KeyeraCovers 3/10/06 1:35 PM Page 1 KEYERA FACILITIES INCOME FUND 2005 ANNUAL REPORT 2005 Annual Report

keys to continued

www.keyera.com success keys to continued

success KeyeraCovers 3/5/06 5:32 PM Page 2

2005 Cash Distributions Declared (Cdn. $/unit) Distribution History ($ per unit per quarter) Record Date Payment Date Amount $0.40 January 31, 2005 February 15, 2005 $ 0.103 $0.35

February 28, 2005 March 15, 2005 $ 0.103 $0.30 March 31, 2005 April 15, 2005 $ 0.103 $0.25 April 29, 2005 May 16, 2005 $ 0.103 May 31, 2005 June 15, 2005 $ 0.113 $0.20 June 30, 2005 July 15, 2005 $ 0.113 $0.15

July 29, 2005 August 15, 2005 $ 0.113 $0.10 August 31, 2005 September 15, 2005 $ 0.113 $0.05 September 30, 2005 October 17, 2005 $ 0.113 $0 October 31, 2005 November 15, 2005 $ 0.113 Q2* Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 November 30, 2005 December 15, 2005 $ 0.119 2003 2004 2005 * Q2 2003 one month only December 30, 2005 January 16, 2006 $ 0.119 Total $ 1.328 2005 Unit Price ($ per unit) $24

$22 Glossary $20 acid gas hydrogen sulphide (H2S) or carbon dioxide (CO2) or a combination of H2S and CO2 acid gas injection the injection of acid gas into a suitable $18 underground geological formation bbls and bbls/d barrels and barrels per day $16 butane a natural gas liquid (NGL) with the $14 molecular formula C4H10 CO carbon dioxide 2 $12 condensate a natural gas liquid (NGL) consisting JAN FEBMAR APR MAY JUNJUL AUG SEP OCTNOV DEC Keyera Facilities Income Fund operates one of the largest natural gas midstream businesses in Canada. Its three primarily of pentanes and heavier liquids H S hydrogen sulphide business lines consist of: natural gas gathering and processing; the processing, transportation, and storage of 2 MMcf/d million cubic feet per day natural gas liquids (NGLs) and crude oil; and an NGL and crude oil commercial business. NGL or NGLs natural gas liquids, consisting of any one or a combination of propane, butane and condensate Keyera’s facilities are strategically located in the west central and foothills natural gas production areas of the propane a natural gas liquid (NGL) with the molecular formula C3H8 raw gas natural gas before it has been subjected Western Canadian Sedimentary Basin. Keyera’s NGL and crude oil infrastructure includes pipelines, terminals, to any processing that may be required for it to become suitable for sale and processing and storage facilities in Edmonton and Fort Saskatchewan, Alberta. Keyera also markets NGL mix NGLs that have been separated from the raw gas but have not yet been processed propane, butane and condensate to customers across North America. into propane, butane or condensate sales gas natural gas that has been treated in a natural gas processing facility and is suitable for sale Keyera trades on The Toronto Stock Exchange under the symbols KEY.UN. and KEY.DB. sour gas natural gas containing more than one percent H2S sulphur a yellow mineral extracted from natural gas

sweet gas natural gas that contains no H2S or less than one percent H2S when produced Front Cover: Nordegg Gas Plant Cover photo is dedicated to the memory of Hugh Gold, Nordegg Area Superintendent, who passed away after a short illness in July 2005. Hugh is greatly missed by his friends and coworkers at Keyera. Keyera AR Pgs 1-26 3/4/06 8:06 PM Page 1

assets people opportunities

Page 2: Page 4: Page 6: Positioned to benefit from Key people Numerous opportunities

robust industry activity operating key assets to grow our business

results

Page 8: Stable and growing

cash flows

contents keyera: Page 1 1: Chairman’s Message Page 12: President’s Message Page 16: Our Business Page 27: Financial Review Page 68: Fund Information

2005 annual report keyera 1

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With 18 plants and facilities, Keyera is one of the largest natural key: gas processors in Canada.

Large, well-positioned facilities Our gas plants are large, with broad capture areas and high barriers to entry, making them franchises in the areas in which they are located. Our NGL processing, transportation and storage facilities are strategically

located to supply key services to the NGL and heavy oil markets. Integrated business lines Our three business lines – natural gas gathering and processing, NGL and crude oil infrastructure, and our NGL and crude oil commercial business – are tightly integrated, allowing us to generate incremental cash flows all along the midstream value chain.

keyera 2005 annual report 2

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Solid footprint in western Canada Strategic location Located in the west central and foothills regions of Western Canadian Sedimentary Basin the Western Canadian Sedimentary Basin, our facilities are strategically positioned to benefit from Western Canadian Sedimentary Basin increased drilling activity in this area. B. C . ALBERTA

Chinchaga Caribou North Star Worsley

Fort Paddle River Saskatchewan Tomahawk Bigoray Greenstreet West Pembina Edmonton Brazeau North Terminal Brazeau Rimbey River Nordegg Gilby River Strachan Medicine River

Natural gas processing facilities NGL processing facilities assets

Room to grow Many of our facilities have available capacity and are able to accommodate additional throughput from

increased producer activity. Versatility Our gas plants are able to process both sweet and sour gas, and are equipped to extract valuable products like NGLs from the raw gas stream. Our NGL facilities process raw NGL into specification products

and provide storage and logistical services to customers. Longevity Our long-life facilities are well maintained and are able to operate as long as there is gas to be processed.

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We operate our facilities Key people operating key assets. Keyera employees share a passion for excellence and a common strategic direction.

key:

Operating expertise Our plant operators and maintenance personnel are highly trained and experienced in operating

sour gas processing facilities in a safe and environmentally responsible manner. Experienced management team Our management personnel have extensive operational knowledge and provide a consistent application of our corporate strategies.

Internal skill development Our team of specialists has created a capability management and development system to provide training and skill development, enabling us to internally develop knowledgeable and competent employees.

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Our operational knowledge

and hands-on approach allow us to quickly identify and implement growth opportunities.

people

Customer focus Our business interests are aligned with those of our customers; we work hard at building long-term

relationships through great service and specialized industry knowledge. Commitment to health, safety and quality assurance Our employees possess specialized experience, knowledge and training in health and safety matters. Our focus on operating in a safe and environmentally prudent manner benefits our employees, customers and unitholders as well as the residents in the communities surrounding our facilities.

2005 annual report keyera 5

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Keyera is well positioned to provide additional products and services as oil and gas production increases in the areas around our plants. key:

Increasing producer activity Natural gas drilling activity in the Western Canadian Sedimentary Basin is moving

west, towards our facilities, where significant natural gas reserves remain to be discovered. Available plant capacity The majority of Keyera’s facilities are able to process new gas production without additional capital expenditures.

Expanding services As heavy oil production increases significantly over the next decade, Keyera is well positioned to

provide diluent for crude oil blending as well as storage and logistics services. New business opportunities Ownership and operation of a diverse asset base presents numerous opportunities to expand our commercial business.

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Growth opportunities The size, scope Our vision of steady value and integration growth is based upon

of our business three key drivers: lines provide Plant utilization

considerable Capture additional throughput from increasing opportunities to drilling activity, utilizing existing available capacity.

grow our business. Internal growth Increase ownership in existing assets Expand existing facilities Build new gathering pipelines Add compression Optimize facilities

Selective acquisitions

Grow our business through acquisitions that meet our strategic and economic criteria.

opportunities

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Our growth strategy is balanced by our commitment

to a conservative capital structure, in keeping with our low risk profile.

key:

Growing business Our business has grown significantly with increases in cash flows, net processing capacity and

marketing volumes. Payout ratio Our payout ratio in 2005 was 80%, enhancing the stability of our distributions and allowing us to pursue internal growth projects.

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Stable and growing cash distributions 31% increase in distributions per unit since inception in May 2003.

Increasing Cash Distributions ($/unit)

1.33 1.14 0.64

1.50

1.00

0.50 2005 2004 2003* 0 * For the period May 30 to December 31 only. results

Conservative capital structure Our strong balance sheet provides financial stability and supports our stable and

growing cash distributions. Standard and Poor’s stability rating In recognition of our low risk profile, Standard and Poor’s has assigned an SR-3 stability rating, indicating the expectation of a high level of stability in distributions.

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keyera: highlights

2005 2004 2003

Financial Revenues ($ millions) 1,187.6 937.4 731.5 Net earnings ($ millions) 60.7 40.5 37.8 Capital expenditures ($ millions) 52.9 29.8 16.0

1 Distributable cash flow ($ millions) 98.7 78.1 26.4 Per unit ($) 1.67 1.50 0.60 1 Distributions to unitholders ($ millions) 78.5 59.5 27.9 Per unit ($) 1.33 1.14 0.64

Total annual unitholder return2 60% 24% 30%

1 2003 results are for the period May 30 to December 31 only; 2003 and 2004 distributable cash flow is shown before deducting Fund expenses. 2 Year over year appreciation in unit price plus distributions.

Note: 2003 and 2004 reflect Keyera Energy Partnership results and are included for comparison purposes. Distributable cash flow is not a standard measure under Canadian generally accepted accounting principles and therefore may not be comparable with the calculation of similar measures for other entities.

Net Earnings Distributable Cash Flow Distributions to Unitholders ($ millions) ($ millions) ($ millions)

60.7 98.7 78.5 40.5 78.1 59.5 37.8 26.4 27.9

75 125 90

100

50 60 75

50 25 30 2005 2005 2005 2004 25 2004 2004 2003 20031 20031 0 0 0

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keyera: chairman’s message

Last year’s commemoration of the province of Alberta’s The board has approved and implemented a business centennial marks an important event in Canadian history, conduct policy dealing with such issues as procurement, establishing 2005 as an outstanding year for all Albertans. conflicts of interest and fraud. In addition, a whistleblower Over the last 100 years, Alberta’s entrepreneurial spirit procedure was established to assist in uncovering behaviors and rich natural resources have fostered the development that are not in the best interest of unitholders. These of many successful business initiatives. Keyera is a fine initiatives reflect our continuing commitment to operate example of one such business. our business in an honest and ethical manner. Since 1998, Keyera’s management and employees Your directors continue to bring enthusiasm, energy have applied this entrepreneurial spirit to the oil and gas and expertise to their roles, providing guidance and good industry’s developing midstream sector. The result is the governance in developing Keyera’s strategic direction. I am emergence of Keyera as one of the largest natural gas proud to be associated with this group of individuals and midstream businesses in Canada. Creativity, innovation would like to thank each of the directors for their hard work and sound fiscal management have helped to grow Keyera’s and commitment over the past year. business to what it is today. On behalf of the board and unitholders, I would also like Through these efforts, Keyera has become a significant to congratulate Jim Bertram, his management team and all contributor to both local and national economies. Over the the employees of Keyera for their efforts this year and for past three years, we have successfully repatriated Keyera’s their success in growing the business. 2005 has truly been ownership from a foreign held entity to one that is now largely an exceptional year, not only for Albertans, but for all Canadian owned. Distributions to Canadian unitholders and Keyera employees and unitholders. With a clear vision for capital gains from unit price appreciation have delivered tax the business and strong forward momentum, Keyera will revenues that benefit all Canadians. Goods and services continue to be a significant contributor to the Canadian consumed at our facilities, combined with salaries paid to economy for years to come. employees and local property and school taxes, stimulate the economies in the communities where we operate. In addition to economic benefits, local communities have also benefited from Keyera’s donations of time and money to support numerous social programs. As someone who has spent considerable time in public service, it is gratifying to be involved with an organization that contributes to the well being of all Canadians. During 2005, Keyera’s unitholders approved the adoption of a corporate trustee structure. This change better aligns the Fund’s governance model with that of Canadian business corporations. A single board of directors is now responsible for directing the affairs of the Fund. The directors are elected by unitholders at each annual meeting, providing unitholders with more direct input into the selection of the board that oversees the management of the Fund.

On behalf of the directors, E. Peter Lougheed Chairman March 1, 2006

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keyera: president’s message

With the close of another successful year, it is gratifying for me to reflect on our accomplishments in 2005. Our business initiatives this past year resulted in three cash distribution increases to unitholders, representing a 21% increase. Since our inception in 2003, Keyera unitholders have seen distributions increase 31% and have enjoyed a 147% total return on their investment.

All three segments of our business experienced record results in 2005. Overall, we benefited from internal growth as well as the full year contribution from the EnerPro and Caribou acquisitions made in 2004.

Our gathering and processing business benefited from additional drilling around several of our plants, while our NGL infrastructure business profited from higher NGL offload, processing and storage revenues.

In our commercial business, our record financial results were made possible by our ability to source and deliver NGLs into key markets on a timely basis. Integration of our commercial business with our natural gas processing and NGL infrastructure assets allows us to aggregate supply, enjoy economies of scale and access higher-margin niche markets.

2005 Developments

Acquisition of additional interest Brine pond expansion facilitates Caribou North pipeline in Strachan gas plant provides increase in NGL storage revenues. construction and plant expansion greater control over business The expansion of Keyera’s brine pond create additional gathering development initiatives. at the Fort Saskatchewan facility will and processing revenues. In 2005, Keyera acquired an additional allow us to maximize utilization of our The construction of the Caribou North 25% interest in the Strachan gas plant, underground storage caverns. Demand Gas Gathering System, a sour natural gas increasing our ownership to 86%. for storage services is growing, driven by gathering pipeline in northeast British This acquisition will increase cash the increasing requirement for diluent Columbia, will facilitate the delivery flows and enhance long-term cash flow in the heavy oil sector. of raw natural gas to Keyera’s Caribou stability. It will also allow greater control gas plant for processing and will expand over the timing of future business the capture area of the gas plant by development initiatives. approximately 1,000 square kilometres.

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Successful execution of business strategy delivers results We believe that our hands-on approach to managing The strong financial results achieved this year result from our business has been a key factor in our ability to acquire the application of a consistent business strategy based on assets and develop internal growth projects. I am confident three key business drivers: plant utilization, internal growth that these business initiatives, and others like them, will and selective acquisitions. Our strategies combine the continue to support our vision of steady value growth built innovation of our people with the capabilities of our assets, around sustainable competitive energy facilities. generating incremental revenue all along the natural gas value chain, and providing stable and growing cash Internal projects support continued growth distributions to unitholders. The number of facilities we operate, the geographical diversity of our business and the integration of our facilities allow us Several key acquisitions in the last two years demonstrate to identify and act upon numerous internal growth projects the successful execution of our strategy and position Keyera each year, helping to grow our business without relying on for continued growth: external acquisitions. For 2006, we have approved a budget The acquisition of EnerPro Midstream Company in 2004 of $50 million for internal growth projects, the largest in significantly increased our ownership of core assets and our history. Several of these projects are already underway gave us greater control over business development and will contribute to our 2006 cash flows. activities in each of our three business lines. The acquisition in 2004 of the Caribou gas plant in Industry fundamentals remain strong northeastern British Columbia established a new core Strong natural gas industry fundamentals are a key factor area in a region that is under-developed with significant in Keyera’s continued success. These fundamentals are undrilled geological potential. The exploration success driven by the need for natural gas in North America for that producers are experiencing, and subsequent residential, commercial and industrial consumption and production increases, led us to initiate the construction the limited available supply of natural gas to meet this of a $21.5 million project to expand the plant and extend need. Over the longer term, natural gas fundamentals are its capture area. expected to remain strong, although there will be periods The acquisition in 2005 of an additional 25% interest in of volatility. In 2005, the increased prices caused by the Strachan gas plant enables us to capture a greater disruptions in supply, such as the natural disasters in the percentage of revenues from the facility and take Gulf of Mexico, demonstrated the sensitive nature of the

advantage of future industry activity in the area. supply-demand balance.

Expansion of Edmonton rail Construction of a raw gas Integrated business lines increase rack increases Keyera’s ability gathering pipeline to Gilby gas commercial contribution. to provide diluent to heavy plant expands capture area. The integration of our commercial oil producers. The construction of a raw gas gathering business with our processing, storage This project will expand the rail rack pipeline west of the Gilby gas plant and transportation facilities is a unique at our Edmonton terminal by 50% and enhances our capture area, resulting in competitive advantage. It enables allow us to deliver condensate into the new gas gathering fees and processing us to source incremental NGL supply Edmonton market, enhancing our ability revenues from drilling activity in the area. and control distribution of products to supply diluent to the growing heavy to end use customers, allowing us to oil market in Alberta. access niche markets and maximize marketing margins.

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key:team

“Operating virtually all of our facilities (Left to right) Jamie Urquhart Vice President, Foothills Region is one of our key differentiators. Marzio Isotti Vice President, West Central Region As a hands-on management team David Smith Executive Vice President, Chief Financial we are able to identify new business Officer and Corporate Secretary opportunities and control the timing Bradley Lock Vice President, of project implementation.” Engineering and Operational Services Jim Bertram Jim V. Bertram President and Chief Executive Officer President and Chief Executive Officer Ken Merritt Vice President, Commercial Infrastructure and Marketing David Sentes keyera 2005 annual report Vice President, Comptroller 14 Keyera AR Pgs 1-26 3/4/06 8:06 PM Page 15

Demand for natural gas remains strong in North America Growing heavy oil production provides and is expected to continue to grow. The primary drivers new business opportunities are increasing electrical demand in the United States and Recent estimates by the Canadian Association of Petroleum growing bitumen and heavy oil production in western Canada. Producers suggest that close to $45 billion will be spent In the short term, we expect the supply of natural gas to over the next decade on bitumen and heavy oil projects in be limited to conventional North American sources. New northeastern Alberta. These projects are expected to result sources are being developed, including liquified natural in additional production of 1.7 million barrels per day of gas (LNG) from offshore and natural gas from the Canadian bitumen and heavy oil. Keyera is well positioned to respond Arctic and Alaskan North Slope. However, given the progress with storage and logistics services, through our Fort to date on these initiatives, indications are that it will be Saskatchewan and Edmonton facilities, and with diluent several years before they contribute to North American supply for crude oil blending. Our ability to meet producer supply in a significant way. Regardless of the timing of these demand will be further enhanced when we complete our new supply sources, the Western Canadian Sedimentary brine pond project and the rail rack expansion which will Basin will continue to be a key supply source for the fore- increase our storage capacity and our access to diluent supply. seeable future. As we look to the future, the combination of strategic acquisitions, attractive internal growth projects, and increased Industry activity increasing around our facilities producer activity around our plants will continue to provide In 2005, 24,800 wells were drilled in Canada, 9% higher the basis for growth in cash distributions to unitholders. than in 2004 and setting a record for the third consecutive year. Producers have continued to move their drilling programs Acknowledgements to the western parts of the Basin. Compared to last year, At Keyera, we consider ourselves to be successful when the drilling was up 29% in the foothills front region, 42% in execution of a strong business strategy is coupled with safe central Alberta and 13% in British Columbia. work practices. In 2005 we achieved both goals. In addition The majority of our facilities are located in this western to our record results, we completed the year with no region, which is relatively under-explored, offers multiple employee lost time due to injury. I would like to thank zones of interest and has significant geological potential. everyone who contributed to this effort, and I am confident Given the strategic location of our facilities in this region, that we will continue to provide our employees, contractors we are well-positioned to take advantage of this increased and the residents surrounding our facilities with a safe and activity. Keyera has the expertise, the infrastructure and the healthy workplace. capacity to process this gas. Keyera’s accomplishments are the result of the combined efforts of a great number of people: our unitholders, who have confidence in our business vision; our directors, who have supported our decisions and provided guidance; our customers, who have continued to choose Keyera; and finally, our employees, who understand and embrace our vision and turn ideas into cash flow. To all of you, thank you for your continued encouragement and support.

Jim V. Bertram President and Chief Executive Officer March 1, 2006

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key:assets Attractive geology on the western side of the Basin

ALBERTA

Dow Fort Saskatchewan Paddle River Keyera Fort Saskatchewan Fort Saskatchewan Pipeline

Tomahawk Bigoray Edmonton Terminal West Pembina

Brazeau North Rimbey Pipe Line

Brazeau River Keyera’s facilities are located on the western side of the Western Canadian Nordegg River Sedimentary Basin, an area that is Rimbey relatively less explored, has significant

Gilby geological potential and where there are significantly more gas-prone zones. Medicine River Deeper zones often have larger reserves Strachan and may also contain hydrogen sulphide and natural gas liquids, necessitating significant processing to meet sales pipeline specifications. As a result, Keyera’s plants are expected to operate for the foreseeable future, benefiting from higher throughput volumes

Natural gas processing facilities and increasing processing revenues.

Strategically located NGL processing facilities

Keyera gathering pipelines

Keyera’s Value Chain Gathering Natural Gas Processing Our business begins with the collection Some components of the raw gas stream of customer’s raw gas in our network of are commercially valuable, such as sales gas gathering pipelines for delivery to Keyera’s and natural gas liquids (NGLs). Others are processing plants. In some cases, raw impurities that must be removed and disposed

gas requires compression to ensure that of, such as water, hydrogen sulphide (H2S) it enters the gathering systems or gas and carbon dioxide (CO2). Through the plants at sufficient pressure. Keyera application of physical and chemical processes charges customers a fee to gather to the raw gas stream, the commercially and compress their gas. valuable products are separated from the impurities. Keyera charges customers a fee for providing these processing services.

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The integration of our gathering and processing facilities, our NGL infrastructure and our commercial business gives us

a competitive edge.

NGL and crude oil processing NGL transportation and storage NGL marketing The NGL mix that is separated from Propane, butane and condensate are Our marketing professionals purchase the raw gas stream during the gas delivered to end-use markets by pipeline NGLs from approximately 200 natural processing stage must be further or on trucks or railcars from loading gas producers and sell to more than separated into products such as propane, terminals located adjacent to our 100 customers. We manage a fleet of butane and condensate before being processing and storage facilities. over 600 railcars, which provides access sold to end-use customers. Keyera Both the NGL mix and sales products to retail and industrial customers across charges customers a fee for separating are often stored in Keyera’s underground North America. these components. Crude oil streams salt caverns for future processing or sale. with diverse characteristics are processed at Keyera facilities to enhance value.

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Keyera’s gathering, processing and transportation assets are strategically located to provide essential services to oil and gas producers. These assets possess a number of characteristics that make them ideally suited to deliver the stable and growing cash flows necessary for an income trust.

Stable fee-for-service revenues Large “franchise-type” facilities Services provided in the natural gas and NGL gathering and Our facilities are able to process large volumes of raw processing businesses are essential for producers. Revenues natural gas and NGLs. Processing facilities of this size offer generated are based on a fee-for-service model, where economies of scale, benefiting our producer customers. customers are charged a fee in exchange for our services. The majority of Keyera’s gas plants have extended gathering The fees are not linked to commodity prices. These revenue systems, creating large capture areas for the plants. Our characteristics result in greater stability and predictability NGL infrastructure is connected to all major NGL feeder of cash flows. pipelines in Alberta. These unique characteristics make our facilities franchises in the areas where they are located. Long-life assets Preserving and extending the lifespan of Keyera facilities Versatile processing facilities is an important priority. Our goal is to maintain our assets The majority of Keyera’s gas processing plants are able to so that they will be able to operate as long as there is gas to process both sweet and sour gas, extract NGLs, and at be processed. certain locations, make specification NGL products. This We conduct regular internal inspections of Keyera flexibility allows Keyera’s producer customers to realize equipment and pipelines, and our plants undergo regularly higher value from their raw gas and makes Keyera facilities scheduled maintenance and repair turnarounds on a four a preferred processing location. year cycle. As well, our facilities are upgraded when required Our NGL processing facilities are able to make to meet technological, environmental and regulatory changes specification NGLs, provide storage and logistics services and industry demands. to customers and deliver products into all major NGL

export pipelines.

Available capacity Processing capability Logistics Infrastructure To meet our customers’ Keyera’s gas plants provide essential Keyera’s NGL and crude oil requirements, Keyera has: services to natural gas producers as: infrastructure includes: 1.64 billion cubic feet per day of gross over 90% of natural gas processing Rail car and truck loading terminals raw gas processing capacity capacity is able to process sour gas; in 12 key locations that allow 65,000 barrels per day of net NGL over 95% of natural gas processing NGLs to move directly to market. processing capacity capacity is able to extract NGLs. 2,500 kilometres of gathering pipelines 8 million barrels of underground NGL storage.

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Integration creates value Natural Gas Processing Facilities Average Keyera’s three business lines: natural gas gathering and Ownership License Daily Utilization processing; NGL and crude oil processing, storage and Interest Capacity Throughput Rate (%) (MMcf/d) (MMcf/d) (%) transportation infrastructure; and our NGL and crude oil Facility commercial business are tightly integrated, enabling us to Rimbey 86 422 281 67 capture incremental revenues along the midstream value Strachan 86 275 146 53 chain. Ownership of plants, pipelines and logistics facilities Brazeau River 52 218 79 36 has allowed us to develop our crude oil midstream Chinchaga 100 148 44 30 business. As well, control of NGL infrastructure allows Bigoray 90 85 31 36 Keyera’s NGL marketing personnel to optimize our logistics Paddle River 87 81 15 19 infrastructure and access niche markets across North Nordegg River 78 75 53 71 America. These characteristics enable us to offer a broad Gilby 78 71 31 44 range of services to our customers while enhancing our Medicine River 24 64 42 66 competitive advantage. Brazeau North 68 49 9 18 West Pembina 74 43 14 33 Low risk marketing strategy Caribou 100 40 28 70 Within our NGL and crude oil commercial business, Keyera Greenstreet 100 25 7 28 operates one of the largest NGL marketing businesses in Worsley 100 20 3 15 Canada. Our marketing business consists of the purchase Tomahawk 68 16 1 6 of NGLs recovered from raw natural gas, often at our gas North Star 87 6 0 7 plants, for resale to customers across North America. Total 1,638 784 48 The majority of the NGLs we buy are sold in the same month as they are purchased, thereby reducing our exposure NGL Processing and Transportation to price fluctuations. For product stored in inventory to Average meet the winter season demand, we can fix the future sale Ownership License Daily Utilization Interest Capacity Throughput Rate price through forward sales and product swaps, to mitigate (%) (bbls/d) (bbls/d) (%) some of the risk of price movements. NGL Processing Fort Saskatchewan (Keyera) 77 30,200 28,962 96 Rimbey Gas Plant 86 31,500 15,916 51 Gilby Gas Plant 78 3,200 1,486 46 Fort Saskatchewan (Dow NGL processing) 18 30,000 22,593 75 (Dow De-ethanizer) 10 69,200 56,118 81 NGL Pipelines

Fort Saskatchewan (Keyera) 77 210,000 126,113 60 Integrated commercial business Rimbey Pipe Line 89 45,000 40,499 90 The following characteristics provide our marketing personnel with a distinct competitive advantage: NGL Storage Facilities Customer diversification: Ownership Gross Net Interest Capacity Capacity We purchase supply from over (%) (bbls) (bbls) 200 producers and sell to more Fort Saskatchewan than 100 customers throughout (Keyera) 77 8,290,000 6,383,300 North America. Fort Saskatchewan (Dow) 18 2,000,000 360,000 Access to niche markets: We manage a fleet of over 600 rail cars. Size creates economies of scale: By aggregating supply, we increased sales to over 50,000 barrels per day in 2005.

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key:people Our employees are experienced, highly trained and capable of adapting to new technologies and regulations.

Operational expertise Sour gas processing is a key competency at Keyera. In order to operate Ron Fandrick is Plant processing facilities in a safe and efficient manner, plant operations and Operations Superintendent maintenance personnel must be experienced, highly trained and capable of at the Strachan gas plant, adapting to changing technologies and regulations. On average, Keyera plant responsible for the safe and personnel have 20 years of experience, and many of our personnel have been efficient operation of the facility. Ron has worked employed at the same facility for more than 20 years. Keyera has developed at Strachan since 1985 internal training programs to augment existing mentoring programs and in various operational roles of increasing facilitate training of new plant operations and maintenance personnel. responsibility and is experienced in all aspects of plant operations. He has a First Class Power Engineering designation and is the Chief Steam Engineer for the facility.

Competency training systems enable internal skill development For the past eight years we have employed a philosophy of internally Keyera’s Manager of developing the skills and competencies required to run our business. Over Quality Control, Owen Baker this period, we have developed an innovative capability management and is responsible for developing development system to continue to improve our employees’ knowledge and Keyera’s training and integrity competency in carrying out their duties safely and efficiently. Keyera is management systems. Owen brings a unique skill set to recognized as an industry leader in this area and we now share our training his role, having spent twelve program with over 20 companies in the oil and gas industry. Revenue years working in natural gas facilities before generated from the sale of our system supports ongoing enhancements embarking on a career in education. His 25 years to our program. as a technical educator, most recently as Dean of In 2002, Keyera entered into a partnership with Lakeland College in Power Engineering at the Southern Alberta Institute Vermilion, Alberta to develop and deliver a petroleum-related curriculum, of Technology, contribute to his understanding of assess an individual’s work experience and course work, and provide the training challenges in our industry. Owen is certification to those meeting occupational or course profiles. Keyera’s Keyera’s Chief Inspector, holds a First Class Steam Engineering designation and is a Certified Pressure occupational expertise combined with Lakeland College’s educational Vessel Inspector. resources provides Keyera’s employees with relevant instruction in a post- secondary environment. Through our partnership with Lakeland College, Keyera is able to develop highly trained employees as Alberta’s demand for skilled operations and trades personnel grows.

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Commitment to health, safety and the environment Ken Meston is the Foothills Keyera is committed to conducting its business in a manner that protects Region’s Health and Safety the health and safety of our employees, contractors, the public and our Advisor. Prior to assuming this environment. We continually monitor and evaluate policies and operating role Ken was a number one practices, taking into account changes in laws and regulations, technical plant operator at the Strachan developments, industry standards and the operational needs of our facilities. gas plant. With 25 years of experience in gas processing In 2005, we completed the year with no employee lost time due to operations, Ken brings a wealth of knowledge to injury. This achievement reflects the commitment, skill and training of this position as well as a commitment to the well Keyera employees in creating a safe and proficient workplace. being of his fellow employees. In addition to his operational knowledge, he holds a Certificate in Occupational Health and Safety from the University of Alberta.

Integrity management programs enhance plant reliability As a Quality Control Keyera recognizes the importance of operating our facilities reliably and Inspector for Keyera’s within regulatory specifications in order to minimize the potential for West Central Region, environmental or public safety incidents. Through regular inspections and Mark Russell provides the application of Keyera’s integrity management system, our team of the expertise necessary quality assurance and quality control specialists provide support to plant for the reliable operation operations and maintenance personnel. of our facilities within regulatory specifications. Mark’s oil and gas As a result of our integrity management programs, Keyera has been able operations background provides a solid foundation to extend the periods between plant maintenance turnarounds to four years, for this role. Mark has been a Keyera employee for reducing downtime while maintaining regulatory compliance. In addition, our 30 years, providing quality control services for over integrity management programs help protect our employees, the public and 18 of those years. Mark is a certified In-Service the environment, and reduce operating costs. Boiler and Pressure Vessel Inspector, the highest designation achievable in his field.

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keyera: directors

Honourable E. Peter Lougheed (1) (3) Robert B. Catell P.C., C.C., Q.C. Bob Catell is Chairman and Chief Peter Lougheed is a corporate director and Executive Officer of KeySpan Corporation Counsel at Bennett Jones LLP, Barristers as well as Chairman and Chief Executive and Solicitors, and was a partner of that Officer of KeySpan Energy Delivery, firm from 1986 to 1999. Mr. Lougheed formerly Brooklyn Union Gas. In addition, E. Peter Lougheed Robert B. Catell served as Premier of Alberta from 1971 Mr. Catell is Chairman of several KeySpan to 1985. He is a director of four Canadian affiliates and subsidiaries. He was named companies and a member of the Trilateral Chairman and Chief Executive Officer Commission. Mr. Lougheed is a member of Brooklyn Union Gas in 1996, and was of the Privy Council of Canada, appointed Chairman and Chief Executive Companion of the Order of Canada Officer of KeySpan in 1998. Mr. Catell and Chancellor Emeritus of Queen's is past Chairman of the American Gas University. Mr. Lougheed holds a Bachelor Association and is a Vice-Chairman of Jim V. Bertram Michael B.C. Davies of Arts degree and a Bachelor of Laws the National Petroleum Council’s Natural degree from the University of Alberta as Gas Committee. He is a director of the well as an MBA from Harvard University. Houston Exploration Company. Mr. Catell holds Bachelors and Masters degrees in Mechanical Engineering from Jim V. Bertram (4) City College of New York. Jim Bertram is President and Chief Executive Officer of Keyera Energy Management Ltd., a position he has held Michael B.C. Davies (2) since the business was started in 1998. Michael Davies is Principal of Davies Previously, Mr. Bertram was employed & Co. Previously, Mr. Davies headed RBC at Gulf Canada as Vice President – Dominion Securities’ M&A Group from Marketing for Gulf Canada’s worldwide its formation in 1986 to 1996 and acted operations. Prior to joining Gulf Canada, as the firm’s senior M&A advisor. Prior he was Vice President – Marketing of to that, he spent a number of years in Amerada Hess Canada Ltd. Mr. Bertram the securities industry as a member is a director of TriStar Oil and Gas Ltd. of the Oil & Gas Group of Morgan and Mission Oil and Gas Inc. Mr. Bertram Stanley in New York. Mr. Davies was holds a Bachelor of Commerce degree also Vice-President and Chief Financial from the University of Calgary. Officer of the Polar Gas Project, an Arctic natural gas pipeline mega project. He is a Director of Echoex Ltd., and Cadent Energy Partners, Inc. Mr. Davies holds a Bachelor of Commerce degree and a Bachelor of Laws degree from the University of British Columbia and is a Chartered Business Valuator.

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keyera: directors

Nancy M. Laird (3) (4) William R. Stedman (3) (4) Nancy Laird is a corporate director Bill Stedman is Chairman and Chief with more than 20 years of experience Executive Officer of ENTx Capital in the energy industry. From 1997 until Corporation, a private holding company July 2002, Ms. Laird was Senior Vice specializing in the electric power industry. President, Marketing and Midstream for Previously, he was President and Chief Nancy M. Laird William R. Stedman EnCana Corporation and for PanCanadian Executive Officer of Pembina Pipeline Energy Corporation, a predecessor Corporation, the operating company corporation to EnCana. Previously, of Pembina Pipeline Income Fund. Ms. Laird was President of NrG Mr. Stedman is a director of Masters Information Services Inc., a joint Energy, Innicor Subsurface Technologies venture initiative involving four of North Inc. and a number of private corporations America's leading natural gas pipeline involved in the electric power industries. companies. Ms. Laird is a Director of Mr. Stedman holds a Bachelor of Civil H. Neil Nichols Wesley Twiss the Alberta Electric System Operator, Engineering degree (with Distinction) Calgary Technologies Inc., Canetic from McGill University, a Bachelor of Resources Trust, Enerflex Systems Ltd. Science degree from Dalhousie University and Hull Child and Family Services. and an MBA from Harvard University. Ms. Laird holds a Bachelor of Arts degree (Honours) from the University of Western Ontario and an MBA from The Schulich Wesley Twiss (2) School of Business. Wesley Twiss is a corporate director with 35 years of experience in the oil and gas industry. Previously he was Executive H. Neil Nichols (2) (3) Vice President and Chief Financial Officer Neil Nichols is a corporate director and of PanCanadian Energy Corporation management consultant, specializing in and Petro-Canada. He is a Director of natural gas infrastructure and delivery Addax Petroleum Corporation, Canadian systems. Previously, Mr. Nichols Oil Sands Trust, Enbridge Income Fund, was President of KeySpan Energy EPCOR, Hydrogenics Corporation and Development Corporation, a subsidiary STARS (Shock Trauma Air Rescue Service of KeySpan Corporation, Brooklyn, Foundation). Mr. Twiss holds a Bachelor New York. Prior to joining KeySpan, of Applied Science degree in Chemical Mr. Nichols was an owner and president Engineering from the University of of Corrosion Interventions, Ltd. and was Toronto and an MBA from the University Chief Financial Officer and Executive of Western Ontario. Mr. Twiss is Vice President of TransCanada Pipelines a graduate of the 2006 Directors Limited. Mr. Nichols is a member of the Education Program of the Institute Financial Executives Institute and is a of Corporate Directors. Registered Industrial Accountant.

(1) Chairman. (2) Member of the Audit Committee. (3) Member of the Compensation and Governance Committee. (4) Member of the Health, Safety and Environment Committee.

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key:opportunities Through internal growth projects and strategic acquisitions, Keyera has provided solid returns to unitholders.

Plant utilization growing from increasing industry activity In 2005, drilling activity increased significantly in the areas surrounding Keyera facilities, continuing the trend experienced over the past few years. This increased activity resulted in additional natural gas being delivered to Keyera plants for processing. In the West Central Region, several producers continue active drilling programs targeting medium depth, liquids-rich natural gas zones. This activity has resulted in additional volumes being delivered to Keyera plants for processing, particularly to the Rimbey gas plant. To capture new production from activity to the west of the Gilby gas plant, we are building a 6-inch diameter, 20 kilometre natural gas pipeline. This project is expected to generate gathering revenues as well as incremental processing revenues at the Gilby gas plant. In the Foothills Region, natural gas from Shell’s Tay River discovery began flowing to the Strachan gas plant for processing in early 2006. It is anticipated that Shell and other producers will drill additional wells in the area. Land acquisition and drilling activity continued in the West Pembina area as producers continued to test the extent of the Nisku bank edge play. To enable the new sour gas from this area to be separated from the produced oil, producers have constructed three new oil batteries. The majority of the gas separated in these batteries is expected to be delivered to one of three Keyera processing plants in the area.

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Caribou North Gas Gathering System

L/94-G-10 K/94-G-10 J/94-G-10 I/94-G-10 L/94-G-9 Compressor station Compressor Station Gas processing plant Caribou North Gas GatheringE/94-G-10 System F/94-G-10 G/94-G-10 H/94-G-10 E/94-G-9 Keyera pipelines

Alaska Highway D/94-G-10 C/94-G-10 B/94-G-10 A/94-G-10 D/94-G-9

L/94-G-7 K/94-G-7 J/94-G-7 I/94-G-7 L/94-G-8

Compressor Station

E/94-G-7 F/94-G-7 G/94-G-7 H/94-G-7 E/94-G-8

Keyera Caribou Plant

Caribou North pipeline and plant expansion expands plant capture area, generating additional gathering and processing revenues In late 2005 we initiated a $21.5 million pipeline and plant expansion project to support additional producer activity to the north of the Caribou gas plant. The 48 kilometre, 6-inch diameter sour gas pipeline, known as the Caribou North Gas Gathering System, will expand the capture area of the Caribou gas plant by about 1,000 square kilometres. This area has seen increasing levels of land acquisition and drilling activity but production has suffered from a lack of gas gathering infrastructure. Start-up of the Caribou North Gas Gathering System is expected in the second quarter of 2006. To accommodate the additional gas from this new pipeline, Keyera will expand the processing capacity at the Caribou gas plant by 25 million cubic feet per day to 65 million cubic feet per day. The success that producers are experiencing in increasing production supports our view of the prospective geology in the area, a key factor in our decision to acquire the Caribou plant in 2004.

Brine pond expansion facilitates increased storage revenues Located in the major NGL processing and distribution centre in western Canada, one of only four NGL marketing hubs in North America, Keyera’s Fort Saskatchewan processing facility is strategically situated to provide services to NGL and heavy oil producers. With the capacity to store over 8 million barrels in underground salt caverns, the storage of products, primarily NGLs, is a key service provided at Fort Saskatchewan. As the number of heavy oil mining and in situ projects increases, demand for various ancillary products and services, including storage for condensate and potentially crude oil, is increasing. To capture additional revenues from this increased demand for storage, Keyera has initiated a $9.9 million brine pond expansion at our Fort Saskatchewan facility.

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Brine is used to displace the stored products as they Selective acquisitions key to success are removed from the underground caverns. As NGLs are The growth of our asset base over the last several years is pumped into an underground cavern, the brine is displaced a reflection of our ability to selectively pursue acquisition from the underground caverns and deposited in large, opportunities. surface level ponds. As the level of NGLs in storage falls, brine is pumped from the brine ponds back into the under- Our focus is on acquiring facilities that are located in ground caverns. areas with attractive long-term prospects and where we see competitive advantages through barriers to entry, Expansion of the brine pond, expected to be completed synergy with existing operations, or the application of our in July 2006, will provide Keyera with sufficient surface operational expertise. capacity to hold all of the brine when storage caverns are at full capacity, allowing us to operate the caverns at a higher In the past two years, we have spent over $300 million utilization level. This will enable us to enter into higher acquiring key facilities to grow our business. The largest value, long-term storage contracts, adding to fee-for-service of these was the acquisition of EnerPro Midstream Company storage revenues at the facility. in 2004. With common ownership interests in five of the

eight EnerPro assets, the acquisition allowed us to become the operator of several key facilities. In 2005, we acquired Expansion of rail rack increases Keyera’s role in the heavy additional ownership interests in three core facilities: the oil diluent market Strachan, Rimbey and Bigoray gas plants.

Heavy oil and bitumen produced in Alberta are often too thick to flow easily in pipelines. To resolve this, producers Acquisition of additional interest in Strachan gas plant mix a lighter product such as condensate, as diluent. provides greater control over business initiatives Condensate is an NGL extracted from raw natural gas, and is one of the NGL products that Keyera markets. The In late 2005, we acquired an additional 25% ownership demand for diluent is growing with the increase in heavy oil interest in the Strachan gas plant. This $24 million purchase and bitumen production. To meet this growing demand, increased Keyera’s ownership position in the plant, along diluent must be imported into Alberta from other locations. with its associated plant facilities and pipelines, to 86%. To facilitate the delivery of additional condensate The Strachan gas plant is a large sour gas facility located supply into Alberta, we have initiated a $6.5 million project in the foothills region of Alberta. With available processing to expand the rail rack at our Edmonton terminal by 50%. capacity and an extensive gathering network, it is well The project is expected to be operational in mid-2006. positioned to benefit from the increasing exploration and Condensate, once delivered to Edmonton, can move development activities that are occurring in the geologically through the Edmonton terminal for delivery to end-use prospective land surrounding the facility. The acquisition customers or be directed into storage at Fort Saskatchewan. will increase cash flow, provide greater control over the implementation and timing of our business development initiatives and enable us to capture a greater percentage of future revenues from the facility.

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Keyera Facilities Income Fund

Management’s Report Management is responsible for the preparation of the accompanying consolidated financial statements. These consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles and include amounts that are based on estimates and informed judgements. Financial information contained throughout this Financial Report is consistent with these consolidated financial statements. Management has overall responsibility for internal controls and has developed and maintains a system of internal controls that provides reasonable assurance that the financial statements realistically report the Fund’s operating and financial results and that the Fund’s assets are safeguarded. Deloitte & Touche, independent external auditors, appointed by the Board of Directors, have independently examined the enclosed consolidated financial statements. The Audit Committee, consisting of independent directors, has reviewed the consolidated financial statements with management and the external auditors and has reported to the Board of Directors. The Board has approved the consolidated financial statements.

Jim V. Bertram David G. Smith President and Chief Executive Officer Senior Vice President and Chief Financial Officer

March 3, 2006

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Keyera Facilities Income Fund

Management’s Discussion and Analysis The following management’s discussion and analysis (“MD&A”) was prepared as of March 8, 2006 and is a review of the results of operations and the liquidity and capital resources of Keyera Facilities Income Fund (the “Fund”). It should be read in conjunction with the accompanying audited consolidated financial statements of the Fund for the year ended December 31, 2005 and the notes thereto as well as the consolidated financial statements of the Fund for the year ended December 31, 2004 and the related management’s discussion and analysis. Additional information related to the Fund, including the Fund’s Annual Information Form, is filed on SEDAR at www.sedar.com.

NOTE REGARDING NON-GAAP FINANCIAL MEASURES This discussion and analysis refers to certain financial measures that are not determined in accordance with Canadian generally accepted accounting principles (“GAAP”). These measures do not have standardized meanings and may not be comparable to similar measures presented by other entities. Measures such as operating margin (described in note 1 under the heading “Results of Operations” of this MD&A) and distributable cash flow (described in note 12 of the audited consolidated financial statements of the Fund) are not standard measures under GAAP and therefore may not be comparable with the calculation of similar measures for other entities. Management believes that these measures provide a more meaningful understanding of the Fund’s results of operations and financial position. Investors are cautioned, however, that these measures should not be construed as an alternative to net earnings determined in accordance with GAAP as an indication of the Fund’s performance.

FORWARD LOOKING STATEMENTS Certain statements contained in this report constitute forward looking statements. The use of words such as “anticipate,” “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should,” “plan,” “intend,” “believe,” and similar expressions, including the negatives thereof, is intended to identify forward looking statements. All statements other than statements of historical fact contained in this document are forward looking statements, including, without limitation, statements regarding the future financial position, business strategy, anticipated growth, proposed activities, budgets, litigation, references to future capital or other expenditures, projected costs and plans, estimated processing levels, environmental matters, and objectives of or involving Keyera. The forward looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results, events, levels of activity and achievements to differ materially from those anticipated in the forward looking statements. Such factors include, but are not limited to: general economic, market and business conditions; industry capacity; competitive action by other companies; fluctuations in oil and gas prices; processing and marketing margins; effects of weather conditions; fluctuation in interest rates and foreign currency exchange rates; the results of resource exploration, development and related activities of producers and customers; actions by governmental authorities; decisions or approvals of administrative tribunals; changes in environmental and other regulations; risks inherent in our operations; reliance on key personnel; and other factors, many of which are beyond the control of Keyera. Readers are cautioned that the foregoing list of important factors affecting forward looking statements is not exhaustive. The forward looking statements reflect management’s current beliefs and assumptions with respect to such things as the outlook for general economic trends, industry trends, commodity prices, capital markets, and the governmental, regulatory and legal environment. Management believes that its assumptions and analysis are reasonable and that the expectations reflected in the forward looking statements contained herein are also reasonable. However, Keyera cannot assure readers that these expectations will prove to be correct. Readers are therefore cautioned that they should not unduly rely on the forward looking statements included in this report and MD&A. Further, readers are cautioned that these forward looking statements speak only as of March 8, 2006 and Keyera does not undertake any obligation to publicly update or to revise any of the forward looking statements, whether as a result of new information, future events or otherwise, except as required by applicable law. All forward looking statements contained in this report and MD&A are expressly qualified by this cautionary statement. Further information about the factors affecting forward looking statements and management’s assumptions and analysis thereof is available in filings made by Keyera with Canadian provincial securities commissions available on www.sedar.com.

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Keyera Facilities Income Fund

INTRODUCTION The Fund was created on April 3, 2003 and began operations on May 30, 2003 with an initial public offering of trust units, acquiring a 39.1% indirect interest in Keyera Energy Partnership (the “Partnership”). Pursuant to transactions completed in connection with the initial public offering, the Partnership acquired Keyera Energy Facilities Limited (“KEFL”) and Keyera Energy Ltd. (“KEL”) on May 30, 2003. On April 1, 2004, the Fund completed a second equity offering, utilizing the net proceeds to acquire an additional interest of 35.9% in the Partnership, bringing the Fund’s ownership interest to 75%. On July 2, 2004, a subsidiary of the Fund acquired EnerPro Midstream Company (“EnerPro”) and contributed the assets of EnerPro to the Partnership, increasing the Fund’s interest in the Partnership to 82.6%. On December 2, 2004, the Fund completed a fourth equity offering, utilizing the net proceeds to acquire the remaining 17.4% interest in the Partnership, bringing the Fund’s ownership interest to 100%. Effective April 1, 2004, the Fund commenced accounting for the Partnership on a consolidated basis. Separate financial statements of the Partnership are therefore no longer presented with those of the Fund. The statement of operations contained in the audited consolidated financial statements includes the results of operations of the Fund, the Partnership, KEFL, KEL, EnerPro and Rimbey Pipe Line Co. Ltd. (“Rimbey Pipe Line”) for the twelve months ended December 31, 2005. The Fund and its subsidiaries are collectively referred to as “Keyera”. The information for the comparative twelve months ended December 31, 2004 includes the results of operations of the Fund since January 1, 2004, and the Partnership, KEFL and KEL since April 1, 2004. The Partnership and Rimbey Pipe Line were accounted for using the equity method until April 1, 2004 and July 2, 2004, respectively. Accordingly, some of the variances described in this report include the effect of these changes in accounting methods and readers are cautioned that certain information included in the financial statements for prior periods may not be directly comparable.

BUSINESS ENVIRONMENT Strong natural gas industry fundamentals are a key factor in Keyera’s success. As a midstream company, Keyera relies on producers to find and develop new sources of natural gas in order to sustain and grow its plant throughput volumes. Strong fundamentals generally result in higher natural gas prices, providing incentives to producers to increase their drilling activity. This activity often leads to additional new gas being delivered to Keyera’s facilities for processing. In 2005, North American natural gas supply and demand were finely balanced, with producers actively working to increase natural gas deliverability. Over the longer term, North American natural gas demand is expected to remain strong, driven by increasing electrical demand in the United States and the growing requirement for natural gas to support the anticipated increase in bitumen and heavy oil production in western Canada. In the short term, the supply of natural gas is expected to be limited to traditional North American sources. New sources of natural gas are being developed, such as liquefied natural gas (“LNG”) from offshore and natural gas from the Canadian Arctic or the Alaskan North Slope. However, given the progress to date on these initiatives, indications are that it will be several years before these sources contribute to North American supply in a significant way. Regardless of the timing of these new sources and their impact on the North American market, the Western Canadian Sedimentary Basin (“WCSB”) will continue to be a key supply source for the foreseeable future. The WCSB is the second largest basin in North America and has experienced an increase in natural gas drilling over the last several years. In 2005, producers drilled 24,800 wells in Canada, 9% higher than the previous year and setting a record for the third consecutive year. An increasing number of those wells are being drilled on the western side of the basin, where the majority of Keyera’s gas processing facilities are located. This area of the basin has considerable geological potential and substantially more gas-prone zones. The deeper zones often have larger reserves and may also contain hydrogen sulphide and natural gas liquids, necessitating significant processing to meet sales pipeline specifications. In 2005, wells drilled increased 29% in the foothills front region, 42% in central Alberta and 13% in British Columbia, areas where Keyera facilities are located.

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Keyera Facilities Income Fund

Although long term fundamentals are expected to support an active natural gas drilling program in the WCSB, there may be periods of volatility which have the potential to affect plant throughput volumes. Factors that can affect the fundamentals in the short term include changes in supply volumes, demand destruction caused by high prices, and environmental factors such as natural disasters and unseasonably warm or cold temperatures. The expected increase in heavy oil and bitumen projects in northern Alberta over the next decade may also provide new business opportunities for Keyera. Recent estimates suggest that close to $45 billion will be spent over the next decade on these projects, which is expected to result in an increase in heavy oil and bitumen production of 1.7 million barrels per day. Current plans are for a large portion of the new production to be delivered to Fort Saskatchewan, Alberta for upgrading before being delivered to end use customers across North America. This is expected to result in an increase in demand for storage and logistics services in the Fort Saskatchewan area, as well as additional demand for condensate for use as diluent in heavy oil streams. Keyera’s Fort Saskatchewan processing and storage facility and Edmonton terminal are well positioned to provide these services.

RESULTS OF OPERATIONS Keyera’s midstream activities are conducted through three business segments. The gathering and processing segment provides natural gas gathering and processing services to producers. The NGL infrastructure segment provides NGL processing, transportation and storage services to producers, marketers (including Keyera) and others. These services are provided primarily on a fee-for-service basis. The marketing segment is focused on the marketing of by-products recovered from the processing of raw gas, primarily NGLs, and crude oil midstream services. The combined operating margin generated from Keyera’s facilities segments (the gathering and processing and NGL infrastructure segments) represented approximately 55% of the operating margin for 2005 compared to 64% in the previous year, due to the exceptionally strong marketing results achieved in 2005.

Operating margin1 Gathering and NGL ($ millions) Processing Infrastructure Marketing2 Total 2005 Revenue 139.3 35.0 1,013.3 1,187.6 Operating expenses (67.5) (24.3) (946.3) (1,038.1) Operating margin 71.8 10.7 67.0 149.5 2004 3,4,5 Revenue 90.3 22.6 631.7 744.6 Operating expenses (40.2) (16.5) (601.3) (658.0) Operating margin 50.1 6.1 30.4 86.6

1 Operating margin, which is defined as operating revenues minus operating expenses, is not a standard measure under Canadian generally accepted accounting principles and therefore may not be comparable with the calculation of similar measures for other entities. 2 Keyera’s marketing business, which is operated within the Partnership, acquires at market rates fractionation and storage services, transportation services and other services from the NGL infrastructure business segment. In accordance with Canadian generally accepted accounting principles, these internal transactions have been eliminated from consolidated revenues and expenses. 3 The comparative year to date operating margins for 2004 contain only the second, third and fourth quarter results of the Partnership. Consolidation of the Partnership’s results by the Fund began April 1, 2004, the date when control was acquired. Previously the Partnership had been accounted for by the Fund on an equity basis. 4 The comparative 2004 operating margin for the NGL infrastructure segment does not include the results of Rimbey Pipe Line in the first two quarters, as control was not acquired until July 2, 2004. Previously, Rimbey Pipe Line had been accounted for by the Fund on an equity basis. 5 For 2004, revenue from the NGL infrastructure segment includes equity earnings from Rimbey Pipe Line of $0.6 million.

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Keyera Facilities Income Fund

Consolidated net earnings for 2005 were $60.7 million, an increase of $38.0 million from 2004. The increase was due to the inclusion of the Partnership, Rimbey Pipe Line and the EnerPro assets for the full year of 2005 and stronger marketing results. The growth was partially offset by higher general and administrative costs, interest expense and depreciation charges. In 2004, net earnings also included a $9.0 million impairment expense related to electrical generation equipment that was not put into service. This equipment is currently being held for resale.

Gathering and Processing Gathering and processing revenue for 2005 was $139.3 million, an increase of $49.0 million or 54% compared to the previous year. Approximately $21.4 million of this increase was attributable to the exclusion of revenue from the Partnership during the first quarter of 2004, when it was accounted for on an equity basis. The remainder of the increase is due to the inclusion of the facilities acquired from EnerPro for the entire twelve months of 2005 as well as modest growth in natural gas throughput volumes in the West Central Region and higher revenues from services such as NGL offloading, reprocessing and sulphur handling. Gathering and processing operating expenses were $67.5 million, an increase of $27.3 million or 68% compared to previous year. Approximately $9.4 million of this increase was attributable to the exclusion of operating expenses from the Partnership for the first quarter of 2004, when it was accounted for on an equity basis. The inclusion of the facilities acquired from EnerPro also contributed to the increased operating costs compared to the prior year. Other factors that contributed to higher operating expenses compared to 2004 were: • unplanned outages at the Strachan and Caribou plants during the first quarter of 2005; • higher electricity costs; and • several maintenance projects undertaken in the fourth quarter of 2005. Much of the revenue from the gathering and processing segment is generated on a cost-of-service basis. On a percentage basis, the increase in operating costs was higher than the increase in revenue primarily due to timing differences that occur as a result of the cost-of-service fee structure. Under most contractual arrangements with customers, revenues associated with the recovery of operating costs accrued at year end are not earned until the expenses are actually invoiced. In addition, some contractual arrangements provide for fixed-fee methodologies for charging revenue and, accordingly, certain costs incurred in the year were not recoverable. Average gross processing throughput of 784 million cubic feet per day was up slightly from 2004 due to incremental volumes from the EnerPro facilities and higher volumes at the Caribou and Rimbey gas plants, from strong industry drilling activity in the areas. This was partially offset by normal declines in production volumes, slower than expected Nisku well additions in the Foothills Region and unplanned outages early in the year at the Strachan and Caribou gas plants.

Gathering and Processing – West Central Region Natural gas drilling in the West Central Region in 2005 reflected the high levels of activity seen in western Alberta. Gross throughput at West Central plants increased by 5% over 2004, largely due to increased throughput at the Rimbey gas plant. To capture new production in this area, Keyera initiated a number of projects over the year. At the Brazeau North gas plant, Keyera constructed the Rat Creek pipeline to capture new gas volumes, followed by an inlet compression expansion project to handle the additional gas from the pipeline. Later in the year, a new 6-inch, 20 kilometre gas pipeline project was initiated to capture gas from an area to the west of the Gilby plant. This project is expected to be completed in the second quarter of 2006.

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Keyera Facilities Income Fund

Keyera increased its ownership in two West Central Region facilities in 2005. With these transactions, Keyera now owns 86.4% of the Rimbey gas plant and 90.2% of the Bigoray gas plant. In the fourth quarter, operating margin was lower than in previous quarters. This was due to several maintenance projects undertaken at Keyera facilities that resulted in increased operating costs and higher electrical costs. Two West Central gas plants, Paddle River and West Pembina, were shut down in the second quarter for scheduled 10 day maintenance turnarounds. In addition, sour gas processing at the Rimbey gas plant was interrupted for eight days in July while repairs were made to a process vessel. There are no West Central Region plant maintenance turnarounds scheduled for 2006.

Gathering and Processing – Foothills Region The Foothills Region experienced a similar increase in levels of drilling activity in 2005 as the West Central Region. However, in the Foothills Region a number of producers are targeting deeper geological zones which often contain larger reserves with higher levels of natural gas liquids and hydrogen sulphide. As a result, throughput levels in the Foothills Region can be more volatile, since a single well can have a significant impact. In 2005, throughput in the Foothills Region was 3% lower than in 2004, largely as a result of delays associated with the development of two producing areas in the region. The West Pembina region experienced active drilling and land sale activity in 2005, although regulatory issues and restrictions caused by a lack of infrastructure caused production delays in the last half of the year. This resulted in lower than expected volumes of sour gas at Keyera facilities in this area in 2005. Two producer owned oil batteries, which are required to separate gas from produced oil, were commissioned in the past several months, resulting in increasing production from the area. A third battery is currently in the process of being started up. As a result of an extensive stakeholder consultation process and subsequent pipeline licensing approvals, construction of the pipeline to deliver gas from the Shell Tay River discovery was not completed until year end and delivery of this gas to the Strachan gas plant did not occur until early in January, 2006. In December, Keyera acquired an additional 24.8% interest in the Strachan gas plant, along with additional pipelines and associated facilities, increasing its ownership in the plant to 85.8%. In addition to future revenues from this acquisition, Keyera is now able to take greater control of future opportunities resulting from developments in the region. At the Nordegg River plant, a producer owned pipeline was built during the first quarter of 2005 to deliver gas from west of the plant for processing. Compressor expansions and overhauls were completed at the Nordegg River and Strachan plants to eliminate bottlenecks in delivering gas to the plants and a larger amine condenser and aerial cooler were installed at the Brazeau River plant to enhance the plant’s ability to process the gas from the West Pembina region. Throughput at the Caribou plant increased gradually throughout the year and by year end the plant was operating near capacity. In the fourth quarter, Keyera announced its intention to construct a 48 kilometre, 6-inch sour gas pipeline north from the plant to access a new capture area north of the Buckinghorse River. To accommodate the additional gas, a 25 MMcf/d plant expansion will be undertaken, expanding the capacity to 65 MMcf/d. To complete this work, the plant will be shut down in the second quarter of 2006. Operating margin in the fourth quarter was lower than in previous quarters due to extensive maintenance projects undertaken, primarily at the Strachan gas plant. To accommodate the new gas from the Shell Tay River well, which is high in hydrogen sulphide, the second sulphur plant was refurbished during the quarter at a cost of $0.9 million. Costs were also incurred in the quarter in preparation for an upgrade of the Strachan flare stack in 2006. At the Worsley gas plant, additional processing capacity was activated in the fourth quarter to accommodate new sweet gas discovered in the area.

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In 2006, the Strachan and Chinchaga gas plants are due for their scheduled shutdowns to undertake maintenance and inspect the process equipment. These shutdowns are undertaken every four years and in 2006 the outages are expected in the second quarter. At Strachan, the maintenance work in 2006 will be extensive, as a full overhaul of the sulphur plant that is in current operation will be completed. This work is required to ensure the reliability of the plant over the next four years for new sour gas from the Tay River well and other wells expected in the area. In addition, while the Strachan plant is offline, the flare stack will be replaced to meet current regulatory guidelines and enhance its operating reliability.

NGL Infrastructure NGL infrastructure revenue for 2005 was $35.0 million, an increase of $12.4 million or 55% compared to the previous year. Approximately $7.0 million of this increase was attributable to the inclusion of revenue from the Partnership and Rimbey Pipe Line, which were not consolidated until April 1, 2004 and July 2, 2004 respectively. The remainder of the increase was due primarily to the increased ownership in the Fort Saskatchewan facility resulting from the EnerPro acquisition in July, 2004 and new multi-year condensate storage agreements which were entered into in the second quarter. NGL infrastructure operating expenses for 2005 were $24.3 million, an increase of $7.8 million or 47% compared to 2004. Approximately $3.8 million of this increase was due to the consolidation of the Partnership and Rimbey Pipe Line, beginning April 1, 2004 and July 2, 2004 respectively. The remainder of the increase was due primarily to the increased ownership in the Fort Saskatchewan facility resulting from the EnerPro acquisition. Two major expansion projects were undertaken in 2005 to allow Keyera to capture additional revenues from growth in the bitumen and heavy oil sector in Alberta. In the third quarter, Keyera began construction of a 3.9 million barrel brine pond at the Fort Saskatchewan processing and storage facility. This brine pond will allow a higher utilization of the existing underground storage at Fort Saskatchewan and enable Keyera to take advantage of the increasing long-term demand for condensate and butane storage. At the Edmonton terminal, Keyera has initiated a project to expand the rail rack by 50% to allow the offloading of condensate and other products. The offloaded product can be moved through the Edmonton terminal for delivery to end use customers or, ultimately, into storage at Fort Saskatchewan. Construction is underway and the new loading spots are expected to be operational in the second quarter of 2006.

Marketing Keyera’s commercial business consists of the marketing of NGLs and crude oil midstream services. Its NGL marketing business engages in the purchase and sale of NGLs. Keyera acquires products through processing arrangements and plant gate purchases. The composition of the revenues generated from the Fund’s NGL marketing business is shown in the table below.

Composition of Marketing Revenue (in thousands of dollars) Physical sales 1,014,823 Financial instruments (1,489) Marketing revenue 1,013,334

Keyera’s marketing business is exposed to commodity price risk between the time contracted volumes are purchased and the time they are sold. Keyera actively manages its commodity price risk by using derivative financial contracts, such as energy related forward sales, price swaps, physical exchanges and options, and by balancing physical and financial contracts in terms of volumes, timing of performance and delivery obligations. The table below outlines the changes in the fair value of the derivative financial contracts entered into by the Fund.

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Changes in Fair Value of Energy Derivative Contracts (in thousands of dollars) Fair value at December 31, 2004 256 Change in the fair value of contracts (1,465) Fair value of new contracts entered into in 2005 (280) Realized losses 1,209 Fair value at December 31, 2005 1 (280)

1 The fair value of the financial contracts represents an estimate of the amount that Keyera would pay or receive if those contracts were closed on December 31, 2005.

Derivative financial contract maturities vary from a single day up to two years. A large number of derivative financial contracts mature in less than one year. The relatively short maturities of the Fund’s derivative financial contracts lower its portfolio risk. Marketing revenue for 2005 was $1.013 billion, an increase of $381.6 million compared to the previous year. Approximately $169.0 million of this increase was attributable to the exclusion of marketing revenue from the Partnership for the first quarter of 2004, when it was accounted for on an equity basis. The remainder of the increase was primarily due to higher sales volumes and historically high commodity prices. NGL sales volumes for 2005 averaged 50,700 barrels per day compared to 49,500 barrels per day in 2004. Butane and condensate prices were strong throughout the year, generally commanding premiums driven by the high demand for diluent products. In the fourth quarter, prices for these diluent products softened due to reduced demand for crude and condensate. Propane prices strengthened during the year. The cost of goods sold for 2005 was $946.3 million, an increase of $345.0 million compared to the previous year. Approximately $161.2 million of this increase was attributable to the exclusion of marketing costs from the Partnership for the first quarter of 2004, when it was accounted for on an equity basis. The remainder of the increase was due primarily to the same factors that affected marketing revenues. NGL product inventories of $53.2 million were $27.0 million higher than last year due to higher prices and volumes. A significant portion of this inventory was sold in early 2006. Inventory has been valued at the lower of cost or net realizable value at December 31, 2005. To assist in expanding its marketing business, Keyera opened a wholesale marketing office in the United States in the fourth quarter. Located in Houston, Texas, the office’s mandate will be to expand Keyera’s marketing business and to provide better service to U.S. customers. Keyera’s NGL marketing business is underpinned by two long-term supply contracts that provide a base supply for its business. The strong margins earned by the marketing business were supported by Keyera’s integrated network of gas processing facilities and its NGL processing, storage, pipeline, truck and rail facilities. Marketing operating margins can vary significantly from period to period depending upon North American demand, inventory positions and pricing. As a result, marketing operating margins in future years may vary significantly from the 2005 results. Keyera’s crude oil midstream business engages in the purchase and sale of products and utilizes Keyera’s various crude oil midstream facilities. In 2005, Keyera initiated a crude oil midstream joint venture project with Pembina Pipeline Corporation at the Edmonton terminal. Construction at the terminal was completed in the fourth quarter and the facility is now operational. In addition, Keyera constructed a crude oil midstream terminal at its Wabasca pipeline terminal in northern Alberta. Given the short period of operation in 2005, the contribution of these new initiatives to 2005 results was not significant.

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Non-operating expenses and other earnings General and administrative expenses for 2005 were $25.2 million, $11.7 million greater than the previous year. Approximately $3.1 million of this increase was attributable to the exclusion of expenses from the Partnership for the first quarter of 2004, when it was accounted for on an equity basis. The remainder of the increase was primarily related to higher incentive compensation costs. The increase in the Fund’s unit price and the increase in per unit distributions were primarily responsible for the higher incentive plan costs. Although staffing levels and administrative activities were greater than 2004, their costs were substantially recovered through allocations to operating activities. Interest expense, net of interest revenue, was $16.2 million for 2005, $4.9 million greater than 2004. Approximately $2.1 million of this increase in interest expense was attributable to the exclusion of the Partnership for the first quarter of 2004, when it was accounted for on an equity basis. The remainder of the increase was due to the higher short term borrowings used to fund inventory and capital projects. Depreciation and amortization expense was $36.9 million for 2005, $15.4 million greater than the previous year. Approximately $5.2 million of this increase was attributable to the exclusion of the Partnership for the first quarter of 2004, when it was accounted for on an equity basis. The remainder of the increase was primarily due to the inclusion of the facilities acquired from EnerPro for the entire twelve months of 2005. The impairment expense of $1.2 million recognized in 2005 related to the disposal of a small, non-core gas processing plant in the Foothills region. In 2004, the impairment expense of $9.0 million related to electrical generation equipment that was not put into service and is currently being held for resale. Equity earnings from long term investments were no longer applicable in 2005, as all investments were consolidated effective July 2, 2004. The $5.3 million of equity earnings recorded in the 2004 results reflects the Fund’s equity earnings in the Partnership and Rimbey Pipe Line, which have been consolidated into the Fund since April 1, 2004 and July 2, 2004 respectively, when control of these entities was acquired. The $1.7 million dilution gain recorded in 2004 was a non-recurring item related to the Fund’s contribution of the EnerPro assets in consideration for an increased interest in the Partnership. Income tax expense for 2005 was $6.6 million, $1.6 million lower than the previous year. A $2.4 million increase in current tax expense due primarily to the inclusion of Rimbey Pipe Line and KEFL for the entire year was more than offset by a $3.9 million reduction in future tax expense. The recovery of future tax was a result of adjustments to opening tax pool balances and lower future tax rates.

Critical Accounting Estimates The Fund’s consolidated financial statements have been prepared in accordance with GAAP. Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the recorded amounts of certain assets, liabilities, revenues and expenses. Management reviews its assumptions and estimates regularly, but new information and changes in circumstances may result in actual results or revised estimates that differ materially from current estimates. The most significant estimates are those indicated below:

Estimation of gathering and processing and NGL infrastructure revenues: For each month, actual volumes processed and fees earned from the gathering and processing and NGL infrastructure assets are not known at the month end. Accordingly, the financial statements contain an estimate of one month’s revenue based upon a review of historic trends. This estimate is adjusted for events that are known to have a significant effect on the month’s operations such as non-routine maintenance projects. At December 31, 2005, operating revenues and accounts receivable for the gathering and processing and NGL infrastructure segments contained an estimate of $14.9 million for December 2005 operations.

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Estimation of gathering and processing and NGL infrastructure operating expenses: The period in which invoices are rendered for the supply of goods and services necessary for the operation of the gathering and processing and NGL infrastructure assets is generally later than the period in which the goods or services were provided. Accordingly, the financial statements contain an estimate of one month’s operating costs based upon a review of historic trends. This estimate is adjusted for events that are known to have a significant effect on the month’s operations such as non-routine maintenance projects. At December 31, 2005, operating expenses and accounts payable contained an estimate of $5.2 million for December 2005 operations.

Estimation of gathering and processing and NGL infrastructure equalization adjustments: Much of the revenue from the gathering and processing and NGL infrastructure assets is generated on a cost- of-service basis. Under this method, the operating component of the fee is a pro rata share of the operating costs for the facility, calculated based upon total throughput. Users of each facility are charged a fee per unit based upon estimated costs and throughput, with an adjustment to actual completed throughput at the end of each year. Each quarter, throughput volumes and operating costs are reviewed to determine whether the estimated unit fee charged during the quarter properly reflects the actual volumes and costs, and the allocation of revenues and operating costs to other plant owners is also reviewed. Appropriate adjustments to revenue and operating expenses is recognized in the quarter and allocations to other owners are recorded. For the gathering and processing and NGL infrastructure segments, operating revenues and accounts receivable contained an equalization adjustment of $2.5 million at December 31, 2005. Operating expenses and accounts payable contained an estimate of $1.1 million.

Estimation of marketing revenues: The majority of NGL marketing sales revenues are recorded based upon actual volumes and prices; however, in many cases actual product lifting volumes have not yet been confirmed or sales prices that are dependent on other variables are not yet known. Accordingly, the financial statements contain an estimate for these sales. Estimates are prepared based upon contract quantities and known events. The estimates are reviewed and compared to expected results to verify their accuracy. They are reversed in the following month and replaced with actual results. At December 31, 2005, marketing sales and accounts receivable contained an estimate for December 2005 revenues of $25.2 million.

Estimation of marketing product purchases: NGL mix (feedstock) and specification products such as propane, butane and condensate are purchased from facilities located throughout western Canada and in some locations in the United States. The majority of NGL mix purchases are estimated each month as actual volume information is generally not available until the next month. The estimates are prepared based upon a three month rolling average of production volumes for each facility and an estimate of price based upon historic information. Specification product volumes and prices are based upon contract volumes and prices. Accordingly, these financial statements contain an estimate for one month of these purchases. Marketing cost of goods sold, inventory and accounts payable contained an estimate of NGL product purchases of $78.5 million at December 31, 2005.

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LIQUIDITY AND CAPITAL RESOURCES Liquidity and working capital Cash provided by operating activities before changes in non-cash working capital was $104.0 million, compared to $60.1 million last year. Approximately $15.7 million of this increase in cash provided by operating activities was attributable to the exclusion of the Partnership for the first quarter of 2004, when it was accounted for on an equity basis. The remainder of the increase was due to the inclusion of the Partnership, Rimbey Pipe Line and the EnerPro assets for the full year of 2005 and the stronger marketing operating margin, partially offset by higher general and administrative costs and current tax expense. Cash and working capital at December 31, 2005 was $9.7 million, down from $34.8 million last year. The decrease in working capital resulted from the use of short-term debt to finance the acquisition of an incremental 24.8% interest in the Strachan plant and related assets. In December 2005, $24.0 million of borrowings were drawn to finance this acquisition, bringing total borrowings from short-term credit facilities to $66.0 million.

Additions to Property, Plant and Equipment Twelve months ended December 31 (in thousands of dollars) 2005 2004 Growth capital expenditures 48.4 22.6 Maintenance capital expentitures 4.5 2.1 Total capital expenditures 52.9 24.7

In 2005, additions to property, plant and equipment amounted to $52.9 million, consisting of $4.5 million of maintenance capital and $48.4 million of growth capital. The maintenance capital expenditures were related to numerous small projects. The most significant growth capital expenditures were $26.4 million for the acquisition of an incremental 24.8% interest in the Strachan plant, an incremental 2.6% interest in the Rimbey plant and a small interest in the Bigoray facility. In addition to increasing Keyera’s future share of operating results from these plants, the increased ownership provides a more flexible operating environment and greater benefit from future business development activities. Other significant growth capital expenditures in 2005 were as follows: • $5.1 million for the construction of the Rat Creek pipeline and installation of incremental compression at Brazeau North to access new volumes • $3.3 million for excavation and ground work related to the brine pond expansion project at Fort Saskatchewan to increase working storage capacity • $3.2 million for efficiency upgrades and plant expansion at Caribou as well as initial work related to the construction of the Caribou North Gas Gathering Pipeline that will extend the plant’s capture area • $2.3 million for the construction of truck terminal facilities to accept oil at Wabasca pipeline • $1.7 million to increase capacity at Worsley to accept new gas • $1.6 million for installation of incremental compression to increase production volumes at the Nordegg River plant • $1.1 million for initial work related to the construction of a new pipeline to extend the Gilby gas plant’s capture area

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In 2006, Keyera expects to spend approximately $2 to $3 million dollars for maintenance capital projects. In addition, it is anticipated that Keyera will spend approximately $21 million for expensed maintenance work. The approved growth capital budget for 2006 is $50 million, but the actual level of growth capital investment is dependent upon available opportunities. Of the 2006 capital budget, more than $30 million has been committed to the following four major projects that are already underway: • Construction of the Caribou North Gas Gathering System • Construction of the new pipeline west of the Gilby plant • Expansion of the Fort Saskatchewan brine pond • Construction of the condensate offload rail facility at Rimbey Pipe Line’s Edmonton terminal Working capital requirements are strongly influenced by the volume of NGLs held in storage and their related commodity prices. NGL inventories are required to meet seasonal demand patterns and will vary depending on the time of year. Historically, the largest allocation of working capital to fund inventory has been approximately $63 million. In addition to the working capital required for inventory, Keyera utilizes approximately $20 to $30 million to finance the other components of working capital. The majority of cash flow is derived from the gathering and processing and NGL infrastructure business segments. The operating income generated from gathering and processing facilities is not significantly exposed to changes in operating costs due to the nature of their fee structure. This fee arrangement provides a mechanism for the recovery of operating costs plus a return on capital. The most significant exposure faced by the gathering and processing and NGL infrastructure businesses is related to declines in production volumes. Without reserve additions, third party production will decline over time as reserves are depleted. As well, commodity prices may decline or production costs may increase and discourage producers from developing additional reserves. Declining production volumes may translate into lower throughput and cash flow at Keyera’s plants and facilities. However, these facilities are located in significant natural gas supply areas of the WCSB and have high barriers to entry for new competitors. Keyera’s cash flows may also be adversely affected by the occurrence of common hazards related to the natural gas processing and pipeline transportation business, such as the failure of equipment, systems or processes, operator error, labour disputes, disputes with owners of interconnected facilities, catastrophic events or acts of terrorism. Given the highly toxic and corrosive nature of sour gas, certain environmental risks are inherent in Keyera’s business. A release of toxic substance could result in damage to the environment and Keyera’s facilities or death or injury, thereby resulting in substantial costs or liabilities to third parties. To mitigate these operational and environmental risks, Keyera maintains written standard operating practices, formally assesses and documents employee competency, and maintains formal inspection, maintenance, safety and environmental programs. Keyera carries casualty and business interruption insurance, although there can be no assurance that the proceeds of such insurance will compensate Keyera fully for any losses nor can it be assured that such insurance will be available in the future. In its marketing business, Keyera’s cash flows are exposed to fluctuations in the prices of the commodities that it buys and sells. This exposure and the related risk mitigation processes are discussed in the Risk Management section of this report. Other risk factors that could affect the financial performance of the Fund are listed in the Unitholder Distributions section of this report. Keyera’s future debt levels are primarily dependent on operating cash flows, working capital requirements and capital investment programs. Management expects the Fund’s 2006 capital expenditures and distributions to be funded by cash flow from operations and borrowing on available debt facilities.

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In order for Keyera to manage seasonal fluctuations in cash flow and working capital, fund growth capital expenditures and stabilize distributions, if required, Keyera has established credit facilities consisting of a $100.0 million revolving term facility that matures on April 21, 2008 and $20.0 million of revolving demand facilities. As at December 31, 2005, $63.0 million was drawn under these credit facilities. Also, a subsidiary of the Partnership has an unsecured revolving credit facility in the amount of $7.0 million. As at December 31, 2005, $3.0 million had been drawn under this credit facility. Management expects that upon maturity of these facilities, adequate replacement facilities will be established. On September 30, 2004, Keyera issued $90.0 million of long-term senior secured notes, through a private placement to investors in the United States. The notes bear interest at 5.23% and mature on October 1, 2009. Keyera has an additional $125.0 million of long-term senior secured notes outstanding. Of that amount, $20.0 million matures in August 2008 and bears interest at 5.42%, $52.5 million matures in August 2010 and bears interest at 5.79%, and $52.5 million matures in August 2013 and bears interest at 6.155%.

Credit risk Credit risk is the risk of loss resulting from non-performance of contractual obligations by a customer or counterparty. The majority of the Partnership’s accounts receivable are due from entities in the oil and gas industry and are subject to normal industry credit risks. Concentration of credit risk is mitigated by having a broad domestic and international customer base. Keyera evaluates and monitors the financial strength of its customers in accordance with its credit policy. Management believes these measures minimize the Partnership’s overall credit risk; however, there can be no assurance that these processes will protect against all losses from non-performance. At December 31, 2005, the accounts receivable from the Partnership’s two largest customers accounted for less than 1% of accounts receivable (2004 – 5%). With respect to counterparties for financial instruments used for economic hedging purposes, Keyera limits its credit risk through dealing with recognized futures exchanges or investment grade financial institutions and by maintaining credit policies which significantly minimize overall counterparty credit risk.

Risk management The marketing of NGLs involves the purchase of NGLs for subsequent sale to wholesale customers. Keyera posts bid prices for physical term purchase arrangements at the Edmonton/Fort Saskatchewan hub. Some of the sales occur soon after the purchases, and in other cases the sales occur in future months. This latter situation results in Keyera having a long position of physical product inventory at certain times of the year. The focus of the risk management program is to protect Keyera’s long position of NGL inventory from changes in commodity prices and to lock in margins. In order to do this, Keyera utilizes financial contracts such as energy related forward sales, price swaps, physical exchanges and options, and generally balances physical and financial contracts in terms of volume, timing of performance and delivery obligations. Occasionally, open positions, primarily attributable to unsold physical inventory, are established to take advantage of market conditions. Positions are regularly monitored and managed by the following processes. Reporting systems capture and report NGL physical and financial transactions and mark them to market. Controls exist to ensure all transactions are captured. Sensitivity analyses are conducted on the NGL transactions to estimate the impact of changes in forward prices. On a monthly basis, or more frequently if required, Keyera’s risk management committee reviews the positions and discusses recent issues related to the market. Transactions are undertaken in accordance with a risk management policy and delegation of authority approved by the Board of Directors.

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Foreign currency rate risk The gathering and processing and NGL infrastructure business segments generated 55% of 2005 operating margin and are not subject to foreign currency rate risk. All sales and virtually all purchases are denominated in Canadian dollars. In the NGL marketing business, approximately $240.0 million of sales or 24% of total marketing revenue were priced in U.S. dollars in 2005.

Commitments Keyera has assumed various contractual obligations in the normal course of its operations. At December 31, 2005, the obligations that represent known future cash payments that are required under existing contractual arrangements are as follows:

Contractual obligations Payments Due by Period (in thousands of dollars) Total 1 Year 2 – 3 Years 4 – 5 Years After 5 Years Long-term debt1 215,000 – 20,000 90,000 105,000 Capital lease obligations – –––– Operating leases2 29,413 7,914 11,688 5,264 4,547 Purchase obligations3 – –––– Total contractual obligations 244,413 7,914 31,688 95,264 109,547

1 Long-term debt obligations do not include interest payments. 2 Keyera has lease commitments relating to railway tank cars, vehicles, computer hardware, office space and natural gas transportation agreements. 3 Keyera is involved in various contractual agreements with ConocoPhillips and other producers to purchase NGLs. These agreements range from one to thirteen years and in general obligate Keyera to purchase all product produced at specified locations on a best efforts basis. The purchase prices are based on then current period market prices. The future volumes and prices for these contracts cannot be reasonably determined.

Control Environment As of December 31, 2005, the Chief Executive Officer and the Chief Financial Officer together with Keyera’s management have evaluated the design and effectiveness of Keyera’s disclosure controls and procedures. They concluded that, as of the end of the period covered by this report, Keyera’s disclosure controls and procedures were adequate and effective in ensuring that material information relating to the Fund and its consolidated subsidiaries would be made known to them by others within those entities, particularly during the period in which this report was being prepared.

Unitholder Distributions The Fund declared $78.5 million of distributions to unitholders in 2005. The Fund’s distributable cash flow of $98.7 million was sufficient to fund all the distributions made to unitholders. The business of the Fund is subject to operational and commercial risks that could adversely affect future earnings and distributable cash flow. These risks include declines in throughput, operational problems and hazards, cost overruns, increased competition, regulatory intervention, environmental considerations, uncertainty of abandonment costs and dependence upon key personnel. These risks are identified and discussed in greater detail in the most recent Annual Information Form available on www.sedar.com. In determining the level of distributions to unitholders, the Board of Directors takes into consideration current and expected future levels of distributable cash flow, growth capital expenditures, debt repayments, working capital requirements and other factors. Standard and Poor’s has assigned the Fund an SR-3 stability rating, indicating the expectation of a high level of stability in distributions.

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Units and Convertible Debentures On September 1, 2005, the Fund adopted a Distribution Reinvestment and Optional Unit Purchase plan (“DRIP”) for eligible unitholders. This plan enables eligible unitholders to reinvest their distributions in Keyera units or make optional cash payments to purchase incremental units. During 2005, $31.0 million of convertible debentures were converted into 2,586,968 trust units, 35,325 trust units were issued under the Long Term Incentive Plan and 88,223 trust units were issued under the DRIP in consideration of $1.6 million, bringing the total units outstanding at December 31, 2005 to 60,125,193. Convertible debentures outstanding at year end were $30.7 million. Subsequent to December 31, 2005, a further $2.5 million of convertible debentures were converted into 210,242 trust units, and 51,420 trust units were issued to unitholders enrolled in the DRIP in consideration for $1.1 million, bringing the total units outstanding at March 3, 2006 to 60,386,855. Convertible debentures outstanding at March 3, 2006 were $28.2 million, which if converted would add 2,349,167 trust units to those outstanding.

NEW ACCOUNTING PRONOUNCEMENTS

Financial Instruments In 2005, the CICA issued the following sections in order to increase harmonization with U.S. and international accounting standards: • Section 1530, Comprehensive Income; • Section 3251, Equity; • Section 3855, Financial Instruments – Recognition and Measurement; and • Section 3865, Hedges. Under these new standards, all financial assets should be measured at fair value with the exception of accounts receivable and investments that are intended to be held to maturity and certain equity investments, which should be measured at cost. All financial liabilities should be measured at fair value when they are held for trading or they are derivatives. The new standard expands the definition of derivatives to include both financial and non-financial contracts. Non-financial contracts would include an agreement to buy or sell a commodity for a fixed price at a future date. Gains and losses on financial instruments measured at fair value will be recognized in net income in the periods they arise with the exception of gains and losses arising from: • financial assets available for sale, in which unrealized gains and losses are deferred in “other comprehensive income” until sold or impaired; and • certain financial instruments that qualify for hedge accounting. Section 3865, Hedges, addresses how hedge accounting is to be performed and requires all gains and losses relating to ineffective hedges to be recorded in net income immediately. Unrealized gains and losses relating to effective cash flow hedges are recognized in “other comprehensive income”. Sections 3855, Financial Instruments – Recognition and Measurement, and 3865, Hedges, require the use of “other comprehensive income”. Other comprehensive income comprises revenues, expenses, gains and losses that are recognized in comprehensive income, but are excluded from net income. Unrealized gains and losses on qualifying hedging instruments, translation of self-sustaining foreign operations, and unrealized gains or losses on financial instruments held for sale will be included in other comprehensive income and reclassified to net income when realized. Section 3251, Equity, requires that “accumulated other comprehensive income” be separately disclosed in the equity section of the balance sheet. These new standards are effective for fiscal years beginning on or after October 1, 2006. The effect on Keyera’s financial position or results of operations of adopting these new requirements is currently being evaluated.

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Non-Monetary Transactions In June 2005, the CICA issued Section 3831, Non-Monetary Transactions, which replaces Section 3830 and requires all non-monetary transactions to be measured at fair value unless: • the transaction lacks commercial substance; • the transaction is an exchange of a product or property held for sale in the ordinary course of business to facilitate sales to customers; • the fair value of the assets of services received or given up is not reliably measureable; and • the transaction is a non-monetary, non-reciprocal transfer to owners. The new requirements apply to non-monetary transactions initiated in periods beginning on or after January 1, 2006. Adoption of this Section is not expected to have a material effect on Keyera’s financial position or results of operations.

SELECTED FINANCIAL INFORMATION The following table presents selected annual financial information for the Fund: (in thousands of dollars, except per unit information) 2003 2004 2005 Operating revenues: Marketing – 631,696 1,013,334 1 Facilities (gathering and processing and NGL infrastructure) – 112,906 174,233 Net earnings 7,587 22,738 60,680 Net earnings per unit ($/unit) Basic 0.57 0.63 1.03 Diluted 0.57 0.55 0.96 Distributions to unitholders 10,805 42,037 78,541 Distributions to unitholders per unit ($/unit) Basic 0.81 1.16 1.33 Diluted 0.81 0.61 1.32 Trust Units outstanding (thousands) Weighted average (basic) 13,357 36,199 58,947 Weighted average (diluted) 13,357 40,941 63,075 Total assets 156,551 1,146,757 1,220,630 Total long-term financial liabilities 1,544 371,000 345,955

1 For 2004, revenue from the facilities segment includes $598 of equity earnings relating to Rimbey Pipe Line.

2005 compared to 2004 For 2005, revenues from marketing were $1.013 billion, up $381.6 million compared to 2004. Approximately $169.0 million of this increase was due to the consolidation of the Partnership beginning on April 1, 2004. The remainder of the increase was largely due to higher sales volumes and historically high commodity prices. Revenues from facilities were $174.2 million, up $61.3 million compared to 2004. Approximately $28.4 million of this increase was attributable to the inclusion of revenue from the Partnership and Rimbey Pipe Line, which were not consolidated until April 1, 2004 and July 2, 2004 respectively. The remainder of the increase was largely due to the inclusion of the facilities acquired from EnerPro for the full year of 2005.

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Net earnings for 2005 were $60.7 million, up $38.0 million compared to 2004. The increase in net earnings was largely due to the inclusion of the Partnership, Rimbey Pipe Line and the EnerPro assets for the full year of 2005. In addition, stronger marketing results also contributed to higher net earnings in 2005. This growth was partly offset by higher general and administrative costs, interest expense and depreciation charges. In 2005, distributions to unitholders increased by $36.5 million due to a higher number of units outstanding as a result of conversions of debentures into trust units. In addition, the Fund increased per unit distributions by approximately 16% compared to 2004.

2004 compared to 2003 The Fund commenced operations on May 30, 2003, with an initial acquisition of a 39.1% indirect interest in the Partnership. For 2003, the investment in the Partnership was accounted for on an equity basis. Accordingly, the only income for 2003 was the Fund’s share of equity earnings in the Partnership. For 2004, the Fund began consolidating the results of operations of the Partnership and Rimbey Pipe Line on April 1, 2004 and July 2, 2004 respectively, as a result of acquiring control. Therefore, the 2003 and 2004 financial results are not directly comparable. In July, 2004, the Fund acquired EnerPro for an aggregate purchase price of $266.9 million plus approximately $8.8 million of working capital adjustments. The acquisition was funded by the issuance of trust units and $100.0 million of 6.75% convertible debentures in June, 2004. The acquisition of the EnerPro facilities increased Keyera’s net processing capacity by approximately 50%. The following table presents selected financial information for the Partnership:

For three months ended Mar 31, Jun 30, Sep 30, Dec 31, Mar 31, Jun 30, Sep 30, Dec 31, (in thousands of dollars) 2004 2004 2004 2004 2005 2005 2005 2005 Operating revenues: Marketing 169,882 147,663 235,316 248,717 228,767 223,590 243,114 317,863 Facilities (gathering, processing and NGL infrastructure) 23,532 27,752 40,928 43,627 39,381 42,792 44,433 47,627 Net earnings 11,921 9,850 6,757 11,969 17,256 14,043 18,545 16,707

December 31, 2005 compared to September 30, 2005 For the fourth quarter of 2005, facilities revenues of $47.6 million increased by $3.2 million compared to the previous quarter. This increase was primarily due to higher throughput volumes and increased flow-through of operating costs. For the fourth quarter of 2005, marketing revenues of $317.9 million increased by $74.7 million compared to the previous quarter. This increase was largely due to the seasonal increase in sales volumes. Net earnings were $16.7 million in the fourth quarter of 2005, down $1.8 million from the previous quarter. This decrease was primarily due to higher general and administrative costs, interest and depreciation charges. The effect of these higher costs was partly offset by the strong marketing results achieved in the fourth quarter.

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September 30, 2005 compared to June 30, 2005 For the third quarter of 2005, operating revenues from facilities were $44.4 million, up $1.6 million compared to the previous quarter. This increase was due to prior period fee recoveries at the Strachan plant and higher revenues from services such as NGL offloading, sulphur handling and reprocessing activities. For the third quarter of 2005, marketing revenues of $243.1 million increased by $19.5 million compared to the previous quarter. This increase was largely due to continued demand for butane and condensate. The price of propane also strengthened in the third quarter of 2005. Net earnings were $18.5 million in the third quarter of 2005, up $4.5 million from the previous quarter. This increase was primarily due to stronger results from facilities in the third quarter as well as lower general and administrative costs and the recognition of an impairment expense of $1.2 million in the second quarter of 2005.

June 30, 2005 compared to March 31, 2005 Operating revenues from facilities for the second quarter of 2005 were $42.8 million, up $3.4 million from the previous quarter. This increase in revenue was largely due to the return of volumes from the Caribou and Strachan plants that experienced unplanned outages in the first quarter of 2005. In addition, volumes were redirected to the Strachan plant in the second quarter due to third party plant turnarounds. For the second quarter of 2005, marketing revenues of $223.6 million decreased by $5.2 million compared to the prior quarter. The decrease in revenues was primarily due to a seasonal decrease in sales volumes that was partially offset by strong condensate and butane price premiums. Net earnings were $14.0 million in the second quarter, down by $3.3 million compared to the first quarter of 2005. This decrease is primarily due to weaker marketing results and an increase in general and administrative costs. General and administrative costs were higher in the second quarter due to higher incentive plan costs. Also in the second quarter, an impairment expense of $1.2 million was recorded to reflect management’s decision to dispose of a small, non-core gas processing plant.

March 31, 2005 compared to December 31, 2004 For the first quarter of 2005, operating revenues from facilities were $39.4 million, down $4.2 million from the prior quarter. This decrease was primarily attributable to unplanned shut-downs at the Caribou and Strachan plants. For the first quarter of 2005, marketing revenues of $228.8 million decreased by $20.0 million compared to the previous quarter. The decrease in revenues was largely due to the seasonal decline in sales of propane. This decline was partly offset by historically high condensate and butane premiums. Net earnings were $17.3 million in the first quarter, up by $5.3 million compared to the prior quarter. This increase is primarily due to increased margins on condensate and butane as well as lower general and administrative costs.

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December 31, 2004 compared to September 30, 2004 For the fourth quarter of 2004, operating revenues from facilities were $43.6 million, up $2.7 million from the previous quarter. The increase was primarily attributable to the flow-through of higher operating and incentive compensation costs. For the fourth quarter of 2004, marketing revenues of $248.7 million increased $13.4 million from the previous quarter due to higher NGL sales volumes and prices during the peak winter season. Also, greater volumes of buy/sell arrangements were done to acquire product for fractionation thereby generating processing fees and increasing facility utilization. Net earnings of $12.0 million were up $5.2 million from the previous quarter. Earnings in the previous quarter included a non-cash charge of $9.0 million for the write-down of an electrical generator, while the fourth quarter saw higher general and administrative costs, depreciation charges and tax expense.

September 30, 2004 compared to June 30, 2004 For the third quarter of 2004, operating revenues from facilities were $40.9 million, up $13.2 million from the previous quarter. The increase was primarily attributable to new EnerPro facilities acquired July 2, 2004. For the third quarter of 2004, marketing revenues of $235.3 million increased $87.7 million from the previous quarter due to higher NGL sales volumes and prices. Sales volumes increased due to the disposition of inventories acquired from EnerPro and a lower than normal inventory build due to high demand. Net earnings for the third quarter of 2004 of $6.8 million decreased by $3.1 million, due primarily to the $9.0 million impairment expense recognized on the electrical generation equipment held for resale and higher depreciation expense.

June 30, 2004 compared to March 31, 2004 For the second quarter of 2004, operating revenues from facilities were $27.8 million, up $4.2 million from the previous quarter. The increase was primarily attributable to the flow-through of turnaround costs at the Nordegg River and Gilby plants. For the second quarter of 2004, marketing revenues of $147.7 million decreased by $22.2 million from the previous quarter due to lower NGL sales volumes partially offset by higher prices. Net earnings for the second quarter of 2004 of $9.9 million decreased by $2.1 million, due primarily to the unrealized loss on financial instruments and higher general and administrative costs partially offset by lower interest expense.

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Auditors’ Report

To the Unitholders of Keyera Facilities Income Fund: We have audited the consolidated statements of financial position of Keyera Facilities Income Fund as at December 31, 2005 and 2004 and the consolidated statements of earnings and unitholders’ equity and cash flows for the years then ended. These financial statements are the responsibility of the management of Keyera Energy Management Ltd. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of Keyera Facilities Income Fund as at December 31, 2005 and 2004 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

Chartered Accountants Calgary, Canada March 3, 2006

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Consolidated Statements of Financial Position

2005 2004 As at December 31 (All amounts expressed in thousands of Canadian dollars) $ $ Assets Current assets Cash and cash equivalents 5,634 11,843 Accounts receivable 191,259 154,324 Inventory 53,205 26,142 Other current assets 4,042 3,600 254,140 195,909

Property, plant and equipment (note 4) 881,330 862,324 Asset held for sale (note 5) 4,573 4,735 Intangible assets (note 6) 80,587 83,789 1,220,630 1,146,757

Liabilities and Unitholders’ Equity Current liabilities Accounts payable and accrued liabilities 171,316 141,290 Distribution payable (note 13) 7,155 5,627 Other current liabilities (note 15) – 2,192 Current portion of debt (note 7) 66,000 12,000 244,471 161,109

Long-term debt (note 7) 215,000 215,000 Convertible debentures (note 8) 30,713 61,757 Asset retirement obligation (note 9) 27,776 24,188 Future income tax liability (note 10) 72,466 70,055 590,426 532,109

Non-controlling interest 2,198 2,000

Unitholders’ equity Unitholders’ capital (note 11) 668,384 635,165 Accumulated earnings 91,005 30,325 Accumulated cash distributions to unitholders (notes 12 and 13) (131,383) (52,842) 628,006 612,648 1,220,630 1,146,757

Commitments and contingencies (note 17)

SEE ACCOMPANYING NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS Approved on behalf of the Fund by its administrator, Keyera Energy Management Ltd.:

Wesley R. Twiss Jim V. Bertram Director Director

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Consolidated Statements of Earnings and Unitholder’s Equity

For the Years Ended December 31 2005 2004 (All amounts expressed in thousands of Canadian dollars, except per unit information) $ $

Operating revenues Marketing sales 1,013,334 631,696 Gathering and processing 139,274 90,346 NGL infrastructure 34,959 21,962 1,187,567 744,004 Operating expenses Marketing cost of goods sold 946,263 601,328 Gathering and processing 67,469 40,210 NGL infrastructure 24,296 16,449 1,038,028 657,987 149,539 86,017

General and administrative 25,217 13,533 Interest expense 16,213 11,303 Depreciation and amortization 36,887 21,512 Accretion expense (note 9) 2,048 1,236 Impairment expense 1,160 8,981 Equity earnings from long-term investments (note 3) – (5,258) Dilution gain – (1,749) 81,525 49,558 Earnings before tax and non-controlling interest 68,014 36,459 Income tax expense (note 10) 6,630 8,164 Earnings before non-controlling interest 61,384 28,295 Non-controlling interest 704 5,557 Net earnings 60,680 22,738

Accumulated earnings, beginning of year 30,325 7,587 Accumulated earnings, end of year 91,005 30,325

Weighted average number of units (thousands) (note 11) – basic 58,947 36,199 – diluted 63,075 40,941 Net earnings per unit (note 11) – basic 1.03 0.63 – diluted 0.96 0.55

SEE ACCOMPANYING NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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Consolidated Statements of Cash Flows

For the Years Ended December 31 2005 2004 (All amounts expressed in thousands of Canadian dollars) $ $

Net inflow (outflow) of cash: Operating activities Net earnings 60,680 22,738 Items not affecting cash: Depreciation and amortization 36,887 21,512 Accretion expense 2,048 1,236 Impairment expense 1,160 8,981 Unrealized loss on financial instruments 280 899 Future income tax expense (note 10) 2,411 6,358 Non-controlling interest 704 5,557 Asset retirement obligation expenditures (note 9) (183) (171) Equity earnings from long-term investments – (5,258) Dilution gain – (1,749) Changes in non-cash operating working capital (33,931) (8,703) 70,056 51,400

Investing activities Additions to property, plant and equipment (note 4) (52,870) (24,659) Proceeds on sale of assets 907 – Acquisitions – (279,826) Acquisition of investments – (307,732) Working capital acquired on acquisitions – (31,454) Cash and debt acquired on acquisitions – 19,395 Dividends on investments – 919 (51,963) (623,357)

Financing activities Issuance of short-term debt 54,000 7,500 Issuance of convertible debentures – 100,000 Issuance of trust units (note 11) 2,175 463,354 Issuance costs on trust units – (24,657) Interest paid on convertible debentures (2,958) (3,576) Issuance of long-term debt (note 7) – 90,000 Deferred financing costs – (4,900) Distributions received from Partnership – 4,631 Distributions paid to unitholders (note 13) (77,013) (37,954) Distributions or dividends paid to others (506) (10,598) (24,302) 583,800 Net cash (outflow) inflow (6,209) 11,843 Cash and cash equivalents, beginning of year 11,843 – Cash and cash equivalents, end of year 5,634 11,843

SEE ACCOMPANYING NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

SEE NOTE 18 FOR CASH INTEREST AND TAXES PAID

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Notes to Consolidated Financial Statements

For the years ended December 31, 2005 and 2004 (All amounts expressed in thousands of Canadian dollars, except where otherwise noted)

1. Structure of the Fund Keyera Facilities Income Fund (the “Fund”) is an unincorporated open-ended trust established under the laws of the Province of Alberta pursuant to the Fund Declaration of Trust dated April 3, 2003. The Fund indirectly owns a 100% interest in Keyera Energy Partnership (the “Partnership”). The Partnership is involved in the business of natural gas gathering and processing, as well as natural gas liquids (“NGL”) processing, transportation, storage and marketing. Its wholly-owned subsidiaries include Keyera Energy Facilities Limited (“KEFL”) and Keyera Energy Ltd. (“KEL”). The Fund is administered by and the Partnership is managed by Keyera Energy Management Ltd. (“KEML” or the “Managing Partner”). The Managing Partner has a 0.005% interest in the Partnership. The Fund commenced operations on May 30, 2003, with the initial acquisition of a 39.1% interest in the Partnership and the Managing Partner. The acquisition of the Fund’s indirect and direct interest in the Partnership and the Managing Partner respectively, had been accounted for on an equity basis prior to April 1, 2004 (see note 3). On April 1, 2004, the Fund acquired an additional 35.9% interest in the Partnership and the Managing Partner, giving the Fund a controlling interest of 75% in the Partnership and the Managing Partner. The controlling interests in the Partnership and the Managing Partner increased to 82.6% on July 2, 2004 through a contribution of assets. On December 2, 2004, the Fund acquired the remaining 17.4% interests in the Partnership and KEML, giving the Fund a 100% indirect and direct controlling interests in both the Partnership and the Managing Partner. The Fund makes monthly cash distributions to unitholders of record on the last business day of each month. The amount of the distributions per trust unit are equal to the pro rata share of the distribution received indirectly from the Partnership and, in the event of the termination of the Fund, participating pro rata in the net assets remaining after satisfaction of all liabilities.

2. Summary of significant accounting policies Principles of consolidation These consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles. The consolidated financial statements include the accounts of the Fund and all controlled entities. Investments in companies in which the Fund does not have direct or joint control over the strategic, investing and financing decisions, but does have significant influence, are accounted for using the equity method.

Measurement uncertainty The preparation of financial statements in accordance with Canadian generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. These include the recoverability of assets and the amounts recorded for depreciation, amortization, accretion and asset retirement obligations, which depend on estimates of oil and gas reserves or the economic lives and future cash flows from related assets. The recognized amounts of such items are based on management’s best information and judgment.

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2. Summary of significant accounting policies (continued)

Foreign currency translation Monetary assets and liabilities denominated in foreign currencies are translated at exchange rates in effect at the balance sheet date. Revenues and expenses are translated at rates of exchange in effect at the transaction date. Exchange gains and losses are recorded in earnings in the period they are incurred.

Revenue recognition Marketing revenue Revenue from the sale of natural gas and natural gas liquids is recognized based on volumes delivered to customers at contractual delivery points and rates. Gathering and processing revenue Gathering and processing revenue is recognized through fixed fee arrangements or flow-through arrangements that are designed to recover operating costs and provide the Partnership a return on its capital. Amounts collected in excess of the recoverable amounts are recorded as a current liability. Recoverable amounts in excess of the amounts collected are recorded as a current receivable. NGL infrastructure revenue Revenue from transportation, processing and storage of NGLs is recognized through fee-for-service arrangements. The fee is comprised of a fixed charge per unit transported or processed. Revenue is recognized when services have been performed.

Joint ventures Substantially all natural gas gathering and processing and NGL infrastructure activities are conducted jointly with others, and accordingly these financial statements reflect only the Fund’s indirect proportionate interest in such activities.

Financial instruments Derivative financial instruments are utilized by the Fund through its ownership in the Partnership to mitigate its exposure to fluctuations in the price of natural gas, natural gas liquids and electricity and currency exchange rates. The Fund uses a variety of instruments to manage these exposures including swaps and options. Gains and losses related to derivative contracts are recognized in marketing revenue. The Fund may elect to use hedge accounting. To be accounted for as a hedge, a derivative financial instrument must be designated and documented as a hedge and must be effective at inception and on an on-going basis. The documentation defines the relationships between the hedging items and the hedged items and documents the objectives and strategies for undertaking various hedge transactions. The process includes linking derivative financial instruments to specific anticipated transactions. The Partnership also formally assesses, both at the inception of the hedge and on an ongoing basis, whether the instrument used is highly effective in offsetting changes in cash flows or fair values of the hedged item. Hedge effectiveness is achieved if the cash flows from the hedging item substantially offset the cash flows of the hedged item and the timing of the cash flows is similar or if changes in the fair value of the financial instrument substantially offset changes in the fair value of the related asset or liability.

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2. Summary of significant accounting policies (continued)

If designated as a hedge, gains and losses on these instruments are deferred and recognized in earnings in the same period as the hedged item. The fair value of derivative financial instruments qualifying for hedge accounting is not recorded on the consolidated statements of financial position. When a hedging derivative financial instrument matures, expires, is sold, terminated or cancelled and is not replaced as part of the Partnership’s hedging strategy, the termination gain or loss is deferred and recognized when the gain or loss on the hedged item is recognized. If a designated hedged item matures, expires, is sold, extinguished or terminated and the hedged item is no longer probable of occurring, any previously deferred amounts associated with the hedging item are recognized in current earnings along with the corresponding gains or losses recognized on the hedged item. If a hedging relationship is terminated or ceases to be effective, hedge accounting is not applied to subsequent gains or losses. Any previously deferred amounts are carried forward and recognized in earnings in the same period as the underlying hedged item.

Cash and cash equivalents Cash and cash equivalents include short-term investments with maturity of three months or less when purchased.

Inventory Inventory is comprised primarily of NGL product for sale through the marketing operations. Inventory is valued at the lower of cost and net realizable value. Cost is determined on a weighted average cost basis, calculated monthly.

Property, plant and equipment Property, plant and equipment consist of natural gas processing and gathering systems and NGL infrastructure facilities which were recorded at cost. Depreciation of these facilities is provided for on a straight-line basis over the estimated useful life of each facility, the periods of which range from seven to thirty-four years. Impairment on property, plant and equipment is measured as the amount by which the carrying value of an asset or asset group exceeds its fair value, as determined by the discounted future cash flows of the asset or asset group.

Intangible assets Intangible assets consist of the marketing business contributed by the partners when the Partnership was first formed and the marketing business contracts acquired on business combinations. These assets have been recorded at the fair market values at the time of the contribution and acquisition. These amounts are being amortized over their estimated economic life. The unamortized balance of these costs is assessed periodically for impairment based on management’s best estimates of future net revenues from marketing operations. Intangible assets also consist of deferred financing fees and goodwill. Amortization of deferred costs is provided for on a straight-line basis over the weighted average term of the related debt offering. The goodwill which resulted from business combinations is assessed for impairment annually at year end on a reporting unit basis by determining whether the balance of goodwill can be recovered through the estimated discounted operating cash flows of each reporting unit over their remaining life.

Asset retirement obligation The asset retirement cost, deemed to be the fair value of the asset retirement obligation, is capitalized as part of the cost of the related long-lived asset and allocated to expense on a basis consistent with depreciation and amortization. Amortization of asset retirement costs is included in depreciation and amortization in the consolidated statement of earnings. The amount of the liability is revised periodically in accordance with changes in the assumptions and estimates underlying the calculations. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion expense in the consolidated statement of earnings, over the estimated time period until settlement of the obligation. Actual expenditures incurred are charged against the accumulated asset retirement obligation.

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2. Summary of significant accounting policies (continued)

Income taxes Under the terms of the Canadian Income Tax Act, the Fund is considered to be a “mutual fund trust” and is taxable only to the extent that its income is not distributed or distributable to its unitholders. The Fund is contractually committed to distribute to its unitholders all or virtually all of its taxable income and taxable capital gains that would otherwise be taxable in its hands and the Fund intends to continue to distribute to its unitholders so that it is not subject to income taxes. All subsidiaries of the Fund follow the liability method of accounting for income taxes. Under this method, these subsidiaries record the future income tax basis of an asset or liability, using the substantively enacted income tax rates. Accumulated future income tax balances are adjusted to reflect a change in the income tax rates and the adjustment is recognized in earnings in the period in which the change occurs.

Stock-based compensation The Fund has a Long Term Incentive Plan (“LTIP”), which is disclosed in note 14. The LTIP is a stock appreciation right as defined by the Canadian Institute of Chartered Accountants. The difference between the market price of the trust units and the grant price for the outstanding units multiplied by the number of rights is recognized as compensation expense, over the vesting period. Fluctuations in the price of the trust units will change the accrued compensation expense and are recognized when they occur.

Net earnings per unit Basic net earnings per unit are calculated by dividing net earnings, respectively, by the weighted average number of units outstanding during the period. For the calculation of the weighted average number, trust units are determined to be outstanding from the date they are issued. Diluted net earnings per unit is calculated by adding the weighted average number of units outstanding during the period to the additional units that would have been outstanding if potentially dilutive units had been issued, using the “treasury stock” method.

Distributions to unitholders The monthly amount of the distributions to unitholders of the Fund is defined in the Fund Declaration of Trust. The computation of the distributions to unitholders is comprised of cash amounts received or receivable as distributions or interest income and any net proceeds from the issuance of trust units, less any amounts that relate to the redemption of trust units and any expenditures of the Fund. Distributions to unitholders, as defined above, is not a measure under Canadian generally accepted accounting principles and there is no standardized measure of distributions to unitholders. Distributions to unitholders, as presented, may not be comparable to similar measures presented by other income trusts.

Comparative figures Certain amounts in the 2004 financial statements have been reclassified to conform to the current year financial statement presentation.

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3. Acquisitions of long-term investments Initial Offering In 2003, the Fund issued 17,000,000 trust units as an initial public offering (the “Initial Offering”) at a price of $10.00 per trust unit for net proceeds of $158,225 after issuance fees of $11,775. The net proceeds received from the Initial Offering were used to purchase a 39.1% indirect interest in the Partnership for consideration of $158,217 from KeySpan Energy Development Co. (“KEDCO”).

Second Offering On April 1, 2004, the Fund issued 15,617,000 trust units in a second public offering (the “Second Offering”) at a price of $12.60 per trust unit for net proceeds of $186,335 after issuance costs of $10,439. The net proceeds received from the Second Offering were used to purchase a further 35.9% indirect interest in the Partnership and the Managing Partner for consideration of $186,335 accounted for using the purchase method. The investments in the Partnership and KEML were comprised of: Partnership KEML Total $$ $ Acquisition cost 158,217 8 158,225 Equity earnings 7,587 – 7,587 Distributions to the Fund (10,805) – (10,805) Investment in the Partnership, December 31, 2003 154,999 8 155,007 Equity earnings 4,659 1 4,660 Distributions to the Fund (4,631) – (4,631) Investment in the Partnership, March 31, 2004 155,027 9 155,036 Acquisition cost 186,327 8 186,335 Investment in the Partnership, April 1, 2004 341,354 17 341,371

Prior to April 1, 2004 the Fund’s investments in the Partnership and the Managing Partner were accounted for using the equity method as the Fund did not have direct control over the strategic, investing, and financing decisions but had significant influence. The purchase on April 1, 2004 of the 35.9% interests in the Partnership and the Managing Partner increased the ownership interests held by the Fund from 39.1% to 75%. As a result, effective April 1, 2004, the results of operations of the Partnership and the Managing Partner were consolidated with those of the Fund. The non-controlling interests in the Partnership and the Managing Partner were reflected in non-controlling interest on the consolidated financial statements in 2004. The difference between the value of the transaction and the carrying value of the net assets of the Partnership and the Managing Partner resulted in a difference of $27,637 which was applied to property, plant and equipment.

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3. Acquisitions of long-term investments (continued)

As at June 30, 2004, the total purchase price of $344,560 for the Fund’s 75% interest in the Partnership and the Managing Partner was allocated as follows: $ Cash 14,399 Current assets 125,125 Property, plant and equipment 405,843 Other assets 13,716 Long-term investment 13,941 Intangible assets 6,442 Deferred costs 1,121 Future income tax asset 3,429 Current liabilities (103,453) Long-term debt (125,000) Asset retirement obligation (11,003) 344,560

Third Offering On June 3, 2004, the Fund issued 9,325,000 trust units in a third public offering (the “Third Offering”) at a price of $10.75 per trust unit, with an over-allotment of 1,398,750 trust units issued on June 10, 2004, for net proceeds of $109,118 after underwriters’ fee of $5,764 and issuance costs of $398. In conjunction with the Third Offering, the Fund issued convertible unsecured subordinated debentures in the principal amount of $100,000, for net proceeds of $95,669 after underwriters’ fee of $4,000 and issuance costs of $331.

Fourth Offering On December 2, 2004, the Fund issued 10,872,333 trust units in a fourth public offering (the “Fourth Offering”) at a price of $13.90 per trust unit for net proceeds of $143,069 after underwriters’ fee of $7,556 and issuance costs of $500. The proceeds of the Fourth Offering were used to acquire the remaining interests in the Partnership and the Managing Partner from KEDCO, thus resulting in the Fund owning a 100% indirect and direct controlling interests in the Partnership and the Managing Partner, respectively. KEML continues to hold a 0.005% interest in the Partnership. The acquisition of the remaining 17.44% interests in the Partnership and Managing Partner fully eliminated the non-controlling interests on the balance sheet of $118,405, with an increase to unitholders’ capital equal to the net proceeds of $143,069 and an addition to property, plant and equipment of $24,664.

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4. Property, plant and equipment Accumulated Net Book Cost Depreciation Value $$$ Beginning balance 2004 ––– Acquisitions of investments 692,926 (97,616) 595,310 Additions, net 25,253 – 25,253 Acquisitions 262,236 – 262,236 Depreciation – (20,475) (20,475) Ending balance 2004 980,415 (118,091) 862,324 Additions, net 51,602 1,088 52,690 Depreciation – (33,684) (33,684) Ending balance 2005 1,032,017 (150,687) 881,330

Acquisitions On June 29, 2004, the Partnership acquired 100% of El Paso Velvet Processing Limited Partnership from wholly-owned subsidiaries of El Paso Corporation, for an aggregate purchase price of $7,000, plus an adjustment for net working capital and transaction costs. The El Paso Velvet Processing Limited Partnership owned 100% of the Caribou gas plant, associated gathering pipelines and related acid gas disposal infrastructure. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition. The results of operations have been included in the consolidated statement of earnings effective July 1, 2004. $ Net working capital 548 Property, plant and equipment 7,650 Asset retirement obligation (1,012) 7,186

On July 2, 2004, the Fund indirectly acquired 100% of the shares of EnerPro Midstream Company (“EnerPro”) for $272,815 plus acquisition costs of $2,645 and working capital adjustments, which were incurred directly by the Partnership. The Fund then contributed the assets of EnerPro to the Partnership, thereby increasing the Fund’s indirect interest in the Partnership and the Managing Partner from 75% to 82.6%. The acquisition has been accounted for as a business combination and was allocated as follows: $ Current assets 8,861 Property, plant and equipment 270,086 Goodwill 64,934 Other intangible assets 8,174 Future income tax liability (64,934) Asset retirement obligation (8,765) 278,356

Upon the acquisition of EnerPro and the contribution of assets to the Partnership, the Fund owned an indirect controlling interest in Rimbey Pipe Line Co. Ltd. (“Rimbey Pipe Line”) through its indirect ownership of the Partnership and KEFL (see note 1). The results of operations of Rimbey Pipe Line are consolidated beginning on July 2, 2004. The non-controlling interest in Rimbey Pipe Line is reflected in the consolidated financial statements.

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5. Asset held for sale In 2004, the Partnership concluded its review of project opportunities for its 50% interest in an electrical generator and chose not to proceed with putting it into service. Accordingly, the equipment was written down to its estimated net realizable value of $4,735 and classified as asset held for sale. In 2005, a portion of the equipment was sold for proceeds of $162.

6. Intangible assets 2005 2004 As at December 31 $ $ Goodwill 64,934 64,934 Other intangible assets (a) 10,997 13,298 Deferred financing costs (note 7 (e)) 4,656 5,557 Total 80,587 83,789

(a) Other intangible assets consist of the marketing business contributed by the Partners when the Partnership was first formed and the marketing business of EnerPro acquired on July 2, 2004 (see note 4). The unamortized balance of the intangible assets is assessed periodically for impairment based on management’s best estimates of future net revenues from marketing operations, and is being amortized over the remaining economic life of three to eight years.

7. Long-term debt 2005 2004 As at December 31 $ $

Bank credit facilities (a) 63,000 7,500 Senior secured notes (b & c) 215,000 215,000 Revolving demand loan (d) 3,000 4,500 281,000 227,000 Less: current portion of long-term debt (66,000) (12,000) Long-term debt 215,000 215,000

(a) The Partnership has a $100,000 unsecured revolving credit facility with certain Canadian financial institutions led by the Royal Bank of Canada. The facility has a three year revolving term and matures on April 21, 2008, unless extended. In addition, the Royal Bank of Canada and the Toronto Dominion Bank have each provided a $10,000 revolving demand facility. The revolving credit facilities bear interest based on the lenders’ rates for Canadian prime commercial loans, U.S. Base rate loans, Libor loans or Bankers’ Acceptances rates. The weighted average interest rate for the year ended December 31, 2005 was 4.40% (2004 – 4.30%). As at December 31, 2005, the balance outstanding on the bank credit facilities was $63,000 (2004 – $7,500). (b) In 2003, $125,000 of unsecured senior notes were issued by the Partnership and KEFL in three parts: Series A of $52,500 due in 2010, bearing interest at 5.79%, Series B of $52,500 due in 2013, bearing interest at 6.155%, and $20,000 due in 2008, bearing interest at 5.42%. Interest is payable monthly. Financing costs of $1,215 have been deferred and are amortized over the remaining terms of the related debt. Amortization expense of $163 has been recorded for the year ended December 31, 2005 (2004 – $122).

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7. Long-term debt (continued)

(c) On September 30, 2004, $90,000 of unsecured senior notes were issued by KEFL and guaranteed by the Partnership. The notes bear interest at 5.23%, payable semi-annually, and mature on October 1, 2009. Financing costs of $568 have been deferred and are amortized over the term of the debt. Amortization expense of $114 has been recorded for the year ended December 31, 2005 (2004 – $28). (d) A subsidiary of the Partnership has an unsecured revolving demand loan facility with a major Canadian chartered bank in the amount of $7,000, of which $3,000 was drawn as at December 31, 2005 (2004 – $4,500). Borrowings under the loan facility bear interest based on the lender’s rates for Canadian prime commercial loans or Bankers’ Acceptances rates. The weighted average interest rate for the year ended December 31, 2005 was 4.13% (2004 – 3.76%). (e) Deferred financing costs as at December 31: 2005 2004 $ $

Deferred financing costs on convertible debentures (note 8) 3,395 4,019 Deferred financing costs, net (b) 835 998 Deferred financing costs, net (c) 426 540 4,656 5,557

8. Convertible debentures On June 3, 2004, the Fund issued convertible unsecured subordinated debentures in the principal amount of $100,000, subject to an underwriters’ commission of $4,000 and issuance costs of $332. These costs have been deferred and are being amortized over the term of the debt. Amortization expense of $624 has been recorded for the year ended December 31, 2005 (2004 – $313). The proceeds were used for the acquisition of EnerPro (see note 4). The convertible debentures bear interest at 6.75% per annum, payable semi-annually in arrears on June 30 and December 31 each year. Interest expense of $2,958 has been accrued for the year ended December 31, 2005 (2004 – $3,578). These debentures will mature on June 30, 2011 and are convertible into trust units of the Fund at the option of the holders at any time prior to maturity at a conversion price of $12.00 per unit. At December 31, 2005, $69,287 (2004 – $38,243) debentures had been converted to trust units.

9. Asset retirement obligation The following table presents the reconciliation between the beginning and ending aggregate carrying amount of the obligation associated with the retirement of the gathering and processing and the NGL infrastructure facilities.

2005 2004 For the year ended December 31 $ $ Asset retirement obligation, beginning of year 24,188 11,003 Liabilities acquired 744 11,581 Liabilities settled (183) (171) Revisions in estimated cash flows 979 539 Accretion expense 2,048 1,236 Asset retirement obligation, end of year 27,776 24,188

The total undiscounted amount of cash flows required to settle the asset retirement obligations is $168,150 which has been discounted using a credit-adjusted risk-free rate of 7% (2004 – $154,927). The majority of these obligations are expected to be settled between 2018 and 2038. No assets have been legally restricted for settlement of the liability.

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10. Income taxes The Fund is a unit trust for income tax purposes. As such, the Fund is only taxable on any taxable income not allocated to the unitholders. Each unitholder resident in Canada will be required to include in computing income for tax purposes for a particular taxation year the pro rata share of the Fund’s income that was paid or payable in that year to the unitholder and that was deducted by the Fund in computing its income. The following is a reconciliation of income taxes, calculated at the combined federal and provincial income tax rates, to the income tax provision included in the consolidated statements of earnings. 2005 2004 $ $ Earnings before tax and non-controlling interest 68,014 36,459 Income from the Fund distributed to unitholders (42,653) 18,095 Income before taxes – operating subsidiaries 25,361 18,364 Income tax at statutory rate of 37.62% (2004 – 38.62%) 9,541 7,092

Non-deductible items excluded from income for tax purpose 2,083 (776) Resource allowance (51) (95) Adjustments to tax pool balances (3,554) 1,536 Changes in estimates (2,467) 436 Benefit of non-capital losses not recorded 442 – Other (392) (387) Alternative minimum tax – 173 Large corporation tax 1,028 185 6,630 8,164 Classified as: Current 4,219 1,806 Future 2,411 6,358 Income tax expense 6,630 8,164

For income tax purposes, the subsidiaries of the Fund have non-capital losses carried forward of approximately $2,773 (2004 – $5,503) which are available to offset income of specific entities of the consolidated group in future periods. The benefit of these losses has not been recorded at December 31, 2005. The future income tax liability relates to the (taxable) deductible temporary differences in the carrying values and tax bases as follows: 2005 2004 As at December 31: $ $ Property, plant and equipment (75,827) (74,872) Intangible assets (956) (1,299) Deferred financing costs (128) (114) Asset retirement obligation 4,104 3,635 Non-capital losses carried forward – 1,960 Other 341 635 Future income tax liability (72,466) (70,055)

The unrecorded future tax liability attributable to the Partnership at December 31, 2005 was $84,612 (2004 – $79,320).

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11. Unitholders’ capital The Fund Declaration of Trust provides that an unlimited number of trust units may be authorized and issued. Each trust unit is transferable, and represents an equal undivided beneficial interest in any distribution from the Fund and in the net assets of the Fund in the event of termination or winding-up of the Fund. All trust units are of the same class with equal rights and privileges. The Declaration of Trust also provides for the issuance of an unlimited number of special trust units that can be used solely for providing voting rights to persons holding securities that are directly or indirectly exchangeable for units and that, by their terms, have voting rights in the Fund. The trust units are redeemable at the holder’s option at an amount equal to the lesser of: (i) 90% of the weighted average price per unit during the period of the last 10 trading days during which the units were traded on the Toronto Stock Exchange; and (ii) an amount equal to (a) the closing market price of the units; (b) an amount equal to the average of the highest and lowest prices of units on the date on which the units were tendered for redemption; or (c) the average of the last bid and ask prices if there was no trading on the date on which the units were tendered for redemption. Redemptions are subject to a maximum of $50 cash redemptions in any particular month. Redemptions in excess of this amount will be paid by way of a distribution in specie of assets of the Fund that may include Commercial Trust Series 1 notes. In 2005, the Fund instituted a Distribution Reinvestment and Optional Unit Purchase Plan (“DRIP”) that permits unitholders to reinvest cash distributions for additional units. This plan allows eligible participants an opportunity to reinvest distributions into trust units at a 3% discount to a weighted average market price, so long as units are issued from treasury under the DRIP. The Fund has the right to notify participants that units will be acquired in the market, in which case units will be purchased at the weighted average market price. Eligible unitholders can also make optional unit purchases under the optional unit purchase component of the plan at the weighted average market price.

Trust units issued and unitholders’ capital Number of Units $ Beginning balance, 2004 17,000,000 158,225 Units issued for cash, April 2004 15,617,000 196,774 Less: issuance costs – (10,439) Units issued for cash, June 2004 10,723,750 115,280 Less: issuance costs – (6,162) Units issued pursuant to long-term incentive plan 14,684 175 Units issued on conversion (note 8) 3,186,910 38,243 Units issued for cash, December 2004 10,872,333 151,125 Less: issuance costs – (8,056) Ending balance, 2004 57,414,677 635,165 Units issued on conversion (note 8) 2,586,968 31,044 Units issued pursuant to distribution reinvestment plan 88,223 1,598 Units issued pursuant to long-term incentive plan 35,325 577 Ending balance, 2005 60,125,193 668,384

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11. Unitholders’ capital (continued)

Net earnings per unit Basic per unit calculations for the year ended December 31, 2005 and 2004 were based on the weighted average number of units outstanding for the year. Convertible debentures were in the money for the year ended December 31, 2005 and 2004 and attributed to the increase in diluted weighted average number of units for 2005 and 2004.

(thousands) 2005 2004 Weighted average number of units – basic 58,947 36,199 Net additional units if incentive awards vested 485 301 Additional units if debentures converted 3,643 4,441 Weighted average number of units – diluted 63,075 40,941

12. Distributable cash flow The Fund makes monthly distributions to holders of record on the last day of each month from its distributable cash flow. Payments are made on or about the 15th day of the following month. The amount of distributable cash flow for each month will generally be the cash flow from operations for such month, including dividends received from investments, and after deducting interest, income tax, and other expenses, less maintenance capital expenditures, expenditures related to asset retirement and site reclamation, and the distributable cash flow attributable to any non-controlling interest. Distributable cash flow, as defined above, is not a measure under Canadian generally accepted accounting principles and there is no standardized measure of distributable cash flow. Distributable cash flow, as presented, may not be comparable to the calculations of similar measures for by other entities. The following table calculates the Fund’s distributable cash flow: 2005 2004 $ $ Net earnings 60,680 22,738 Add (deduct): Depreciation and amortization 36,887 21,512 Accretion expense 2,048 1,236 Impairment expense 1,160 8,981 Unrealized loss on financial instrument 280 899 Future income tax expense 2,411 6,358 Non-controlling interest 704 5,557 Asset retirement obligation expenditures (183) (171) Equity earnings from investments – (5,258) Dividends received from investments – 5,762 Dilution gain – (1,749) Maintenance capital (4,472) (2,075) Non-controlling interest distributable cash flow (782) (10,851) Distributable cash flow 98,733 52,939

Distributions to unitholders 78,541 42,037

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13. Accumulated distributions to unitholders $ Beginning balance, 2004 10,805 Unitholders’ distributions declared and paid 36,410 Unitholders’ distributions declared 5,627 Ending balance, 2004 52,842 Unitholders’ distributions declared and paid 71,386 Unitholders’ distributions declared 7,155 Ending balance, 2005 131,383

14. Compensation plans The Long Term Incentive Plan (the “LTIP” or the Plan“) compensates officers, directors, key employees and consultants by delivering units of the Fund or paying cash in lieu of units. Participants in the LTIP are granted rights (”unit awards“) to receive units of the Fund on specified dates in the future. The Plan permits the directors of KEML to authorize the grant of unit awards from time to time. Units can be issued from treasury or acquired in the marketplace under the plan. A maximum of 1,300,000 units have been reserved for issue from treasury under the Plan. The Plan consists of two types of unit awards, which are described below. Management accounts for unit awards and the issuance of units under the Plan in accordance with the intrinsic value method of accounting for stock-based compensation. The aggregate compensation cost recorded for the Plan was $10,589 for the year ended December 31, 2005 (2004 – $2,782).

(a) Performance Unit Awards The Performance Unit Awards will vest 100% on the third anniversary of each grant date, July 1, 2003 and July 1, 2004 and July 1, 2005. The number of units to be issued will be determined by the financial performance of the Fund over the three-year period. The number of units to be issued will be calculated by multiplying the number of unit awards by an adjustment ratio and a payout multiplier. The adjustment ratio increases the number of units to be issued to reflect the per unit cash distributions paid by the Fund to its unitholders during the term that the unit award is outstanding. The payout multiplier is based upon the actual three-year average annual cash distributions per unit of the Fund. The table below describes the relationship between the three-year average annual cash distribution per unit and the payout multiplier. Three-year annual cash distributions per unit July 1, 2003 Grant July 1, 2004 Grant July 1, 2005 Grant Payout Less than 1.09 Less than 1.15 Less than 1.32 Nil First range 1.09 – 1.18 1.15 – 1.22 1.32 – 1.39 50% – 99% Second range 1.19 – 1.38 1.23 – 1.38 1.40 – 1.55 100% – 199% Third range 1.39 and greater 1.39 and greater 1.56 and greater 200%

As of December 31, 2005, 478,172 Performance Unit Awards (2004 – 294,262) were outstanding: 122,400 were granted on July 1, 2003, 164,737 on July 1, 2004 and 191,035 on July 1, 2005. The compensation cost recorded for these units for the year ended December 31, 2005 was $8,246 (2004 – $1,903) using the closing market price of a unit of the Fund on January 3, 2006.

(b) Time Vested Unit Awards (”Restricted Unit Awards“) Restricted Unit Awards will vest automatically, over a three-year period from the effective date of the award on July 1, 2003, July 1, 2004 and July 1, 2005 regardless of the performance of the Fund. The number of units to be issued will be increased by an adjustment ratio which reflects the per unit distributions paid by the Fund to its unitholders during the term that the unit award is outstanding.

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14. Compensation plans (continued)

As of December 31, 2005, 123,427 Restricted Unit Awards (2004 – 133,355) were outstanding: 23,233 were granted on July 1, 2003, 56,009 on July 1, 2004 and 44,185 on July 1, 2005. The compensation cost recorded for these units for the year ended December 31, 2005 was $2,343 (2004 – $879) using the closing market price of a unit of the Fund on January 3, 2006. During the year ended December 31, 2005, 35,325 units were issued from treasury and $577 was credited to unitholders’ equity in respect to the units issued. In addition, the equivalent of 23,971 of unit awards were settled in cash.

15. Related party transactions Prior to April 1, 2004, KEML was a 39.1% owned subsidiary of the Fund. KEML provides management and administrative services to the Fund and the Partnership on a cost recovery basis. Effective April 1, 2004, KEML was controlled by the Fund and the management and administrative fees are eliminated upon consolidation. The Fund had the following balances receivable from and due to related parties in the normal course of business reflected in other current assets and other current liabilities: 2005 2004 As at December 31: $ $ Due from related parties – 407 Due to related parties – 2,192

The following table summarizes the Fund’s related party transactions through its indirect ownership in the Partnership as reflected in the consolidated financial statements beginning on April 1, 2004:

2005 2004 Year ending December 31 $ $ Operating allocation and NGL revenue – 841 Tariff expense for use of pipeline and NGL purchases – 1,452 Equity earnings from investments – 598 Dividends received from investments – 1,132

The transactions summarized above were made in the normal course of operations and were measured at the exchange value or on a cost recovery basis, which represented the amount of consideration established and agreed to by the related parties. The acquisition of EnerPro added an additional 35.5% interest in Rimbey Pipe Line, which when combined with the 45.3% investment held by the Partnership, represented an indirect controlling interest in Rimbey Pipe Line. Beginning on July 2, 2004, the transactions with Rimbey Pipe Line are eliminated upon consolidation to reflect the Partnership’s indirect controlling interest.

16. Financial instruments Energy price risk management The Partnership enters into contracts to purchase and sell natural gas, natural gas liquids and crude oil. These contracts are exposed to commodity price risk between the time contracted volumes are purchased and sold and currency exchange risk for those sales denominated in U.S. dollars. The Partnership actively manages these risks by using forward currency contracts and swaps, energy related forwards, swaps and options and by balancing physical and financial contracts in terms of volumes, timing of performance and delivery obligations. Management monitors the Partnership’s exposure to the above risks and regularly reviews its financial instrument activities and all outstanding positions.

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16. Financial instruments (continued)

To mitigate the Partnership’s exposure to fluctuations in the price of natural gas, natural gas liquids and electricity, price swap and option agreements are regularly used. These agreements require payments to (or receipts from) counter parties based on the differential between fixed and variable prices for commodities. The Partnership routinely enters into forward currency exchange contracts and swaps to mitigate its exposure to fluctuations in currency exchange rates. These contracts require the exchange of currencies between counter- parties at previously agreed upon exchange rates. The fair values of the derivatives listed below represent an estimate of the amount that the Partnership would receive (pay) if these instruments were closed out at the end of the period.

Carrying Amount Notional Fair Value $ Volume $ 2005 Natural gas liquids: Price swaps –––

Currency: Forward contracts (maturing by January 2006) – US$13,000 (60) 2004 Natural gas liquids: Price swaps (maturing by August 2005) – 63,000 Bbls 256

Currency: Forward contracts (maturing by March 2005) – US$12,050 (28)

Where the financial instrument is not designated as a hedge or does not meet the criteria for hedge accounting, it is recorded on the consolidated statement of financial position at its fair value, either as an asset or a liability. Changes in the fair value of the financial instrument are recognized in earnings in the period in which they occur. The fair value of the financial instruments which do not qualify or have not been designated as hedges are listed below. The carrying amounts are recorded in accounts receivable and accounts payable, respectively.

Carrying Amount Notional Fair Value $ Volume $ 2005 Natural gas liquids: Price swaps (maturing by March 2006) (280) 60,000 Bbls (280) 2004 Natural gas liquids: Price swaps – – –

The estimated fair value of all financial instruments is based on quoted market prices and, if not available, on estimates from third-party brokers or dealers.

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16. Financial instruments (continued)

Credit risk The majority of the Partnership’s accounts receivable are due from entities in the oil and gas industry and are subject to normal industry credit risks. Concentration of credit risk is mitigated by having a broad domestic and international customer base. The Partnership evaluates and monitors the financial strength of its customers in accordance with its credit policy. At December 31, 2005, the accounts receivable from the Partnership’s two largest customers amounted to less than 1% of accounts receivable (2004 – 5%). Revenue from the Partnership’s two largest customers amounted to 12% of operating revenue in 2005 (2004 – 13%). With respect to counterparties for financial instruments used for hedging purposes, the Partnership limits its credit risk through dealing with recognized futures exchanges or investment grade financial institutions and by maintaining credit policies which significantly minimize overall counter party credit risk.

Interest rate risk Management uses fixed and floating rate debt to finance its operations. The floating rate debt exposes the Partnership to changes in interest payments as interest rates fluctuate. At December 31, 2005, fixed rate borrowings comprised 77% (2004 – 96%) of total debt outstanding. The fair value of the Partnership’s senior fixed rate debt at December 31, 2005 was $222,074 (2004 – $222,819). The fair value of the Fund’s unsecured convertible debentures at December 31, 2005 was $55,591 (2004 – $74,108).

Fair value The carrying values of cash and cash equivalents, accounts receivable, other current assets and accounts payable and accrued liabilities approximate their fair values because the instruments are near maturity or have no fixed repayment terms. The fair value of the bank credit facilities approximates fair value due to their floating rates of interest.

Foreign currency rate risk The facilities business, where all sales and virtually all purchases are denominated in Canadian dollars, is not subject to foreign currency rate risk. In the marketing business, approximately US$238,584 of sales were priced in U.S. dollars for the year ended December 31, 2005 (2004 – US$129,871).

17. Commitments and contingencies The Fund, through its operating entities, is involved in various contractual agreements with ConocoPhillips. The agreements range from one to thirteen years and comprise the processing of ConocoPhillips’ natural gas and the purchase of NGL production in the areas specified in the agreements. The purchase prices are based on current period market prices. There are lease commitments relating to railway tank cars, vehicles, computer hardware, office space and natural gas transportation agreements. The estimated annual minimum operating lease rental payments from these commitments are as follows: $ 2006 7,914 2007 7,055 2008 4,633 2009 3,298 2010 1,966 Thereafter 4,547 29,413

There are legal actions for which the ultimate results cannot be ascertained at this time. Management does not expect the outcome of any of these proceedings to have a material effect on the financial position or results of operations.

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18. Supplemental cash flow information 2005 2004 $ $ Interest paid 14,933 13,883 Taxes paid 4,024 1,837

19. Segmented information The Fund, through its consolidation with the Partnership, has three reportable segments: gathering and processing, NGL infrastructure and marketing. Gathering and processing include natural gas gathering and processing. NGL infrastructure includes natural gas liquids processing, transportation, and storage. The marketing business consists of marketing of natural gas liquids, sulphur and crude oil. The accounting policies of the segments are the same as those described in the summary of significant accounting policies.

Gathering and NGL Processing Infrastructure Marketing Corporate Total Year ended December 31 $$$$ $ 2005 Revenue 142,916 57,759 1,013,334 – 1,214,009 Inter-segment revenue (3,642) (22,800) – – (26,442) External revenue 139,274 34,959 1,013,334 – 1,187,567 Operating expenses (67,469) (24,296) (972,704) – (1,064,469) Inter-segment expenses ––26,441–26,441 External operating expenses (67,469) (24,296) (946,263) – (1,038,028) 71,805 10,663 67,071 – 149,539 General and administrative, interest and other – – – (41,430) (41,430) Depreciation and amortization (25,838) (6,990) (2,301) (1,758) (36,887) Accretion expense (1,784) (264) – – (2,048) Impairment expense (1,160) – – – (1,160) Earnings (loss) before tax and non-controlling interest 43,023 3,409 64,770 (43,188) 68,014 Identifiable assets 794,792 222,708 184,878 18,252 1,220,630 Capital expenditures 43,122 8,761 – 987 52,870

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19. Segmented information (continued)

Gathering and NGL Processing Infrastructure Marketing Corporate Total Year ended December 31 $$$$ $ 2004 Revenue1 92,897 33,396 631,696 – 757,989 Inter-segment revenue (2,551) (10,836) – – (13,387) External revenue 90,346 22,560 631,696 – 744,602 Operating expenses (40,210) (16,449) (614,715) – (671,374) Inter-segment expenses – – 13,387 – 13,387 External operating expenses (40,210) (16,449) (601,328) – (657,987) 50,136 6,111 30,368 – 86,615 General and administrative, interest and other – – – (20,176) (20,176) Depreciation and amortization (15,553) (3,720) (1,317) (922) (21,512) Accretion expense (1,014) (222) – – (1,236) Impairment expense (8,981) – – – (8,981) Dilution gain – – – 1,749 1,749 Earnings (loss) before tax and non-controlling interest 24,588 2,169 29,051 (19,349) 36,459 Identifiable assets 768,119 212,612 134,740 31,286 1,146,757 Capital expenditures 21,566 2,107 – 986 24,659

1 Revenue from the NGL Infrastructure segment includes equity earnings from investment in Rimbey Pipe Line of $598 for the year ended December 31, 2004.

Export sales Revenue from sales of NGLs made outside of Canada was $74,689 (2004 – $115,130).

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keyera: fund information

Board of Directors Officers Head Office Investor Relations (1)(3) E. Peter Lougheed Jim V. Bertram Suite 600, 144 – 4th Avenue S.W. John Cobb Counsel, Bennett Jones LLP President and Calgary, Alberta T2P 3N4 Director, Investor Relations Calgary, Alberta Chief Executive Officer Phone: 403-205-8300 Avery Reiter Jim V. Bertram (4) David G. Smith Website: www.keyera.com Investor Relations Advisor President and Executive Vice President, Toll Free: 1-888-699-4853 Chief Executive Officer Chief Financial Officer Stock Exchange Listing Direct: 403-205-7670 Keyera Energy Management Ltd. and Corporate Secretary The Toronto Stock Exchange Email: [email protected] Calgary, Alberta Marzio Isotti Trading Symbols KEY.UN; KEY.DB Robert B. Catell Vice President, Stability Rating Chairman and West Central Region Corporate Trustee Standard & Poor’s SR-3 Chief Executive Officer and Transfer Agent Bradley W. Lock KeySpan Corporation Vice President, Computershare Trust 2005 Trading Summary New York, New York Engineering and Company of Canada Units Outstanding (December 31): (2) Michael B.C. Davies Operational Services Calgary, Alberta 60.1 million Principal, Davies & Co. Ken W. Merritt Banff, Alberta Auditors Total Units Traded: Vice President, 45.8 million Nancy M. Laird (3)(4) Commercial Infrastructure Deloitte & Touche LLP Corporate Director and Marketing Calgary, Alberta Total Value Traded: Calgary, Alberta $794.7 million David A. Sentes Legal Counsel H. Neil Nichols (2)(3) Vice President, Average Daily Management Consultant Comptroller Macleod Dixon LLP Trading Volume: Mississauga, Ontario Calgary, Alberta 182,577 shares K. Jamie Urquhart (3)(4) Trading Prices: William R. Stedman Vice President, Annual Meeting of Unitholders Chairman and Foothills Region High: $23.44 1:00 p.m., Wednesday, May 10, 2006 Chief Executive Officer Low: $13.51 Sun Life Plaza, Plus 15 Level ENTx Capital Corporation Close (December 31): $21.75 Calgary, Alberta 144 – 4th Avenue S.W. Calgary, Alberta Wesley R. Twiss (2) Corporate Director Calgary, Alberta

(1) Chairman (2) Member of the Audit Committee (3) Member of the Compensation and Governance Committee (4) Member of the Health, Safety and Environment Committee

keyera 2005 annual report 68 KeyeraCovers 3/10/06 1:35 PM Page 1 KEYERA FACILITIES INCOME FUND 2005 ANNUAL REPORT 2005 Annual Report

keys to continued

www.keyera.com success keys to continued

success KeyeraCovers 3/5/06 5:32 PM Page 2

2005 Cash Distributions Declared (Cdn. $/unit) Distribution History ($ per unit per quarter) Record Date Payment Date Amount $0.40 January 31, 2005 February 15, 2005 $ 0.103 $0.35

February 28, 2005 March 15, 2005 $ 0.103 $0.30 March 31, 2005 April 15, 2005 $ 0.103 $0.25 April 29, 2005 May 16, 2005 $ 0.103 May 31, 2005 June 15, 2005 $ 0.113 $0.20 June 30, 2005 July 15, 2005 $ 0.113 $0.15

July 29, 2005 August 15, 2005 $ 0.113 $0.10 August 31, 2005 September 15, 2005 $ 0.113 $0.05 September 30, 2005 October 17, 2005 $ 0.113 $0 October 31, 2005 November 15, 2005 $ 0.113 Q2* Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 November 30, 2005 December 15, 2005 $ 0.119 2003 2004 2005 * Q2 2003 one month only December 30, 2005 January 16, 2006 $ 0.119 Total $ 1.328 2005 Unit Price ($ per unit) $24

$22 Glossary $20 acid gas hydrogen sulphide (H2S) or carbon dioxide (CO2) or a combination of H2S and CO2 acid gas injection the injection of acid gas into a suitable $18 underground geological formation bbls and bbls/d barrels and barrels per day $16 butane a natural gas liquid (NGL) with the $14 molecular formula C4H10 CO carbon dioxide 2 $12 condensate a natural gas liquid (NGL) consisting JAN FEBMAR APR MAY JUNJUL AUG SEP OCTNOV DEC Keyera Facilities Income Fund operates one of the largest natural gas midstream businesses in Canada. Its three primarily of pentanes and heavier liquids H S hydrogen sulphide business lines consist of: natural gas gathering and processing; the processing, transportation, and storage of 2 MMcf/d million cubic feet per day natural gas liquids (NGLs) and crude oil; and an NGL and crude oil commercial business. NGL or NGLs natural gas liquids, consisting of any one or a combination of propane, butane and condensate Keyera’s facilities are strategically located in the west central and foothills natural gas production areas of the propane a natural gas liquid (NGL) with the molecular formula C3H8 raw gas natural gas before it has been subjected Western Canadian Sedimentary Basin. Keyera’s NGL and crude oil infrastructure includes pipelines, terminals, to any processing that may be required for it to become suitable for sale and processing and storage facilities in Edmonton and Fort Saskatchewan, Alberta. Keyera also markets NGL mix NGLs that have been separated from the raw gas but have not yet been processed propane, butane and condensate to customers across North America. into propane, butane or condensate sales gas natural gas that has been treated in a natural gas processing facility and is suitable for sale Keyera trades on The Toronto Stock Exchange under the symbols KEY.UN. and KEY.DB. sour gas natural gas containing more than one percent H2S sulphur a yellow mineral extracted from natural gas

sweet gas natural gas that contains no H2S or less than one percent H2S when produced Front Cover: Nordegg Gas Plant Cover photo is dedicated to the memory of Hugh Gold, Nordegg Area Superintendent, who passed away after a short illness in July 2005. Hugh is greatly missed by his friends and coworkers at Keyera.