30, 2005 were $53.6 million as compared to $52.3 million for the comparable year to date period of 2004.

Cold Lake Pipeline System ("Cold Lake")

Revenues from Inter Pipeline's 85% interest in Cold Lake were $15.1 million during the three months ended June 30, 2005, down $2.7 million from $17.8 million earned in the same period of 2004. Despite the increase in Cold Lake volumes of 36,200 b/d, the decrease in revenues is primarily a result of the expected reduction in capital fees per barrel that became effective January 1, 2005. This resulted in an approximately $3.5 million reduction in revenue when comparing the second quarter of 2005 and 2004. Cold Lake was not impacted by the severe weather conditions experienced by the conventional system.

Inter Pipeline's share of the Cold Lake revenues for the six months ended June 30, 2005 was $30.1 million, a decrease of $4.8 million from the comparable period of 2004. This revenue decrease was also a result of the expected reduction in capital fees per barrel that became effective January 1, 2005, despite the increase in volumes moving through Cold Lake.

The Cold Lake Transportation Services Agreement is supported with an annual minimum ship or pay commitment of $38.0 million ($44.7 million - 100% basis) in 2005 and thereafter reduces to approximately $30.8 million ($36.3 million - 100% basis) annually through to the end of December, 2011.

Operating Expenses

Conventional

The operating expenses for the conventional system were $7.9 million (YTD 2005 - $14.8 million), which is consistent with the $7.6 million (YTD 2004 - $14.1 million) incurred in the comparable quarter of 2004. An increase in the environmental remediation liability of $0.4 million was offset by a slight decrease in fuel and power costs, consistent with decreased volumes. The average Alberta market power price for the three months ended June 30, 2005 was $51.44 compared to $60.15 in the comparable period in 2004. The impact of lower Alberta market power prices on fuel and power costs was reduced by Inter Pipeline's electricity hedging program, which fixed 5.0 mega-watts of power at an average price of $46.95 per MW.h for both comparative quarters.

Cold Lake

Cold Lake operating expenses for the three months ended June 30, 2005 were $4.2 million (YTD 2005 - $7.6 million) compared to $3.4 million for the first three months of 2004 (YTD 2004 - $6.6 million). The increase was due to a $0.5 million increase in pipeline integrity and other project expenditures and a $0.4 million increase in routine costs. These increases were offset by a $0.1 million reduction in fuel and power costs. The decrease associated with lower Alberta market power prices was offset by increased consumption consistent with higher volumes in the second quarter of 2005 compared to the same period in 2004. The majority of operating expenses are recoverable from the shippers and the recoveries are recorded as revenue.

CORPORATE

General and Administrative

Inter Pipeline's general and administrative expenses totaled $3.3 million during the second quarter of 2005, which is $1.3 million higher than the $2.0 million in the comparable period of 2004. This increase in costs is primarily attributable to the increased staff levels and other expenses resulting from the acquisition of the NGL extraction business in July of 2004.

The increase in general and administrative expenses of $2.1 million to $6.1 million for the first six months of 2005 compared to $4 million for the same period in 2004 is also a reflection of the increased costs related to the acquisition of the NGL extraction business.

Non-Cash Compensation

During the three months ended June 30, 2005, Inter Pipeline incurred non-cash compensation expense of $4.2 million related to its Unit Incentive Option Plan ("UIOP") compared to a recovery of $0.5 million in the comparable three month period of 2004. 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. There was also an increase in Inter Pipeline's Class A unit price from $8.87 per unit at March 31, 2004 to $9.78 per unit at June 30, 2005 (December 31, 2004 - $9.16).

On a year to date basis, $8.7 million has been expensed compared to $4.3 million for the first six months of 2004. The increase of $4.4 million is also primarily attributable to both the increase in unit price and the increase in the number of vested units outstanding in the six month period.

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

Inter Pipeline's depreciation and amortization of its operating and intangible assets totaled $14.9 million in the three months ended June 30, 2005, which is $1.4 million higher than the $13.5 million charged in the second quarter of 2004. The depreciation and amortization in the first six months of 2005 was $29.7 million as compared to $27.1 million for the same period of 2004. The increase in both periods is attributable to the depreciation and amortization associated with the operating and intangible assets of the NGL extraction business offset by a reduction in depreciation on the conventional pipeline assets due to a change in depreciation method. Beginning January 1, 2005, the conventional pipeline assets are being depreciated on a straight line basis over the next 30 years.



Financing Charges

Three Months Ended Six Months Ended
June 30 June 30
------------------------------------------------------------------------
($millions) 2005 2004 2005 2004
------------------------------------------------------------------------
Credit facility interest
expense $ 1.7 $ 1.3 $ 3.4 $ 2.8
Interest on loan payable
to General Partner 5.7 - 11.5 -
Debentures interest
expense 0.6 1.2 1.3 3.0
------------------------------------------------------------------------
Cash related financing
charges 8.0 2.5 16.2 5.8
Amortization of deferred
financing costs 0.3 0.1 0.5 0.3
Accretion of discount on
Debentures - 0.1 - 0.2
------------------------------------------------------------------------
Total financing charges $ 8.3 $ 2.7 $16.7 $ 6.3
------------------------------------------------------------------------
------------------------------------------------------------------------


Inter Pipeline incurred $1.7 million of total credit facility interest expense during the quarter, compared to $1.3 million in the comparable quarter of the prior year. Short-term interest rates for the quarter ranged from a weighted average bankers acceptance rate of 3.45% to a weighted average prime rate of 4.23% (2004 - 2.98% for bankers acceptances and 3.82% for prime rate). The weighted average principal outstanding on the credit facilities was $121.1 million for the three months ended June 30, 2005 (2004 - $94.1 million).

Interest of $5.7 million was incurred in the quarter and $11.5 million year-to-date on the $379.8 million loan payable to the General Partner. The loan payable to the General Partner was part of the financing plan to acquire the NGL extraction business in July 2004. This loan payable did not exist in the first six months of 2004.

Debenture holders converted $21.9 million of Debentures into 3.7 million Class A units since June 30, 2004, including $10.0 million since December 31, 2004. Inter Pipeline incurred $0.6 million of interest expense in respect of its Debentures during the second quarter of 2005, as compared to $1.2 million in the comparable three month period of 2004. Debenture interest on a year to date basis was $1.3 million as compared to $3.0 million in the same period of 2004. 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.

Management and Acquisition Fees

The General Partner was paid a management fee equivalent to 2% of "Operating Cash," as defined in the Partnership Agreement. The fees of $0.8 million for the second quarter of 2005 are higher than the $0.6 million paid for the second quarter of 2004. This increase is due primarily to the addition of Operating Cash from the NGL extraction business beginning July 28, 2004. Year to date management fees have increased $0.5 million from $1.2 million in 2004 for the same reason.

Capital Expenditures

Inter Pipeline incurred a total of $1.6 million on capital expenditures in the three months ended June 30, 2005 (YTD - $4.7 million). Approximately $0.5 million was growth capital primarily related to the conventional pipeline business. The remaining $1.1 million was spent on sustaining capital projects for the corporate ($0.4 million), conventional pipeline ($0.3 million) and extraction businesses ($0.4 million).

Capital expenditures related to the previously announced Bow River south expansion will begin to accrue in the third quarter of 2005.



SUMMARY OF QUARTERLY RESULTS


------------------------------------------------------------------------
2003 2004
------------------------------------------------------------------------
(millions,
except
per unit Third Fourth First Second Third Fourth
and % Quarter Quarter Quarter Quarter Quarter Quarter
amounts) (restated) (1)
------------------------------------------------------------------------
Revenue
NGL Extraction
Business(1) n/a n/a n/a n/a $ 111.4 $ 188.9
Conventional
Pipeline(4) $26.9 $27.0 $26.2 $26.1 $ 28.3 $ 27.9
Cold Lake
Pipeline(4) $18.3 $18.5 $17.1 $17.8 $ 19.8 $ 18.6
Net Income $ 6.4 $ 1.7 $ 9.1 $14.5 $ 18.8 $ 29.5
Per unit -
basic and
diluted $0.06 $0.01 $0.07 $0.10 $ 0.12 $ 0.17
Cash Flow
from
Operations
(1)(3) $23.4 $24.4 $27.9 $27.7 $ 38.7 $ 55.9
Per unit $0.21 $0.20 $0.21 $0.20 $ 0.23 $ 0.33
Cash
distributions
(1)(2)(3) $20.4 $22.3 $24.4 $25.1 $ 32.5 $ 33.7
Per unit(3) $0.18 $0.18 $0.18 $0.18 $0.1825 $0.1875
Payout
ratio(3) 87.2% 91.3% 87.4% 90.4% 83.8% 60.3%
Partnership
units
outstanding
Weighted
Average 112.0 121.7 133.6 138.9 166.1 179.4
End of
Period 113.3 128.8 138.1 139.4 178.0 180.1



SUMMARY OF QUARTERLY RESULTS

------------------------------------------------------------------------
2005
------------------------------------------------------------------------
(millions, except
per unit and % First Second
amounts) Quarter Quarter
------------------------------------------------------------------------
Revenue
NGL Extraction
Business(1) $ 170.5 $ 144.8
Conventional
Pipeline(4) $ 27.1 $ 26.5
Cold Lake
Pipeline(4) $ 15.0 $ 15.1
Net Income $ 22.6 $ 13.1
Per unit -
basic and
diluted $ 0.12 $ 0.08
Cash Flow from
Operations(1)(3) $ 42.2 $ 32.9
Per unit $ 0.23 $ 0.18
Cash distributions
(1)(2)(3) $ 34.0 $ 34.2
Per unit(3) $0.1875 $0.1875
Payout ratio(3) 80.6% 104.2%
Partnership units
outstanding
Weighted Average 181.0 182.3
End of Period 181.9 183.0

(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.
(3) Please refer to the "Non-GAAP Financial Measures" section of this
MD&A.
(4) Restated for change in segment reporting policy.



LIQUIDITY AND CAPITAL RESOURCES

As at June 30
-----------------------------------------------------------------------
(millions, except for % amounts) 2005 2004
-----------------------------------------------------------------------

Cash and cash equivalents $ 5.4 $ 0.6
-----------------------------------------------------------------------
-----------------------------------------------------------------------

Working capital (deficiency), excluding
cash (6.7) $ 8.4
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Variable rate debt
Revolving credit facility $400.0 $210.0
Revolving credit facility - unutilized (285.5) (123.0)
-----------------------------------------------------------------------
Revolving credit facility outstanding 114.5 87.0
Less variable rate debt swapped to fixed (62.0) (63.0)
-----------------------------------------------------------------------
Total variable rate debt outstanding 52.5 24.0
-----------------------------------------------------------------------

Fixed rate long-term debt
Loan payable to General Partner 379.8 -
Debentures 22.9 43.7
Add variable rate debt swapped to fixed 62.0 63.0
-----------------------------------------------------------------------
Total fixed rate long-term debt
outstanding 464.7 106.7
-----------------------------------------------------------------------

Total debt and Debentures outstanding $517.2 $130.7
-----------------------------------------------------------------------
-----------------------------------------------------------------------

Senior debt to total capitalization 31% 9%
Total debt to total capitalization 33% 14%
-----------------------------------------------------------------------
-----------------------------------------------------------------------


Although Inter Pipeline has re-borrowed $9.0 million in the three months ended June 30, 2005, Inter Pipeline applies any excess cash against its outstanding debt to avoid interest costs. Approximately $36.5 million of revolving debt has been repaid and $10.0 million of Debentures have been converted to Inter Pipeline units since December 31, 2004. Of the $517.2 million of total debt outstanding at June 30, 2005, only $52.5 million was exposed to a period ending variable interest rate of 3.45% with the remaining $464.7 million of fixed term debt (excluding Debentures) having rates ranging from 5.41% to 6.31%.

Standard & Poor's has upgraded Inter Pipeline's BBB long-term corporate credit rating to a stable outlook from a negative outlook.

Inter Pipeline'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 $114.5 $ - $114.5 $ - $ -
Loan payable to
General Partner 379.8 - - - 379.8
Debentures 22.9 - 22.9 - -
Operating leases 9.5 1.3 3.9 2.2 2.1
------------------------------------------------------------------------
Total obligations $526.7 $1.3 $141.3 $2.2 $381.9
------------------------------------------------------------------------
------------------------------------------------------------------------


Inter Pipeline is continuing to plan its Bow River south expansion, but as of June 30, 2005 has not committed to any construction contracts or equipment procurement.

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 Inter Pipeline and specifically, may establish cash reserves that are determined to be necessary or appropriate for the proper management of Inter Pipeline. 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.



Three Months Ended Six Months Ended
June 30 June 30
------------------------------------------------------------------------
(millions, except per
unit and % amounts) 2005 2004 2005 2004
------------------------------------------------------------------------
Extraction revenue $ 144.8 $ - $ 315.4 $ -
Pipeline revenue,
excluding accretion of
discount on Annual
Service Contract
Recovery Amounts 41.6 43.9 83.6 87.2
Shrinkage gas expense (99.2) - (214.9) -
Cash operating expense (42.2) (11.1) (85.1) (20.6)
General and
administrative expense (3.3) (2.0) (6.0) (4.0)
Management fees expense (0.8) (0.6) (1.7) (1.2)
Credit facility interest
expense (1.7) (1.3) (3.4) (2.8)
Loan payable to General
Partner interest expense (5.7) - (11.5) -
Interest on Debentures (0.6) (1.2) (1.3) (3.0)
------------------------------------------------------------------------
Cash flow from
operations(1) 32.9 27.7 75.1 55.6
Net change in non-cash
working capital (5.4) (1.0) 32.5 6.1
------------------------------------------------------------------------
Cash provided by
operating activities $ 27.5 $ 26.7 $ 107.6 $ 61.7
------------------------------------------------------------------------
------------------------------------------------------------------------

Cash distributions (1) $ 34.2 $ 25.1 $ 68.2 $ 49.4
------------------------------------------------------------------------
------------------------------------------------------------------------

Per unit $0.1875 $0.1800 $0.3750 $0.3600
------------------------------------------------------------------------
------------------------------------------------------------------------

Payout ratio(1) 104.2% 90.4% 90.9% 88.9%
------------------------------------------------------------------------
------------------------------------------------------------------------

Growth capital
expenditures(1) $ 0.5 $ 5.8 $ 2.1 $ 8.9
Sustaining capital
expenditures(1) 1.1 0.4 2.6 0.6
------------------------------------------------------------------------
Total capital
expenditures $ 1.6 $ 6.2 $ 4.7 $ 9.5
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) Please refer to the "Non-GAAP Financial Measures" section of this
MD&A.


It is the intention of the General Partner of Inter Pipeline 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 Inter Pipeline's credit facilities should they ever be needed to maintain the monthly distributions.


OUTSTANDING UNIT DATA

Inter Pipeline's outstanding units as at June 30, 2005 are as follows:

(millions) Class A Class B Total
------------------------------------------------------------------------
Units outstanding 182.8 0.2 183.0
Units reserved for issuance upon
exercise of vested Unit Incentive
Options 2.0 - 2.0
Units reserved for issuance upon
conversion of Debentures 3.7 - 3.7
------------------------------------------------------------------------


FINANCIAL INSTRUMENTS AND OFF-BALANCE SHEET ARRANGEMENTS

Inter Pipeline 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 foreign exchange risk and to assist with stabilizing cash flow from operations. Inter Pipeline attempts to accomplish this primarily through the use of financial instruments. Inter Pipeline is prohibited from using financial instruments for speculative purposes. All hedging policies are authorized and approved by the Board of Directors through the risk management policy.

Inter Pipeline 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

Inter Pipeline has entered into power price swap agreements in respect of 5.0 MW per hour for the period from January 1, 2005 through December 31, 2006 at an average price of $48.23 per MW.h and 2.5 MW per hour for the period from January 1, 2007 to December 31, 2007 at an average price of $51.50 per MW.h. The mark-to-market value of these contracts at June 30, 2005 is an unrecognized gain of $0.9 million (June 30, 2004 - $0.6 million).

EXTRACTION BUSINESS

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

Commodity Prices

Inter Pipeline 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 June 30, 2005 to hedge NGL revenues fix NGL prices at the following average prices for the period from July 2005 to December 2005:



Average Average
Price (US$/ Quantity
US gallon) (b/d)
-----------------------------------------------------------------------
Propane 0.800 3,832
Normal Butane 0.950 656
Iso Butane 0.957 406
Pentanes Plus 1.198 325
-----------------------------------------------------------------------


Contracts outstanding at June 30, 2005 to hedge natural gas purchases fix natural gas prices at an average price of $7.232 per gigajoule for the period from July 2005 to December 2005 for average quantities of 23,261 gigajoules per day. The mark-to-market value of the NGL and natural gas contracts at June 30, 2005 resulted in unrecognized gains (losses) of US$(5.2) million and $0.4 million, respectively. Inter Pipeline was not involved in this line of business in the second quarter of 2004.

Foreign Currency

The NGL price swap agreements are calculated based on US dollar prices. Therefore, at June 30, 2005, Inter Pipeline had outstanding foreign exchange contracts to sell an average of US$5.8 million per month at an average fixed rate of US$0.800 per Canadian dollar for the period July 2005 to December 2005. The mark-to-market value of these contracts at June 30, 2005 results in an unrecognized gain of $0.9 million. There were no foreign currency exchange contracts in place in the second quarter of 2004.

CORPORATE

Interest Rates

$62.0 million of the outstanding debt at June 30, 2005 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 unrecognized loss of $6.3 million at June 30, 2005 compared to an unrecognized loss of $4.7 million at June 30, 2004.

TRANSACTIONS WITH RELATED PARTIES

No revenue was earned from related parties for the three months ended June 30, 2005 and 2004.

Inter Pipeline has entered into a support agreement that enables Inter Pipeline 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 Inter Pipeline'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 $0.8 million were paid to the General Partner in the second quarter of 2005 (2004 - $0.6 million). No amounts were paid in the second quarter of 2005 under the support agreement.

Inter Pipeline has entered into a loan agreement with the General Partner for $379.8 million.

ACCOUNTING POLICIES

Variable Interest Entities

The Accounting Standards Board has issued Canadian Accounting Guideline 15 (AcG 15), "Consolidation of Variable Interest Entities" which is now effective as of January 1, 2005. This standard requires companies to identify variable interest entities in which they have an interest, determine whether they are the primary beneficiary of such entities and, if so, consolidate them for financial reporting purposes. Inter Pipeline has reviewed its investments and has concluded that no adjustments are required to the consolidation methods being used to account for its ownership interests in these entities.

NON-GAAP FINANCIAL MEASURES

Certain financial measures referred to in this MD&A, namely "cash distributions", "cash flow from operations", "cash flow from operations per unit", "Distributable Cash", "enterprise value", "growth capital expenditures", "payout ratio" 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 Inter Pipeline to generate cash and fund the monthly distributions. Management considers these non-GAAP financial measures to be important indicators in assessing its performance.

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

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 period.

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

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

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

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

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 Inter Pipeline, including Inter Pipeline's Annual Information Form, is available on SEDAR at www.sedar.com.

Dated at Calgary, Alberta this 11th day of August, 2005.

Disclaimer

This Management's Discussion and Analysis ("MD&A") highlights significant business results and statistics for Inter Pipeline Fund's three and six month period ended June 30, 2005. 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. All amounts are stated in Canadian dollars unless otherwise specified.



Inter Pipeline Fund

CONSOLIDATED BALANCE SHEETS

As at As at
June 30, December 31,
(unaudited) (thousands of dollars) 2005 2004
------------------------------------------------------------------------

ASSETS
Current Assets
Cash $ 5,443 $ 4,412
Accounts receivable 70,555 115,471
Prepaid expenses and other deposits 4,265 5,592
Current portion of Annual Service Contract
Recovery Amounts (note 3) - 2,349
------------------------------------------------------------------------
Total Current Assets 80,263 127,824

Intangible and other assets (note 4) 372,469 379,562
Property, plant and equipment (note 5) 1,213,840 1,232,817
Deferred financing charges, net of
accumulated amortization of $8,925
(December 31, 2004 - $8,160) 2,124 2,748
------------------------------------------------------------------------
Total Assets $ 1,668,696 $ 1,742,951
------------------------------------------------------------------------
------------------------------------------------------------------------

LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Distributable cash payable $ 11,437 $ 11,255
Accounts payable and accrued liabilities 70,100 90,125
------------------------------------------------------------------------
Total Current Liabilities 81,537 101,380

Long-term debt (note 6) 494,300 530,800
Convertible Debentures (note 7) 22,934 32,510
Asset Retirement Obligation 9,027 8,743
Environmental liabilities 3,956 3,580
Future income taxes 1,083 1,007
------------------------------------------------------------------------
Total Liabilities 612,837 678,020
------------------------------------------------------------------------

Partners' Equity
Conversion feature on Convertible Debentures
(note 7) 962 1,395
Partners' Equity (note 8) 1,054,897 1,063,536
------------------------------------------------------------------------
Total Partners' Equity 1,055,859 1,064,931
------------------------------------------------------------------------
Total Liabilities and Partners' Equity $ 1,668,696 $ 1,742,951
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to the interim consolidated financial statements.


Inter Pipeline Fund

CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY

Six months
ended
-------------------------------------------------
(unaudited) June 30, June 30,
(thousands of dollars) 2005 2004
------------------------------------------------------------------------
Class A Class B
Limited Unlimited
Liability Liability
Partnership Partnership
Units Units Total Total
------------------------------------------------------------------------

Balance, beginning
of period $ 1,062,472 $ 1,064 $ 1,063,536 $ 753,510
Net income for the
period 35,694 36 35,730 23,632
Cash distributions
declared (68,171) (69) (68,240) (49,446)
Issuance of Partnership
units
Conversion of Debentures
(notes 7 and 8) 10,010 10 10,020 59,288
Issued under Distribution
Reinvestment and
Optional Unit
Purchase Plan (note 8) 1,705 2 1,707 1,778
Issued under Unit
Incentive Option
Plan (note 9) 10,005 10 10,015 4,125
Amortization of
Debenture issue costs (242) - (242) (3,309)
Unit-based compensation
(note 9) 2,368 3 2,371 2,467
------------------------------------------------------------------------
Balance, end
of period $ 1,053,841 $ 1,056 $ 1,054,897 $ 792,045
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to the interim consolidated financial statements.


Inter Pipeline Fund

CONSOLIDATED STATEMENTS OF NET INCOME

Three months ended Six months ended
(unaudited) June 30 June 30
(thousands of dollars) 2005 2004 2005 2004
------------------------------------------------------------------------

REVENUES
Extraction revenue $ 144,845 $ - $ 315,382 $ -
Transportation revenue 41,562 43,982 83,636 87,252
Accretion of discount on
Annual Service Contract
Recovery Amounts (note 3) 30 81 53 183
------------------------------------------------------------------------
186,437 44,063 399,071 87,435
------------------------------------------------------------------------

EXPENSES
Shrinkage gas 99,211 - 214,919 -
Operating 42,603 11,064 85,479 20,640
General and administrative 3,330 2,027 6,059 4,000
Non-cash compensation
expense 4,200 (485) 8,713 4,328
Depreciation and
amortization 14,862 13,505 29,687 27,137
Financing charges (note 10) 8,253 2,729 16,700 6,339
Management fee to
General Partner 782 639 1,708 1,194
Future income taxes 56 83 76 165
------------------------------------------------------------------------
173,297 29,562 363,341 63,803
------------------------------------------------------------------------

NET INCOME $ 13,140 $ 14,501 $ 35,730 $ 23,632
------------------------------------------------------------------------
------------------------------------------------------------------------

Net income per Partnership
unit (note 8)
Basic and Diluted $ 0.08 $ 0.10 $ 0.20 $ 0.17
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to the interim consolidated financial statements.


Inter Pipeline Fund

CONSOLIDATED STATEMENTS OF CASH FLOWS

Three months ended Six months ended
(unaudited) June 30 June 30
(thousands of dollars) 2005 2004 2005 2004
------------------------------------------------------------------------

OPERATING ACTIVITIES
Net income $ 13,140 $ 14,501 $ 35,730 $ 23,632
Depreciation and
amortization 14,862 13,505 29,687 27,137
Amortization of deferred
financing charges (note 10) 255 102 523 282
Accretion of discount on
Debentures (note 10) - 112 - 270
Non-cash compensation expense 4,200 (485) 8,713 4,328
Non-cash operating expense 376 - 376 -
Future income taxes 56 83 76 165
Accretion of discount on
Annual Service Contract
Recovery Amounts (30) (81) (53) (183)
------------------------------------------------------------------------
Cash flow from operations 32,859 27,737 75,052 55,631
Net change in non-cash
working capital (5,373) (1,047) 32,539 6,087
------------------------------------------------------------------------
Cash provided by operating
activities 27,486 26,690 107,591 61,718
------------------------------------------------------------------------

INVESTING ACTIVITIES
Annual Service Contract
Recovery Payment (note 3) 930 1,622 2,402 3,295
Expenditures on property,
plant and equipment (1,594) (6,237) (4,674) (9,474)
Proceeds on sale of assets 173 431 196 494
Acquisition of the Extraction
Business (note 2) - - 342 -
Net change in non-cash
working capital (1,320) 1,651 (5,517) 413
------------------------------------------------------------------------
Cash used in investing
activities (1,811) (2,533) (7,251) (5,272)
------------------------------------------------------------------------

FINANCING ACTIVITIES
Cash distributions declared (34,224) (25,064) (68,240) (49,446)
Increase / (decrease) in
long-term debt, net of
repayments 9,000 (7,000) (36,500) (15,000)
Cash received under
Distribution Reinvestment
and Optional Unit Purchase
Plan 1,084 601 1,707 1,778
Issuance of units under Unit
Incentive Option Plan 2,179 684 3,683 2,325
Deferred financing charges (20) - (141) -
Net change in non-cash
working capital 68 75 182 636
------------------------------------------------------------------------
Cash used in financing
activities (21,913) (30,704) (99,309) (59,707)
------------------------------------------------------------------------
Increase / (decrease) in cash 3,762 (6,547) 1,031 (3,261)
Cash, beginning of period 1,681 7,112 4,412 3,826
------------------------------------------------------------------------
Cash, end of period $ 5,443 $ 565 $ 5,443 $ 565
------------------------------------------------------------------------
------------------------------------------------------------------------

Cash interest paid on
long-term debt and
Debentures $ 14,825 $ 3,204 $ 16,626 $ 5,264
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to the interim consolidated financial statements.


Inter Pipeline Fund

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2005
(tabular amounts in thousands of dollars, except unit and per unit
information)
(unaudited)


1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

These unaudited interim consolidated financial statements are presented in accordance with Canadian generally accepted accounting principles and have been prepared by management following the same accounting policies and methods of computation as the consolidated financial statements for the year ended December 31, 2004, except as discussed below. The disclosures provided in these interim consolidated financial statements are incremental to those included with the annual consolidated financial statements. These interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto in Inter Pipeline Fund's ("the Partnership") annual report for the year ended December 31, 2004. The second quarter for the NGL extraction business is typically a time when there is lower demand for natural gas and thus results in lower input volumes and related NGL production at the Partnership's NGL extraction plants. The conventional pipeline business normally experiences lower second quarter throughput caused by lower overall crude oil production due to seasonal road bans, and production facility maintenance.

Change in Estimate

Effective January 1, 2005, the Partnership has amended its estimates for calculating depreciation on the pipeline facilities and equipment of the conventional gathering system of the Pipeline Business. It was determined that due to a change in circumstances and experience gained in the last few years, the straight-line method of depreciation would better reflect a matching of the depreciation of the pipeline assets to the decline in the revenue-producing volume throughput of these assets. The estimated remaining service life of these assets has also been re-evaluated and revised to thirty years to better reflect the number of years over which these pipeline facilities and equipment will be in operation, which is also tied in to the estimated remaining life of the crude oil reserves expected to be gathered and shipped on these pipeline systems. The impact of this change on the three and six months ended June 30, 2005 is to decrease depreciation and amortization expense and increase net income by $4.3 million and $8.8 million respectively.

Change in Policy for Segment Reporting

The Partnership has changed its policy for segment reporting to separate the previously reported Pipeline Business into the Cold Lake Pipeline and Conventional Pipeline businesses. This change has been made to distinguish the contractual-based results of operations of the Cold Lake Pipeline business from the Conventional Pipeline business. These segments' operations are still primarily the transportation, storage and processing of hydrocarbons, however the revenues and costs are derived differently and therefore they are being evaluated and managed separately. This change in accounting policy has been applied retroactively in Note 13 - Segmented Information.


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 $1.9 million, for a net cash consideration paid of $713.1 million. The purchase was financed through $443 million of long-term debt and a portion of the proceeds from the issuance of 37.95 million Class A units. Concurrent with this transaction, an acquisition fee of $7.15 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 working capital adjustment was finalized during the first quarter of 2005, and the Partnership allocated the final Purchase Price as follows:



Cash $ 3,677
Working capital deficiency (34)
Intangible assets - Customer contracts and patent (note 4) 296,339
Property, plant and equipment (note 5) 421,599
Asset retirement obligation (8,507)
------------------------------------------------------------------------
$ 713,074
------------------------------------------------------------------------
------------------------------------------------------------------------


3. INVESTMENT IN ANNUAL SERVICE CONTRACT RECOVERY AMOUNTS

During the three and six months ended June 30, 2005, the Partnership received net payments of $0.9 million and $2.4 million, respectively (three and six months ended June 30, 2004 - $1.6 million and $3.3 million, respectively) related to its net investment in the Annual Service Contract Recovery Amounts. As at June 30, 2005, no 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 (December 31, 2004 - $2.3 million).



4. INTANGIBLE AND OTHER ASSETS
June 30, December 31,
2005 2004
------------------------------------------------------------------------
Accumulated Net Book Net Book
Cost Amortization Value Value
------------------------------------------------------------------------
Transportation
Services Agreement $ 93,548 $ (8,054) $ 85,494 $ 87,107
Customer contracts
(note 2) 287,612 (8,793) 278,819 283,988
Patent (note 2) 8,727 (571) 8,156 8,467
------------------------------------------------------------------------
$ 389,887 $ (17,418) $ 372,469 $ 379,562
------------------------------------------------------------------------
------------------------------------------------------------------------


5. PROPERTY, PLANT AND EQUIPMENT
June 30, December 31,
2005 2004
------------------------------------------------------------------------
Accumulated Net Book Net Book
Cost Depreciation Value Value
------------------------------------------------------------------------
Conventional Pipeline
system facilities
and equipment $ 749,861 $ (302,908) $ 446,953 $ 452,191
Cold Lake Pipeline
system facilities
and equipment 372,569 (30,689) 341,880 347,855
Extraction plants
and equipment
(note 2) 422,574 (12,677) 409,897 416,624
Cold Lake Pipeline
system linefill 10,384 - 10,384 10,384
Spare parts 3,326 - 3,326 3,379
Deferred receipt
facility
expenditures 5,571 (4,171) 1,400 2,384
------------------------------------------------------------------------
$ 1,564,285 $ (350,445) $ 1,213,840 $ 1,232,817
------------------------------------------------------------------------
------------------------------------------------------------------------


6. LONG-TERM DEBT

At June 30, 2005, the following amounts have been drawn under the Partnership's credit facilities:



June 30, December 31,
2005 2004
------------------------------------------------------------------------
Loan Payable to General Partner $ 379,800 $ 379,800
$400 million Unsecured Revolving Credit Facility 114,500 151,000
------------------------------------------------------------------------
$ 494,300 $ 530,800
------------------------------------------------------------------------
------------------------------------------------------------------------


7. CONVERTIBLE DEBENTURES

During the six months ended June 30, 2005, $10.0 million of 10% Convertible Extendible Unsecured Subordinated Debentures ("Debentures") were converted into Class A units, $9.6 million of which related to the Debt component and $0.4 million to the Equity Component. 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.



8. PARTNERS' EQUITY

Number of units issued and outstanding

Class A Units Class B Units Total
------------------------------------------------------------------------
Balance at December 31, 2004 179,911,495 180,217 180,091,712
Issued on conversion of
Debentures (note 7) 1,668,316 1,692 1,670,008
Issued under Distribution
Reinvestment and Optional
Unit Purchase Plan 190,837 196 191,033
Issued under Unit Incentive
Option Plan (note 9) 1,041,761 1,092 1,042,853
------------------------------------------------------------------------
Balance at June 30, 2005 182,812,409 183,197 182,995,606
------------------------------------------------------------------------
------------------------------------------------------------------------


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:



Three months ended Six months ended
June 30 June 30
2005 2004 2005 2004
------------------------------------------------------------------------
Basic 182,301,056 138,938,925 181,667,133 136,288,021
Effect of dilutive
exercisable unit
options 1,812,156 1,256,336 1,860,173 1,458,361
------------------------------------------------------------------------
Diluted 184,113,212 140,195,261 183,527,306 137,746,382
------------------------------------------------------------------------
------------------------------------------------------------------------


9. UNIT-BASED COMPENSATION

The following table summarizes information regarding unit options
outstanding at June 30, 2005:

Weighted-
Weighted- average
average adjusted
Number of exercise exercise
options price (1) price (2)
------------------------------------------------------------------------
Options outstanding,
December 31, 2004 4,353,080 $ 7.04 $ 4.93
Options exercised (1,041,761) $ (6.51) $ (3.45)
Options cancelled (66,667) $ (7.30) $ (5.52)
---------------------------------------------
Options outstanding,
June 30, 2005 3,244,652 $ 7.19 $ 4.99
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) The weighted-average exercise price based on the exercise price on
the date of grant.
(2) The weighted-average exercise price adjusted for the incentive
reduction.


As a result of options exercised in the six months ended June 30, 2005, $10.0 million was credited to Partners' Equity representing an amount equal to the market value of the units issued on the date of exercise. An additional $2.4 million was credited to Partners' Equity for the cost of outstanding and exercisable options at June 30, 2005.



10. FINANCING CHARGES

Three months ended Six months ended
June 30 June 30
2005 2004 2005 2004
------------------------------------------------------------------------
Interest expense $ 7,416 $ 1,353 $ 14,904 $ 2,761
Interest on Debentures 582 1,162 1,273 3,026
Amortization of deferred
financing charges 255 102 523 282
Accretion of discount
on Debentures - 112 - 270
------------------------------------------------------------------------
Total financing charges $ 8,253 $ 2,729 $ 16,700 $ 6,339
------------------------------------------------------------------------
------------------------------------------------------------------------

11. RISK MANAGEMENT

Frac spread risk management
Hedge contracts outstanding at June 30, 2005 were as follows:


Average
Average Price Quantity
NGL swaps (US$/ US gallon) (b/d) Hedged Period
------------------------------------------------------------------------
July 1, 2005 -
Propane 0.800 3,832 December 31, 2005
July 1, 2005 -
Normal Butane 0.950 656 December 31, 2005
July 1, 2005 -
Iso Butane 0.957 406 December 31, 2005
July 1, 2005 -
Pentanes Plus 1.198 325 December 31, 2005
------------------------------------------------------------------------

Average
Average Price Quantity
(Cdn$/GJ) (GJ/day) Hedged Period
------------------------------------------------------------------------
July 1, 2005 -
Natural gas swaps 7.232 23,261 December 31, 2005
------------------------------------------------------------------------


Average
Monthly
Notional
Amount
Average Price (US$
(US$/Cdn$) thousands) Hedged Period
------------------------------------------------------------------------
Foreign exchange July 1, 2005 -
swaps 0.800 5,753 December 31, 2005
------------------------------------------------------------------------


The fair market value of the NGL, natural gas and foreign exchange swap contracts at June 30, 2005 results in unrecognized gains/(losses) of US$(5.2) million, $0.4 million, and $0.9 million respectively. No similar contracts were in place at June 30, 2004.

During the three and six months ended June 30, the realized gains/(losses) on the frac spread hedge swap contracts recognized in income were:


Three months ended Six months ended
June 30 June 30
2005 2004 2005 2004
------------------------------------------------------------------------
NGL swaps $ (2,482) $ - $ (4,489) $ -
Natural gas swaps 573 - (2,879) -
Foreign exchange swaps (8) - 1,262 -
------------------------------------------------------------------------
Net realized (loss) on
frac spread swaps $ (1,917) $ - $ (6,106) $ -
------------------------------------------------------------------------
------------------------------------------------------------------------


Interest rate risk management

The fair market value of the outstanding interest rate hedge swap contracts on $62 million of the outstanding debt as at June 30, 2005 results in an unrecognized loss of $6.3 million (June 30, 2004 - $4.7 million). During the three and six months ended June 30, 2005, the realized loss on the interest rate hedge swap contracts recognized in income was $0.5 million and $1.1 million, respectively (three and six months ended June 30, 2004 - $0.6 million and $1.2 million, respectively).

Power price risk management

Electricity price hedge swap contracts outstanding at June 30, 2005 were as follows:



Price Quantity
Hedged Period ($/MW.h) (MW)
------------------------------------------------------------------------

2005 46.95 5.0
2006 49.50 5.0
2007 51.50 2.5
------------------------------------------------------------------------


The fair market value of the electricity price hedge swap contracts results in an unrecognized gain of $0.9 million at June 30, 2005 (June 30, 2004 - $0.6 million).

12. COMPARATIVE FIGURES

Certain prior period comparative figures have been reclassified to conform to the current period's presentation.



13. SEGMENTED INFORMATION

Three months ended June 30
Cold Lake Conventional Extraction
Pipeline Pipeline Business
2005 2004 2005 2004 2005 2004
------------------------------------------------------------------------
REVENUES
Extraction
revenue $ - $ - $ - $ - $144,845 $ -
Transportation
revenue 15,051 17,820 26,511 26,162 - -
Accretion of
discount on
Annual Service
Contract Recovery
Amounts (note 3) - - - - - -
------------------------------------------------------------------------
15,051 17,820 26,511 26,162 144,845 -
------------------------------------------------------------------------

EXPENSES
Shrinkage gas - - - - 99,211 -
Operating 4,167 3,434 7,943 7,630 30,493 -
General and
administrative - - - - - -
Non-cash
compensation
expense - - - - - -
Depreciation and
amortization 4,012 3,875 4,717 9,630 6,133 -
Financing charges
(note 11) - - - - - -
Management fee to
General Partner - - - - - -
Future income taxes - - - - - -
------------------------------------------------------------------------
8,179 7,309 12,660 17,260 135,837 -
------------------------------------------------------------------------

NET INCOME $ 6,872 $ 10,511 $ 13,851 $ 8,902 $ 9,008 $ -
------------------------------------------------------------------------
------------------------------------------------------------------------

Expenditures on
property, plant
and equipment $ 30 $ (4,816)$ (1,215) $(1,421) $ (409) $ -
------------------------------------------------------------------------
------------------------------------------------------------------------


Three months
ended June 30
Corporate Total
2005 2004 2005 2004
------------------------------------------------------------------------

REVENUES
Extraction revenue $ - $ - $144,845 $ -
Transportation revenue - - 41,562 43,982
Accretion of discount on
Annual Service Contract
Recovery Amounts (note 3) 30 81 30 81
------------------------------------------------------------------------
30 81 186,437 44,063
------------------------------------------------------------------------

EXPENSES
Shrinkage gas - - 99,211 -
Operating - - 42,603 11,064
General and administrative 3,330 2,027 3,330 2,027
Non-cash compensation expense 4,200 (485) 4,200 (485)
Depreciation and amortization - - 14,862 13,505
Financing charges (note 11) 8,253 2,729 8,253 2,729
Management fee to General
Partner 782 639 782 639
Future income taxes 56 83 56 83
------------------------------------------------------------------------
16,621 4,993 173,297 29,562
------------------------------------------------------------------------

NET INCOME $ (16,591)$(4,912) $ 13,140 $ 14,501
------------------------------------------------------------------------
------------------------------------------------------------------------

Expenditures on property,
plant and equipment $ - $ - $ (1,594)$ (6,237)
------------------------------------------------------------------------
------------------------------------------------------------------------

Six months ended June 30

Cold Lake Conventional Extraction
Pipeline Pipeline Business
2005 2004 2005 2004 2005 2004
------------------------------------------------------------------------

REVENUES
Extraction revenue $ - $ - $ - $ - $315,382 $ -
Transportation
revenue 30,077 34,911 53,559 52,341 - -
Accretion of
discount on
Annual Service
Contract Recovery
Amounts (note 3) - - - - - -
------------------------------------------------------------------------
30,077 34,911 53,559 52,341 315,382 -
------------------------------------------------------------------------

EXPENSES

Shrinkage gas - - - - 214,919 -
Operating 7,569 6,573 14,793 14,067 63,117 -
General and
administrative - - - - - -
Non-cash
compensation
expense - - - - - -
Depreciation and
amortization 8,019 7,752 9,402 19,385 12,266 -
Financing charges
(note 11) - - - - - -
Management fee to
General Partner - - - - - -
Future income taxes - - - - - -
------------------------------------------------------------------------
15,588 14,325 24,195 33,452 290,302 -
------------------------------------------------------------------------

NET INCOME $ 14,489 $ 20,586 $ 29,364 $ 18,889 $ 25,080 $ -
------------------------------------------------------------------------
------------------------------------------------------------------------

Expenditures on
property, plant
and equipment $ (432)$ (5,044)$ (3,367)$ (4,430) $ (875)$ -
------------------------------------------------------------------------
------------------------------------------------------------------------

Six months
ended June 30
Corporate Total
2005 2004 2005 2004
------------------------------------------------------------------------

REVENUES
Extraction revenue $ - $ - $ 315,382 $ -
Transportation revenue - - 83,636 87,252
Accretion of discount on
Annual Service Contract
Recovery Amounts (note 3) 53 183 53 183
------------------------------------------------------------------------
53 183 399,071 87,435
------------------------------------------------------------------------

EXPENSES
Shrinkage gas - - 214,919 -
Operating - - 85,479 20,640
General and administrative 6,059 4,000 6,059 4,000
Non-cash compensation expense 8,713 4,328 8,713 4,328
Depreciation and amortization - - 29,687 27,137
Financing charges (note 11) 16,700 6,339 16,700 6,339
Management fee to General
Partner 1,708 1,194 1,708 1,194
Future income taxes 76 165 76 165
------------------------------------------------------------------------
33,256 16,026 363,341 63,803
------------------------------------------------------------------------

NET INCOME $ (33,203)$(15,843) $ 35,730 $23,632
------------------------------------------------------------------------
------------------------------------------------------------------------

Expenditures on property,
plant and equipment $ - $ - $ (4,674) $(9,474)
------------------------------------------------------------------------
------------------------------------------------------------------------

Note: In the three and six months ended June 30, 2004, the Extraction
Business was not a segment as it was acquired by the Partnership in
July, 2004.


As at As at
June 30, December 31
2005 2004
------------------------------------------------------------------------
Total Assets
Cold Lake Pipeline $ 457,173 $ 476,433
Conventional Pipeline 465,714 475,692
Extraction Business 745,809 790,826
------------------------------------------------------------------------

$ 1,668,696 $ 1,742,951
------------------------------------------------------------------------
------------------------------------------------------------------------


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