Keyera Facilities Income Fund - 2007 Year-End Report



    CALGARY, Feb. 26 /CNW/ -

    For the year ended December 31, 2007

    
    2007 YEAR-END HIGHLIGHTS

    -   Keyera delivered outstanding performance in 2007, posting record
        results in all three business segments.

    -   In February 2008, Keyera announced an 8% increase in its monthly cash
        distribution from $0.125 to $0.135 per unit, beginning with the
        February 2008 distribution. This is the sixth increase in five years
        and represents an 8% compound annual growth rate in distributions
        since Keyera's inception in 2003.

    -   Cash flow from operating activities in 2007 was $119.8 million, a new
        record. Distributions to unitholders totaled $90.2 million, or $1.48
        per unit, 3% higher than the $1.43 per unit declared in 2006. Fourth
        quarter distributions were $23.0 million, or 37.5 cents per unit.

    -   Distributable cash flow(1) was $143.5 million in 2007, or $2.35 per
        unit, 42% higher than 2006 and more than double the 2003 IPO level on
        a per-unit basis. Fourth quarter distributable cash flow(1) was
        $41.4 million, or $0.68 per unit. This results in a payout ratio of
        63% and 55% respectively.

    -   Net earnings for 2007 were $14.5 million compared to $68.1 million in
        2006. This difference was primarily due to recording $80.2 million of
        non-cash future income tax expense in the second quarter of 2007, as
        a result of the implementation of the tax on publicly traded Canadian
        income trusts.

    -   All three business segments recorded the highest annual results in
        Keyera's history, despite an uncertain business environment and the
        completion of several significant plant turnarounds during the year.
        Contribution from Gathering and Processing was $87.4 million, up 19%
        from last year. The NGL Infrastructure contribution was
        $46.8 million, 4% higher than in 2006. Contribution from the
        Marketing business was $41.9 million, 70% higher than in the previous
        year.

    -   Scheduled maintenance turnarounds were successfully completed in 2007
        at the Rimbey, Bigoray, Brazeau River and Medicine River gas
        processing plants. Turnarounds scheduled for 2008 and 2009 will be at
        smaller plants and are expected to have only a minimal effect on
        Keyera's cash flow in those years.

    -   Keyera invested over $30 million on growth capital projects in 2007,
        acquiring additional assets and expanding facilities. In 2008,
        assuming timely receipt of regulatory approvals, Keyera anticipates
        investing between $80 and $100 million on growth capital projects.
        They include the ethane extraction project at the Rimbey gas plant,
        as well as the mining of a new storage cavern, connecting a new
        pipeline and expansion of a truck terminal, all at Keyera's Fort
        Saskatchewan facility.

    -   On January 2, 2008, Keyera completed an internal reorganization
        intended to streamline the existing legal structure and simplify
        accounting, legal reporting and income tax compliance.

    (1) See "Non-GAAP Financial Measures" on page 7 and a reconciliation of
        distributable cash flow to cash flow from operating activities on
        page 26.
    

    Message to Unitholders

    In 2007, Keyera met or surpassed all our key financial and operating
targets and achieved record results.
    During the fourth quarter, Keyera continued to build on the strong
performance we delivered during the first three quarters of 2007. Cash flow
from operating activities was $119.8 million, the highest in our history. On
the strength of these excellent results, we declared $90.2 million in
distributions to our unitholders from distributable cash flow of
$143.5 million, leaving $53.3 million to reinvest in our business. Net
earnings for the quarter were $40.0 million, significantly higher than the
$14.9 million in the same period in 2006. Net earnings for 2007 were
$14.5 million, despite recording an $80 million non-cash future income tax
expense during the second quarter.
    In February 2008, we announced an 8% increase in our monthly cash
distribution from $0.125 to $0.135 per unit. Since our inception in 2003, we
have increased distributions 49% through six distribution increases. This
represents an 8% compound annual growth rate in our distributions, an
accomplishment that I am very proud of.
    Our record achievements in 2007 are the result of excellent performance
in each of our operating segments. Contribution from our Gathering and
Processing segment was $87.4 million, 19% higher than 2006, primarily due to
increased throughput at most of Keyera's facilities. Overall throughput at our
plants reached record levels in 2007, led by increases at our Strachan,
Brazeau River, Bigoray and Caribou gas plants. Based on these record
throughput levels, we are exploring the possibility of expanding some of our
facilities, including our sour gas processing capacity in the Pembina region
and our gathering and processing capabilities in the Caribou region of
north-eastern British Columbia.
    Our NGL Infrastructure and Marketing segments also delivered exceptional
results. In our NGL Infrastructure segment, our storage and logistics services
continued to operate efficiently, meeting the service needs of our customers
and providing important support for our Marketing business. Based on this
solid operating record, contribution from the NGL Infrastructure segment
reached $46.8 million in 2007, a 4% increase compared to last year. As well,
each of the business lines within our Marketing segment, including crude oil
and NGLs, produced strong results, allowing this segment to deliver
contribution of $41.9 million, a 70% increase over 2006.
    Keyera's performance in 2007 demonstrates our ability to deliver strong
operational and financial results in challenging times. As the public policy
debates continue to unfold, over issues ranging from the proposed changes to
the Alberta royalty system, to the impact of the legislation passed by the
federal government with respect to the taxation of publicly traded income
funds, to new environmental regulatory initiatives, we are focusing our
efforts on growing our business and adapting our strategies to anticipate and
meet the challenges that lie ahead.
    Against this backdrop of challenge and change, the strength of our
balance sheet and the demonstrated capacity of our core operating businesses
to grow revenue and net income confirm our confidence in Keyera's future.
While Keyera is not immune to the challenges presented by lower gas prices and
public policy initiatives affecting the energy industry, the strategic
location and interconnectedness of our facilities, together with the proven
success of our strategy of sustainable growth, have cushioned the impact of
these events.
    Looking ahead, our plan is to continue to build on our strengths with the
goal of continuing to deliver results for our unitholders. To this end, we
will be maintaining our focus on developing our oil sands strategy and
pursuing other projects that contribute to our long-term business objectives.
At present, we have over $80 million of projects that are either underway or
in the development stages.
    Some of the most exciting initiatives currently underway involve our Fort
Saskatchewan facility. Our facilities in Fort Saskatchewan are an integral
part of our oil sands strategy and our overall goal of building on our
strategic position in this key energy hub. We have signed a long-term lease
that will allow us to connect a fourth pipeline between our Fort Saskatchewan
facility and our Edmonton terminal. This fourth pipeline will improve our
operational flexibility by allowing us to dedicate a pipeline for each of the
four products we move between the two facilities, making it easier to supply
NGLs to our customers, and enhancing the rates at which we can move products
in and out of our storage caverns. In addition, we are nearing completion of
our truck terminal expansion at Fort Saskatchewan, which is designed to
enhance our product loading services and provide us with increased operational
flexibility to load and unload specification products as well as NGL mix.
    One of the largest projects we have underway at our Fort Saskatchewan
facilities is the expansion of our underground storage. At present, we own or
control about a third of all the existing underground storage in Fort
Saskatchewan and are the only provider of condensate storage in the region.
Our plan over the next five to six years is to increase our storage capacity
by 37% to 11.6 million barrels by mining four new storage caverns in order to
meet the anticipated demand for diluent storage as oil sands production
increases. Work on the first of the proposed new caverns is in progress and if
planning and construction go as anticipated, we are optimistic that the first
cavern will be in service in 2009.
    Keyera's financial results in 2007 demonstrate the strength, resilience
and complementary nature of Keyera's business lines. In 2007 we continued to
deliver excellent returns and we enter 2008 with significant momentum. As we
face the challenges that lie ahead, we are committed to continuing to be
actively engaged in the regulatory environments so that we can anticipate,
influence and adapt to the changes and trends on the horizon, and we will work
proactively with our partners, customers and prospective customers to maximize
our business opportunities and deliver results for our unitholders.
    On behalf of Keyera, I thank you for your support and look forward to
continued success.

    Jim V. Bertram
    President and CEO
    Keyera Facilities Income Fund

    Contribution From Operating Segments

    Keyera operates one of the largest natural gas midstream businesses in
Canada with three major operating segments: Gathering and Processing, NGL
Infrastructure and Marketing. The Gathering and Processing segment includes
natural gas gathering systems and processing plants strategically located in
the natural gas production areas on the western side of the Western Canadian
Sedimentary Basin. The NGL Infrastructure segment includes natural gas liquids
(NGLs) and crude oil pipelines, terminals, processing and storage facilities
in Edmonton and Fort Saskatchewan, Alberta, one of North America's major
energy hubs. The Marketing segment includes activities such as the marketing
of propane, butane and condensate to customers in Canada and the United
States, and crude oil midstream activities.
    Keyera's Gathering and Processing and NGL Infrastructure segments provide
a large portion of the total contribution. Keyera benefits from the
geographical diversity of its natural gas processing plants, NGL
infrastructure facilities and associated assets. The revenues generated from
these facilities are fee-for-service based, with minimal direct exposure to
commodity prices. The remainder of Keyera's contribution is derived from its
Marketing segment. Because of Keyera's integrated approach to its business,
its infrastructure provides a significant competitive advantage in NGL
marketing. Keyera also benefits from diversified sources of NGL supply and a
diversified customer base across North America.
    The following table shows the contribution from each of Keyera's
operating segments and includes inter-segment transactions that are eliminated
in the Fund's consolidated financial statements. Because contribution is not a
standard measure under Canadian generally accepted accounting principles
("GAAP"), it may not be comparable to similar measures reported by other
entities. Contribution does not include the elimination of inter-segment
transactions as required by GAAP and refers to operating revenues less
operating expenses. Management believes contribution provides an accurate
portrayal of operating profitability by segment. Keyera's Gathering and
Processing and NGL Infrastructure segments charge Keyera's Marketing segment
for the use of facilities at market rates. Those charges are reflected in
contribution, but are eliminated in GAAP segment measures. The most comparable
GAAP measures are reported in note 17, Segmented Information, which is found
in the financial statements.

    
    -------------------------------------------------------------------------
    Contribution by Operating
    Segment                     Three Months Ended       Twelve months ended
    (Thousands of Canadian          December 31,              December 31,
     dollars)                    2007         2006         2007         2006
    -------------------------------------------------------------------------

    Gathering & Processing(1)
    Revenue before inter-
     segment eliminations(4)   51,942       44,523      191,164      170,184
    Operating expenses before
     inter-segment
     eliminations(4)          (24,082)     (22,312)    (103,792)     (96,558)
    -------------------------------------------------------------------------
    Gathering & Processing
     contribution              27,860       22,211       87,372       73,626
    -------------------------------------------------------------------------

    NGL Infrastructure(1)
    Revenue before inter-
     segment eliminations(4)   19,245       19,742       71,079       69,072
    Operating expenses         (6,483)      (6,099)     (23,697)     (23,956)
    Unrealized (loss)/gain       (154)           -         (556)           -
                             ------------------------------------------------
    Operating expenses
     before inter-segment
     eliminations(4)           (6,637)      (6,099)     (24,253)     (23,956)
    -------------------------------------------------------------------------
    NGL Infrastructure
     contribution              12,608       13,643       46,826       45,116
    -------------------------------------------------------------------------

    Marketing(2)
    Revenue                   375,547      286,765    1,262,548    1,161,636
    Unrealized (loss)/gain     (1,631)        (440)     (12,007)         263
                             ------------------------------------------------
    Revenue before inter-
     segment eliminations(4)  373,916      286,325    1,250,541    1,161,899
    Operating expenses
     before inter-segment
     eliminations(4)         (361,243)    (284,348)  (1,205,653)  (1,134,677)
    General &
     administration              (745)        (631)      (2,964)      (2,524)
    -------------------------------------------------------------------------
    Marketing contribution     11,928        1,346       41,924       24,698
    -------------------------------------------------------------------------
    Total contribution         52,396       37,200      176,122      143,440
    -------------------------------------------------------------------------
    Other expenses(3)         (22,701)     (19,197)     (84,344)     (76,997)
    -------------------------------------------------------------------------
    Earnings before income
     tax and non-
     controlling interest      29,695       18,003       91,778       66,443
    -------------------------------------------------------------------------
    Notes:
    (1) Gathering and Processing and NGL Infrastructure contribution includes
        revenues for processing, transportation and storage services provided
        to Keyera's Marketing business.
    (2) The Marketing contribution is net of expenses for processing,
        transportation and storage services provided by Keyera's facilities
        and general and administrative costs directly attributable to the
        Marketing segment.
    (3) Other expenses include corporate general and administrative,
        interest, depreciation and amortization, accretion and impairment
        expense. Corporate general and administrative costs exclude the
        direct Marketing general and administrative costs.
    (4) Revenue and operating expenses before inter-segment eliminations as
        shown above are both non-GAAP measures and do not consider the
        elimination of inter-segment sales and expenses. Inter-segment
        transactions are eliminated upon consolidation of Keyera's financial
        results to arrive at external revenue and external operating
        expenses, both GAAP measures, as reported in note 17, Segmented
        Information.


    Fourth Quarter Results

    -------------------------------------------------------------------------
                                   (unaudited)
                                Three months ended       Twelve months ended
    Statement of Net Earnings       December 31,              December 31,
    (Thousands of Canadian       2007         2006         2007         2006
     dollars)                       $            $            $            $
    -------------------------------------------------------------------------
    Operating revenues
    Marketing                 373,916      286,325    1,250,541    1,161,899
    Gathering and Processing   50,520       43,621      187,490      166,736
    NGL Infrastructure         11,849       10,855       41,110       39,888
    -------------------------------------------------------------------------
                              436,285      340,801    1,479,141    1,368,523
    Operating expenses
    Marketing                 352,425      274,559    1,172,010    1,102,045
    Gathering and Processing   24,082       22,312      103,792       96,558
    NGL Infrastructure          6,637        6,099       24,253       23,956
    -------------------------------------------------------------------------
                              383,144      302,970    1,300,055    1,222,559
    -------------------------------------------------------------------------
                               53,141       37,831      179,086      145,964
    General and
     administrative             6,613        3,453       21,882       18,892
    Interest expense            5,507        5,153       20,176       18,156
    Depreciation and
     amortization              10,579       10,413       42,040       39,843
    Accretion expense             386          809        2,482        2,257
    Impairment expense            361            -          728          373
    -------------------------------------------------------------------------
                               23,446       19,828       87,308       79,521
    -------------------------------------------------------------------------

    Earnings before income
     tax and non-controlling
     interest                  29,695       18,003       91,778       66,443
    Income tax (recovery)
     expense                  (10,332)       2,840       76,993       (2,660)
    -------------------------------------------------------------------------
    Earnings before
     non-controlling
     interest                  40,027       15,163       14,785       69,103
    Non-controlling interest        -          235          306        1,025
    -------------------------------------------------------------------------
    Net earnings               40,027       14,928       14,479       68,078
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
    Statements of Cash Flows       (unaudited)
    (Thousands of Canadian      Three months ended       Twelve months ended
     dollars)                       December 31,              December 31,
    Net inflow (outflow)         2007         2006         2007         2006
     of cash:                       $            $            $            $
    -------------------------------------------------------------------------
    Operating activities
    Net earnings               40,027       14,928       14,479       68,078
    Items not affecting cash:
      Depreciation and
       amortization            10,578       10,413       42,040       39,843
      Accretion expense           386          809        2,482        2,257
      Impairment expense          361            -          728          373
      Unrealized loss (gain)
       on financial
       instruments              1,784          440       12,563         (263)
      Loss on sale of asset       245            -          245            -
      Future income tax
       (recovery) expense     (11,712)       1,800       72,645       (7,042)
      Non-controlling
       interest                     -          235          306        1,025
    Asset retirement
     obligation
     expenditures                 (57)         (79)        (213)        (160)
    -------------------------------------------------------------------------
                               41,612       28,546      145,275      104,111
    Changes in non-cash
     operating working
     capital                    3,885       13,584      (25,450)       6,545
    -------------------------------------------------------------------------
                               45,497       42,130      119,825      110,656
    -------------------------------------------------------------------------
    Investing activities
    Capital expenditures       (8,963)      (8,138)     (25,313)     (73,868)
    Acquisition of
     non-controlling interest       -            -       (6,716)           -
    Additions to intangibles        -            -            -       (1,115)
    Proceeds on sale of
     assets                       504            -        4,704            -
    Changes in non-cash
     working capital              560        2,649       (1,114)        (651)
    -------------------------------------------------------------------------
                               (7,899)      (5,489)     (28,439)     (75,634)
    -------------------------------------------------------------------------
    Financing activities
    (Repayment) issuance of
     debt under credit
     facilities               (40,000)     (13,399)    (107,984)      41,984
    Issuance of long-term
     debt, net of financing
     costs                     39,582            -      118,895            -
    Issuance of trust units       819          904        3,255        4,252
    Distributions paid to
     unitholders              (22,952)     (21,724)     (89,799)     (86,509)
    Distributions or
     dividends paid to others       -         (240)           -         (479)
    -------------------------------------------------------------------------
                              (22,551)     (34,459)     (75,633)     (40,752)
    -------------------------------------------------------------------------
    Net cash inflow (outflow)  15,047        2,182       15,753       (5,730)
    Cash (bank indebtedness),
     beginning of period          610       (2,278)         (96)       5,634
    Cash (bank indebtedness),
     end of period             15,657          (96)      15,657          (96)
    -------------------------------------------------------------------------
    

    Management's Discussion and Analysis

    The following management's discussion and analysis ("MD&A") was prepared
as of February 26, 2008 and is a review of the results of operations and the
liquidity and capital resources of Keyera Facilities Income Fund (the "Fund")
and its subsidiaries (collectively "Keyera"). It should be read in conjunction
with the accompanying audited consolidated financial statements of the Fund
for the year ended December 31, 2007 and the notes thereto. The financial
statements have been prepared in accordance with Canadian generally accepted
accounting principles and are stated in Canadian dollars. Additional
information related to the Fund, including the Fund's Annual Information Form,
is filed on SEDAR at www.sedar.com.

    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"). Measures such as operating margin (operating revenues
minus operating expenses), distributable cash flow (cash flow from operating
activities adjusted for changes in non-cash working capital, maintenance
capital expenditures and the distributable cash flow attributable to any
non-controlling interest) and EBITDA (earnings before interest, taxes,
depreciation and amortization) are not standard measures under GAAP and
therefore may not be comparable to similar measures reported by other
entities. Management believes that these supplemental measures facilitate the
understanding of the Fund's results of operations, leverage, liquidity and
financial position. Operating margin is used to assess the performance of
specific segments before general and administrative expenses and other
non-operating expenses. Distributable cash flow is used to assess the level of
cash flow generated from ongoing operations and to evaluate the adequacy of
internally generated cash flow to fund distributions. EBITDA is commonly used
by management, investors and creditors in the calculation of ratios for
assessing leverage and financial performance. 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 MD&A and accompanying documents
contain forward-looking statements. These statements relate to future events
or the Fund's future performance. Such statements are predictions only and
actual events or results may differ materially. 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 of Keyera; business strategy and
plans of management; anticipated growth and proposed activities; budgets,
including future capital, operating or other expenditures and projected costs;
estimated utilization rates; objectives of or involving Keyera; impact of
commodity prices; treatment of Keyera under governmental regulatory regimes;
the existence, operation and strategy of the risk management program,
including the approximate and maximum amount of forward sales and hedging to
be employed; and expectations regarding Keyera's ability to raise capital and
to add to its assets through acquisitions or internal growth opportunities.
    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. In some instances, this MD&A
and accompanying documents may also contain forward-looking statements
attributed to third party sources. For example, the discussions with respect
to possible amendments to federal legislation imposing taxes on the
distributions of publicly traded income trusts and partnerships and the
proposed changes in the Alberta royalty system are based solely on news
releases and background information prepared by the federal and Alberta
governments respectively. Management believes that its assumptions and
analysis in this MD&A 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.
    All 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; operational matters,
including potential hazards inherent in our operations; risks arising from
co-ownership of facilities; activities of other facility owners; competitive
action by other companies; activities of producers and other customers and
overall industry activity levels; changes in gas composition; fluctuations in
commodity prices and supply/demand trends; processing and marketing margins;
effects of weather conditions; fluctuations in interest rates and foreign
currency exchange rates; changes in operating and capital costs, including
fluctuations in input costs; actions by governmental authorities; decisions or
approvals of administrative tribunals; changes in environmental and other
regulations; reliance on key personnel; competition for, among other things,
capital, acquisition opportunities and skilled personnel; changes in tax laws
relating to income trusts, including the effects that such changes may have on
Unitholders, and in particular any differential effects relating to
Unitholder's country of residence; and other factors, many of which are beyond
the control of Keyera, some of which are discussed in this MD&A and in
Keyera's Annual Information Form dated February 26, 2008 (the "Annual
Information Form") filed on SEDAR and available on the Keyera website at
www.keyera.com.
    Readers are cautioned that they should not unduly rely on the forward
looking statements in this MD&A and accompanying documents. Further, readers
are cautioned that the forward looking statements in this MD&A speak only as
of the date of this MD&A 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 may be
required by applicable laws.
    All forward looking statements contained in this MD&A and accompanying
documents 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 SEDAR at
www.sedar.com.

    BUSINESS ENVIRONMENT

    Industry activity
    In 2007, producers drilled 18,606 wells in Canada, down from the record
levels of activity experienced over the last several years and 20% lower than
in 2006. Drilling activity was affected by a number of factors, including low
gas prices, high costs and a number of government regulatory and fiscal
changes.
    Despite this slowdown in activity levels, throughput at Keyera facilities
increased by 3% compared to 2006. This increase partially reflects the tie-in
of wells drilled in earlier years, but also reflects a more selective approach
to exploration and development efforts by producers. Customers have indicated
that they are choosing drilling locations that are close to existing
infrastructure, allowing them to connect their production quickly. Often the
gas reserves are rich in NGLs, resulting in higher producer netbacks.
    In the fourth quarter, producers in Canada drilled almost 5,300 wells,
down slightly from the third quarter of 2007, and down just 4% from the same
period last year. On a go forward basis, the Petroleum Services Association of
Canada is forecasting a similar number of wells to be drilled in the first
quarter of 2008 as were drilled over the past two quarters.
    In the foothills front region of Alberta, the number of wells drilled in
the fourth quarter was 16% less than the fourth quarter of 2006. The average
depth of wells drilled in this region in the fourth quarter was 2,144 metres,
11% lower than the same period last year. In the central Alberta region, the
number of wells drilled was 20% lower than the same quarter last year, with
the average depth per well remaining flat at 1,131 metres. British Columbia
also experienced a decline in drilling, with wells drilled falling 5% compared
to the fourth quarter of last year. The average depth per well in this area
increased to over 2,300 metres, a 9% increase in depth compared to the fourth
quarter of 2006.
    Throughput volumes at most Keyera plants increased again in the fourth
quarter, with overall throughputs up 6% compared to the third quarter of 2007
and up 9% from the fourth quarter of 2006. Producer activity around Keyera's
plants, combined with Keyera's growth projects, were responsible for the
increase.
    Indications are that North American natural gas fundamentals may be
strengthening. Recent North American natural gas demand has been strong and
U.S. natural gas storage inventories are at their lowest level for this time
of year since early 2005. The U.S. Energy Information Administration estimates
that, if the U.S. has normal weather for the remainder of the winter, U.S.
inventories will end the winter at normal levels, more than 20% below last
year's end-of-winter levels. Keyera believes that these positive trends
support continued drilling activity in western Canada, particularly on the
western side of the basin where most of its facilities are located.

    New Alberta royalty framework
    On October 25, 2007 the Government of Alberta announced increases in
royalties. The new royalty regime, which is expected to be implemented in
2009, will change the royalty structure for natural gas and conventional oil
by adjusting sliding rate formulas that are price and volume sensitive. These
changes result in higher royalty rates at current prices. In addition, new
price sensitive formulas will be adopted for oil sands development at both the
pre- and post-payout stages.
    Keyera is not a royalty payor, and therefore is not directly affected by
the proposed royalty changes. However, as a service provider to the upstream
industry, Keyera will be affected by producers' responses to the new regime.
Producers are continuing to assess the impact of the new royalty regime on
their operations and future activities. Keyera is working with producers in
the areas around its plants to determine what impact the proposed royalty
changes may have on Keyera. Until we have stronger indications from producers
with respect to their plans, the long term implications of the royalty
announcement for Keyera are difficult to determine. Since many of Keyera's
facilities are located west of the fifth meridian where gas drilling tends to
be deeper, the Government's decision to retain a variation of the Deep Gas
Drilling Program is a positive outcome for Keyera.
    Further information about the new royalty framework is available from the
Government of Alberta website at http://www.gov.ab.ca/ and a copy of the
framework itself can be found at
http://www.energy.gov.ab.ca/Org/Publications/royalty_Oct25.pdf.

    Climate change regulations
    In 2007, the Alberta government amended laws and regulations dealing with
greenhouse gas emissions. The initiative is designed to reduce the emissions
intensity (i.e. the amount of greenhouse gases emitted on a unit of production
basis) of greenhouse gases at applicable facilities.
    Under the new rules, existing large emitters must reduce net emissions
intensity to 88% of the average emissions intensity at a facility between 2003
and 2005. If the actual emissions intensity is above the target, the facility
licensee can generate or purchase "emissions offsets", or purchase fund
credits at a cost of $15/tonne of CO2 equivalent, or purchase emission
"performance credits".
    Keyera operates three facilities which are subject to these requirements:
the Strachan, Rimbey and Brazeau River gas plants. Based on a worst case
scenario, which assumes that Keyera purchases fund credits at $15/tonne and no
offsets or credits are created or purchased at a cost that is less than
$15/tonne, the anticipated cost of these new rules for Keyera is estimated at
$408,000 in 2007. Thereafter, on an annual basis, the cost is expected to be
approximately $1 million per year. Keyera's management anticipates that a
portion of these costs will be recoverable from customers as flow-through
operating costs. Projects implemented since 2002 at Keyera's facilities could
generate emissions offsets or performance credits; however, it is premature to
determine what benefit, if any, could be realized from such actions.
    In January 2008, the Alberta government announced its intention to reduce
projected greenhouse gas emissions in Alberta by 50% by 2050. No details of
this initiative are currently available.
    The federal government released the Regulatory Framework for Air
Emissions (the "Framework") on April 26, 2007 which sets out new GHG and air
pollutant ("AP") emission reduction targets for various industrial sectors,
including the oil and gas industry. The Framework forms the basis for
consultations and the draft GHG and AP regulations are expected to be released
in the spring of 2008. The effect on Keyera can not be determined until the
federal government provides additional information.
    As part of the provincial budget brought down on February 19, 2008, the
B.C. government announced a proposed broad-based carbon tax to be implemented
effective July 1, 2008. According to the budget, the carbon tax initially will
not apply to industrial emissions, including emissions from the oil and gas
industry. The budget does not provide a timeframe for extension of the tax to
industrial emissions. The effect on Keyera can not be determined until the
B.C. government provides additional information.

    Other environmental regulations
    On October 2, 2007, the Government of Alberta announced a new cumulative
effects initiative covering the "industrial heartland" area northeast of
Edmonton. This initiative establishes targets for air, water and land quality
and applies to all large industrial facilities within the area, including
Keyera's Fort Saskatchewan facility. These facilities will be subject to
cumulative airshed targets which are scheduled to come into effect in January
2009. Working groups have been or are being formed to deal with the allocation
of the airshed objectives, water and land management issues, including sulphur
and wetlands management. Based on the information currently available, Keyera
does not anticipate that this initiative will require significant changes to
current operations. However, the effect that this program may have on future
operations or possible expansion is not clear at this time. A more complete
description of the environmental regulations that affect Keyera's businesses
can be found in the Annual Information Form, which is available on Keyera's
website (www.keyera.com) or on SEDAR at www.sedar.com.

    Tax changes
    In October 2006, the Government of Canada announced a new tax on the
distributed income of publicly-traded Canadian income trusts and limited
partnerships (the "Distribution Tax"), and in June of 2007, implementing
legislation was passed. So long as Keyera only experiences "normal growth",
the Fund will not be subject to the Distribution Tax until January 2011. As a
result, beginning in 2011, tax will be payable by Keyera on the portion of its
distributions that is considered ordinary taxable income and, for a Canadian
resident taxpayer, this portion of Keyera's distributions will be treated as
dividend income for tax purposes. There will be no change in the taxation of
Keyera's distributions that are considered to be a return of capital or
dividend income.
    On October 30, 2007, the Federal government announced a proposal to
reduce federal corporate tax rates from 22.12% in 2007 to 15% by 2012. These
lower tax rates would also apply to income trusts. These tax measures became
law on December 14, 2007 reducing the combined federal and provincial tax rate
that will be applicable to the Fund from 31.5% to 29.5% in 2011 and 28% in
2012. This reduction in federal tax rates has been included in the
determination of the future tax provision of the Fund.
    On December 20, 2007, the federal department of finance proposed
amendments to clarify the Distribution Tax legislation. These proposals
included technical amendments to allow a trust or partnership to hold a
diversified portfolio investment through one or more "portfolio investment
entities" without causing the trust or partnership to be subject to the
Distribution Tax. Once the proposed amendments are passed, Keyera may consider
a further re-organization.
    The Distribution Tax will reduce the amount of cash flow available to
Unitholders. Keyera's management and Board of Directors considers this future
reduction in cash flow in their distribution decisions.
    As at January 1, 2008, Keyera estimates that it has approximately
$325 million of unutilized tax pools and deductions, consisting mostly of
class 41 undepreciated capital costs, available for deduction by the Fund's
subsidiaries.

    RESULTS OF OPERATIONS

    Keyera's 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. The services in both these segments are provided 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 activities. A more complete description of Keyera's
businesses by segment can be found in the Annual Information Form, which is
available on Keyera's website (www.keyera.com) or on SEDAR at www.sedar.com.
    Keyera delivered exceptional financial results in 2007, with operating
margin of $179.1 million, $33.1 million higher than in 2006. These record
results were achieved despite a slowdown in the oil and gas industry in
western Canada and the completion of maintenance turnarounds at the Rimbey gas
plant, Keyera's largest facility, as well as at the Brazeau River, Bigoray and
Medicine River gas plants.
    All business segments contributed to these results, with each business
segment achieving record performance. A number of Keyera's gas plants in the
Gathering and Processing segment saw throughputs increase in 2007, resulting
in overall throughput reaching the highest levels in Keyera's history. Storage
revenues in the NGL Infrastructure segment continued to grow and strong market
fundamentals combined with Keyera's access to proprietary rail infrastructure
and logistical expertise enabled the Marketing segment to post record results.
    This strong operating performance in 2007 was partially offset by a
non-cash future income tax expense of $72.6 million. This was primarily
related to the income trust tax legislation enacted in the second quarter of
2007, partially offset by a $11.7 million future income tax recovery in the
fourth quarter resulting from the enactment in December 2007 of lower federal
income tax rates. As a result of the non-cash future income tax expense,
together with slightly higher general and administrative costs, interest
expense and depreciation charges, net earnings and comprehensive income was
$14.5 million in 2007, compared to $68.1 million in 2006.
    Consolidated net earnings for the fourth quarter of 2007 were
$40.0 million, up $25.1 million from the same period in 2006. The strong
operating margin earned from all segments and the $11.7 million non-cash
future income tax recovery, partially offset by higher general and
administrative and interest costs, accounted for the increase. The non-cash
future income tax recovery resulted from the enactment of lower federal income
tax rates in December 2007.

    Gathering and Processing

    Gathering and Processing revenue for 2007 was $187.5 million, an increase
of $20.8 million, or 12%, compared to the previous year. The increase was due
primarily to higher throughput in the Foothills Region, the recovery of a
portion of turnaround costs incurred at the Rimbey, Brazeau River, Bigoray and
Strachan gas plants, the conversion from fixed to flow-through fees at certain
plants and incremental compression fees at the Rimbey gas plant in 2007.
    In the fourth quarter of 2007, Gathering and Processing revenue was
$50.5 million, an increase of $6.9 million, or 16%, compared to the same
period in 2006. The increase was primarily due to higher throughput in the
Foothills Region and the commencement of reprocessing services at the Paddle
River gas plant.
    Gathering and Processing operating expenses for 2007 were $103.8 million,
an increase of $7.2 million, or 7%, compared to 2006. The increase was
primarily due to higher turnaround costs for the turnarounds completed in 2007
at the Rimbey, Bigoray, Brazeau River and Medicine River gas plants, compared
to the turnaround costs incurred in 2006. Another factor in the increase was
higher operating costs at Caribou resulting from higher throughput and
unscheduled maintenance work at the plant.
    In the fourth quarter of 2007, Gathering and Processing operating
expenses were $24.1 million, an increase of $1.8 million compared to the same
period in 2006. The increase was primarily a result of higher operating and
maintenance costs at the Strachan gas plant due to higher volumes and
maintenance work completed in the quarter.
    Average gross processing throughput in 2007 was 843 million cubic feet
per day, a new record and 3% higher than 2006. Fourth quarter throughput of
882 million cubic feet per day was up 9% from the same period in 2006.
    During 2007, Keyera's Gathering and Processing assets were realigned into
new business regions, the Foothills Region and the North Central Region. The
Foothills Region consists of the Strachan, Brazeau River, Nordegg River,
Paddle River, Bigoray, Brazeau North, West Pembina and Tomahawk gas plants and
associated gathering pipelines. The North Central Region consists of the
Rimbey, Gilby, Medicine River, Worsley, Caribou, Chinchaga, North Star and
Greenstreet gas plants and associated gathering pipelines. This realignment is
reflected in the discussion below.

    Gathering and Processing - North Central Region
    The North Central Region posted very strong results in 2007, despite a
slowdown in shallow drilling activity in the region and the completion of a
scheduled turnaround at the Rimbey gas plant, Keyera's largest facility. Gross
throughput of 432 million cubic feet per day in 2007 was 6% lower than last
year, resulting from the loss of processing throughput while the Rimbey
turnaround was underway and lower drilling activity in the Rimbey/Gilby area.
In the fourth quarter of 2007, throughput was 440 million cubic feet per day,
3% lower than the same period last year. The decline was a result of lower
drilling activity in the Rimbey/Gilby area.
    In the Rimbey/Gilby region, the loss of throughput resulting from a
slowdown in drilling was offset by tie-ins of previously drilled wells. Keyera
has been encouraged by current drilling activity in this area and has
identified a number of additional opportunities to offset any further
declines. Rimbey is an attractive processing alternative for producers,
offering higher netbacks resulting from Rimbey's ability to deliver
specification NGL products, as well as other products and services. Volumes
delivered to the NGL offload facility at Rimbey increased in 2007.
    In the Caribou region, activity continued in both new well licenses and
land sales throughout the year. Keyera extended the Caribou North Gas
Gathering System in early 2007 across the Trutch Creek at the north end of the
pipeline, to connect production from new gas drilling in that area. At mid
year, Keyera acquired about 18 kilometres of existing gathering pipeline and
an abandoned plant site north of the existing pipeline system and, at year
end, announced a further 24-kilometre extension of the Caribou North Gas
Gathering pipeline. Throughput is now averaging 50 million cubic feet per day
at Caribou, about 75% of capacity, and detailed engineering is underway for a
possible expansion of the facility.
    In July 2007, Keyera announced a project at the Rimbey gas plant to
extract ethane from the raw gas at the plant. The proposed project, estimated
to cost $26 million, involves modifying the existing NGL extraction process
and installing new compression equipment at the plant and constructing a
32-kilometre ethane delivery pipeline. The project is awaiting regulatory
approval from the Energy Resources Conservation Board. If approved Keyera will
be able to extract up to 5,000 barrels per day of saleable ethane from field
gas processed at the Rimbey plant. A significant portion of the ethane to be
extracted is currently used as fuel gas within the plant and will therefore be
incremental to the current supply of ethane in Alberta.
    In January 2008, the North Star gas plant, a non-core asset, was sold.

    Gathering and Processing - Foothills Region
    The Foothills Region delivered record results in 2007, as continued
strong drilling activity in the region resulted in increasing throughput
during the year. Gross throughput of 411 million cubic feet per day in 2007
was 51 million cubic feet per day, or 14%, higher than in 2006. In addition,
Foothills revenues benefited from higher fees due to the higher concentrations
of NGLs and hydrogen sulphide in the gas streams. In the fourth quarter of
2007, throughput was 442 million cubic feet per day, 25% higher than the same
period in 2006. This increase was due to significant producer activity around
Foothills Region plants.
    In the Pembina area, sour gas development targeting the Nisku zones
continued in the fourth quarter, including the licensing of several new wells.
Utilization at Keyera's three sour gas processing plants in the area, Bigoray,
West Pembina and Brazeau River, continued to increase throughout the year. To
address the resulting sour gas capacity constraints, Keyera completed
modifications to its pipeline systems in the fourth quarter to increase
processing flexibility by diverting sour gas to other plants in the area.
    A pressure survey of the acid gas disposal well at the Brazeau River gas
plant was completed while the plant was offline for its scheduled maintenance
turnaround. The survey indicated that the acid gas reservoir was filling more
rapidly than anticipated. In the fourth quarter, Keyera acquired a depleted
reservoir as well as another acid gas injection well. Construction of the
necessary pipeline connections began early in the new year and the well became
operational in February 2008. Until the new well was operational, some volumes
were redirected to other Keyera facilities for processing and, for a brief
period, sour gas processing was curtailed at the Brazeau River gas plant.
    At the Bigoray gas plant, piping and equipment modifications were
completed earlier in 2007 to provide for the future expansion of sour gas
processing at the plant. In addition, a new distributed control system was
installed at the plant to provide improved operating reliability and
flexibility. Throughput increased substantially during the year and Keyera is
currently working on plans to debottleneck gathering and inlet compression
facilities to accommodate the increasing production volumes.
    Lands to the west of Keyera's Strachan, Nordegg River and Brazeau River
gas plants saw considerable activity throughout the year as producers pursued
sweet, liquids-rich plays. These areas are close to Keyera gathering pipelines
and processing infrastructure, enabling quick tie-ins and production. In
addition, the liquids-rich gas provides the producer with a higher netback
than dry sweet gas, making these play types attractive to producers.
    New production was connected to the Strachan North pipeline for delivery
to the Strachan gas plant in the fourth quarter. A producer-owned field
compressor was installed during the fourth quarter, resulting in increased
throughput at Strachan. Southwest of the Brazeau River gas plant, Keyera is
partnering with a producer to build a new gathering pipeline to deliver new
gas production to the plant. The pipeline is expected to be operational late
in the first quarter.
    In the fourth quarter, Keyera entered into an arrangement to use its NGL
extraction facilities to extract NGLs from new gas volumes delivered to the
Paddle River gas plant.

    NGL Infrastructure

    NGL Infrastructure revenue for 2007 was $41.1 million, an increase of
$1.2 million, or 3%, compared to the previous year. The increase was primarily
due to higher storage revenues at Keyera's Fort Saskatchewan facility. The
effect of higher storage revenues was partly offset by a fee adjustment and
reduced volumes from the Rimbey Pipeline system in the third quarter of 2007.
    NGL Infrastructure operating expenses for 2007 were $24.3 million, an
increase of $0.3 million compared to 2006. This increase was largely due to
higher supplies and maintenance costs partly offset by lower costs for
electricity and natural gas.
    In the fourth quarter of 2007, NGL Infrastructure revenues were
$1.0 million higher than the same period in 2006, largely due to higher
storage revenues at the Fort Saskatchewan facility. Operating expenses were
$0.5 million higher than the fourth quarter of 2006, due primarily to the
purchase of an additional charcoal bed filter.
    NGL Infrastructure facilities overall operated at typical levels for the
fourth quarter. Higher product demand, particularly for propane, and the
receipt of imported condensate resulted in higher rail loading activity in the
fourth quarter. Storage revenues remained strong in the fourth quarter, driven
by normal winter season inventory requirements and diluent demand for oil
sands production. Fractionation throughput was lower than usual in the third
quarter of 2007 due to short-term market conditions, but returned to typical
levels in the fourth quarter.
    Keyera continues to focus on strengthening its competitive position in
the Edmonton/Fort Saskatchewan area. As part of that strategy, Keyera is
pursuing a number of initiatives.
    Work is underway to expand the storage capacity at Keyera's Fort
Saskatchewan facility to meet the expected need for diluent storage to support
oil sands development over the next decade. The project, which is expected to
take five to six years to complete, will expand the current storage capacity
by three million barrels, or 37%, to about 11.6 million barrels and is
expected to cost $70 to $80 million. Engineering work on the first cavern is
being finalized, equipment is being ordered and site construction work was
completed early in the first quarter of 2008. The cost of the first cavern is
expected to be $18 million, with a large portion of the cost being spent in
2008. Assuming construction proceeds as planned, the first cavern is expected
to be put into service late in 2009.
    The expansion of the truck terminal at the Fort Saskatchewan facility is
largely complete, commissioning will begin shortly and the facility is
expected to be operational in March. The project will increase Keyera's
operational flexibility and provide enhanced product loading services for
customers serving the domestic NGL market.
    The fourth pipeline between the Fort Saskatchewan facility and the
Edmonton terminal is also proceeding and is expected to be onstream by
mid-year assuming timely receipt of land owner approval. Engineering work on
this project has identified additional operational efficiencies which have
provided a capacity boost, eliminating the need for a booster station on the
pipeline and reducing the net capital cost of the project. When operational,
the new pipeline will provide significantly more operational flexibility,
allowing Keyera to deliver condensate and butane at increased rates into and
out of the Edmonton terminal, Fort Saskatchewan storage and other pipelines
and terminals in the area. This pipeline is also expected to support the new
storage caverns and will add value to Keyera's storage services by increasing
the flexibility for customers.
    Looking to the future, Keyera is working towards connecting the Fort
Saskatchewan and Edmonton facilities to more pipelines and new facilities in
the area. In the first quarter of 2008, Keyera reached an agreement with a
major pipeline operator to connect Keyera's facilities into another major
crude oil, condensate and NGL pipeline delivering product into the
Edmonton/Fort Saskatchewan hub.

    Marketing

    Generally, market fundamentals for propane, butane and condensate were
positive throughout the year as supply and demand remained largely in balance
and rising crude oil prices positively affected product prices. Keyera
exploited these strong fundamentals throughout the year and utilized its
proprietary rail and storage infrastructure to enhance unit margins.
    Marketing revenue for 2007 was $1,250.5 million, an increase of
$88.6 million compared to the previous year. The increase was due primarily to
higher sales prices and growth in the crude oil midstream business, partially
offset by the cost of the financial contracts that Keyera uses in its risk
management program. Keyera's risk management program employs a multi-faceted
approach to managing its supply and sales portfolio, including: monitoring its
inventory position and its purchase and sale commitments; actively
participating in various hub markets; using financial contracts, such as
energy-related forward sales, price swaps, physical exchanges and options; and
offsetting some of its physical and financial contracts in terms of volumes,
timing of performance and delivery obligations. (See "Liquidity and Capital
Resources - Marketing Risk Management"). Due to rising prices for crude oil
and liquid hydrocarbons in 2007, the forward financial sales contracts used to
hedge the commodity price risk arising from holding physical inventory reduced
marketing revenues by $20.0 million, while in 2006 the program added
$7.0 million in revenues due to declining commodity prices.
    The table below outlines the composition of the revenues generated from
Keyera's Marketing business and the changes in the fair value of the
derivative financial contracts.

    
                                                               Twelve months
                                                                       ended
    Composition of Marketing Revenue                             December 31,
    (Thousands of Canadian dollars)                                     2007
    -------------------------------------------------------------------------
    Physical sales                                                 1,270,511
    Financial instruments - realized                                 (10,059)
    Financial instruments - unrealized                                (9,911)
    -------------------------------------------------------------------------
    Marketing revenue                                              1,250,541
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Changes in Fair Value of Energy Derivative Contracts
    (Thousands of Canadian dollars)
    -------------------------------------------------------------------------
    Fair value at December 31, 2006                                      211
    Change in the fair value of contracts                              9,848
    Fair value of new contracts entered into in 2007                  (9,911)
    Realized losses                                                  (10,059)
    -------------------------------------------------------------------------
    Fair value at December 31, 2007(1)                                (9,911)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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, 2007.
    

    NGL sales volumes for 2007 averaged 50,800 barrels per day compared to
52,200 barrels per day in 2006. The reduction was a result of lower propane
volumes in 2007, partially offset by growth in butane and condensate volumes.
In the fourth quarter of 2007, NGL sales volumes averaged 53,800 barrels per
day compared to 55,400 barrels per day in the fourth quarter of 2006.
    Marketing operating expenses for 2007 were $1,172.0 million, an increase
of $70.0 million compared to the previous year. The increase was due primarily
to higher supply costs compared to 2006.
    NGL product inventories of $76.6 million at December 31, 2007 were
$22.7 million higher than the previous year due to higher volumes and
significantly higher prices at year-end. Inventory has been valued at the
lower of cost or net realizable value at December 31, 2007.
    Propane demand in 2007 followed normal seasonal trends. In the first
quarter, cold weather bolstered demand and Keyera used its rail car fleet and
NGL infrastructure to facilitate the movement of product to niche markets
where demand and prices were high. The second and third quarters experienced
lower demand, typical of the summer season. The fourth quarter saw a seasonal
increase in demand early in the quarter and prices remained high due to the
strong correlation with the price of crude oil. Keyera used the propane
terminal in Superior, Montana, which was acquired in June of 2007, as well as
its other three propane terminals in the US, to deliver propane into regional
markets via rail car for loading onto customers' trucks for further delivery
to end use customers.
    Butane demand remained strong throughout most of 2007, which enabled
Keyera to earn steady margins from quarter to quarter. Much of Keyera's supply
was committed to term sales contracts, providing a steady market for product
and secure margins.
    In general, condensate demand was strong throughout most of 2007, as oil
sands producers continued to purchase condensate for use as diluent to enable
heavier crude oil to flow in pipelines. Keyera imported condensate into
Alberta from lower priced regions in North America throughout the year, using
its storage facilities at Fort Saskatchewan to exploit periods of short-term
price volatility. In addition, Keyera used its newly constructed condensate
truck loading rack at the Rimbey gas plant to deliver product into local
markets. The utilization of its asset infrastructure was a key factor in
allowing Keyera to deliver strong condensate margins throughout the year.
    Keyera's crude oil midstream business continued to develop in 2007.
Market fundamentals were strong throughout the year, enabling the business to
contribute increased operating margins compared to 2006.
    In the fourth quarter of 2007, marketing revenues of $373.9 and operating
expenses of $352.4 million generated $21.5 million of operating margin, up
$9.7 million from the same period in 2006. This increase was related to
several factors. Product prices were stronger in 2007 compared to 2006 when,
in the fourth quarter of the year, warm weather in the eastern U.S.
contributed to lower propane demand and butane and condensate markets remained
soft. In the fourth quarter of 2007, prices for all products were influenced
by high crude oil prices. Propane demand was typically strong for the winter
season, butane term sales provided steady margins and condensate was in high
demand for use as diluent. All of these factors contributed to sound unit
margins. Adjustments relating to the routine voidance of a butane cavern in
the fourth quarter of 2007 reduced margins by $0.8 million.
    At December 31, 2007, the unrealized loss on financial contracts
recognized in the fourth quarter was $1.7 million ($12.0 million recognized
for the full year), primarily due to the change in the value of crude oil
price swap contracts and fixed price contracts. At December 31, 2007, the fair
market value of these contracts represented a liability of $12.4 million and
an asset of $2.5 million, which represents an estimate of the amount that
Keyera would pay or receive if these instruments had been closed out at the
end of the period. The estimated fair value of all derivatives held for
trading is based on quoted market prices and, if not available, on estimates
from third party brokers or dealers.
    Of the $12.0 million unrealized loss in 2007, the portion relating to
changes in crude oil financial contracts amounted to approximately
$9.9 million. These contracts are used to protect inventory from fluctuations
in the prices of NGL products. To the extent these contracts are effective
(i.e., the change in the market price of crude oil is correlated to the change
in the prices of the underlying physical NGL products), gains and losses on
these financial contracts will be offset by gains and losses in the proceeds
that will be realized upon the sale of the products.
    The remainder of the 2007 unrealized loss relates primarily to the
$2.3 million unrealized loss recognized in the first quarter of 2007 as a
result of the adoption of new accounting standards for fixed price physical
contracts. As the fixed price contracts were priced higher than market, the
new accounting standards required an asset of $2.3 million to be recorded with
a corresponding decrease in opening deficit. As these contracts matured and
the actual proceeds on the fixed price sales were recorded in revenue, the
previously recorded asset of $2.3 million was reduced to nil with a
corresponding charge (unrealized loss) to earnings in the first quarter of
2007.
    The adoption of the new accounting standards is expected to continue to
result in volatility in operating margins due to unrealized gains and losses
associated with financial instruments.

    Non-operating Expenses and Other Earnings

    General and administrative expenses for 2007 were $21.9 million, up
$3.0 million from the previous year. Long-term incentive plan costs were
$3.2 million higher than in 2006, reflecting an increase in unit price and the
effect of a distribution increase implemented in May 2007. Excluding the
effect of the long-term incentive plan, general and administrative expenses
were in line with those incurred in 2006.
    Interest expense, net of interest revenue, was $20.2 million for 2007,
$2.0 million greater than in 2006. The increase was due to higher borrowings
used to fund capital projects undertaken in 2006 and 2007.
    Depreciation and amortization expense was $42.0 million for 2007,
$2.2 million greater than the previous year. The increase was due to growth in
the asset base resulting from the completion of several major construction
projects during the past two years.
    An impairment expense of $0.7 million was recorded in 2007 to adjust the
carrying value of the North Star gas plant, a small non-core facility that was
sold in early 2008.
    Income tax expense for 2007 was $77.0 million, $79.7 million higher than
the previous year due to an increase in future income tax expense. Future
income tax expense for 2007 was $72.6 million compared with a future income
tax recovery of $7.0 million in the prior year. This increase was primarily
due to recording $80.2 million of future income tax expense in the second
quarter of 2007 resulting from the new tax imposed on publicly traded income
trusts and limited partnerships in Canada. The future tax expense is an
estimate of the tax that will ultimately be payable by the Fund due to
differences between the accounting and tax basis of assets and liabilities of
the operating partnership. As a result of the new tax legislation,
distributions will no longer be deductible by the Fund beginning in 2011. The
effect of recording the new tax on income trusts was partially offset by lower
future federal income tax rates that were enacted in 2007.
    Current income tax expense for 2007 was $4.3 million, virtually unchanged
from 2006. The impact of lower earnings posted by the Rimbey Pipeline business
in the third quarter of 2007 was offset by higher earnings posted by Keyera
Energy Facilities Ltd. throughout 2007.

    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, 2007, operating revenues and accounts receivable for the
Gathering and Processing and NGL Infrastructure segments contained an estimate
of $21.8 million primarily for December 2007 operations.

    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 historical
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, 2007, operating expenses and accounts payable contained
an estimate of $8.5 million primarily for December 2007 operations.

    Estimation of Gathering and Processing and NGL Infrastructure
    equalization adjustments:
    Much of the revenue from the Gathering and Processing and NGL
Infrastructure assets includes a recovery of operating costs. 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 throughput completed after the
end of the 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 are 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 $6.6 million at December 31, 2007. Operating expenses and
accounts payable contained an estimate of $6.9 million.

    Estimation of Marketing revenues:
    The majority of the Marketing sales revenues is recorded based upon
actual volumes and prices; however, in many cases actual product lifting
volumes have not yet been confirmed and 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, 2007, the Marketing sales and accounts receivable
contained an estimate for December 2007 revenues of $75.7 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 historical 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 $101.3 million at December 31, 2007.

    Estimation of Asset Retirement Obligation:
    Keyera will be responsible for compliance with all applicable laws and
regulations regarding the decommissioning, abandonment and reclamation of its
facilities at the end of their economic lives. The determination of the
estimate of these obligations is based upon settlement between 2018 and 2038.
Keyera utilizes a documented process, overseen by the Health, Safety and
Environment Committee, to estimate future liability and the anticipated cost
of the decommissioning, abandonment and reclamation of its facilities.
    Keyera has estimated that, at December 31, 2007, the total undiscounted
amount required to settle the asset retirement obligations is $183.0 million,
compared to $183.2 million at December 31, 2006. The discounted net present
value of this obligation at December 31, 2007 is $37.8 million, compared to
$34.5 million at December 31, 2006. The increase in the discounted amount is
primarily due to accretion.
    It is not possible to predict these costs with certainty since they will
be a function of regulatory requirements at the time of decommissioning,
abandonment and reclamation and the actual costs may exceed the current
estimates which are the basis of the asset retirement obligation shown in
Keyera's financial statements.
    Additional information related to decommissioning, abandonment and
reclamation costs is provided in Keyera's 2008 Annual Information Form, which
is available on SEDAR.

    LIQUIDITY AND CAPITAL RE

SOURCES Cash flow from operating activities Cash flow from operating activities during the fourth quarter of 2007 was $45.5 million, of which $3.9 million was generated from a decrease in non-cash working capital. Before changes in non-cash working capital, cash flow from operating activities was $41.6 million. From this cash flow, Keyera paid $23.0 million of distributions to its unitholders and required $8.4 million for capital expenditures, leaving $10.2 million of cash. Keyera also received $39.6 million of net proceeds from the issuance of long-term debt, $0.8 million from the issuance of trust units under the distribution reinvestment plan ("DRIP"), $3.9 million from the change in non-cash working capital and $0.5 million of proceeds from the disposition of equipment. From this cash, Keyera repaid $40.0 million of short-term borrowings, leaving a net cash inflow of $15.0 million for the quarter. For the full year, cash flow from operating activities was $119.8 million, after the use of $25.5 million to fund an increase in non-cash working capital primarily due to higher product inventories. Cash flow from operating activities before changes in non-cash working capital was $145.3 million. From this cash flow Keyera paid $89.8 million of distributions to its unitholders and required $33.1 million for capital expenditures and acquisitions, leaving $22.4 million of cash. Keyera also received $4.7 million from dispositions and $3.3 million from the issuance of trust units under the DRIP, bringing cash available to $30.4 million. Along with this cash, net proceeds of $118.9 million from the issuance of long-term debt were used to fund the repayment of $108.0 million of short-term borrowings and finance the $25.5 million change in non-cash working capital, leaving a $15.8 million net cash inflow for the year. Cash and working capital were $75.7 million at December 31, 2007 compared to a deficit of $41.1 million at December 31, 2006. The deficit at December 31, 2006 resulted from the use of short-term debt to finance growth capital expenditures and was eliminated in 2007 when Keyera received $118.9 million of net proceeds from the issuance of long-term debt and used much of these proceeds to repay short-term debt. Keyera has no direct exposure to asset backed commercial paper. Surplus cash is held in interest bearing deposit accounts or invested in term deposits, guaranteed investment certificates, or Bankers' Acceptances issued by Canadian chartered banks. Capital expenditures Twelve months ended Capital Additions and Acquisitions December 31, (in millions of Canadian dollars) 2007 2006 ------------------------------------------------------------------------- Growth capital expenditures 23.9 70.9 Maintenance capital expenditures 1.4 3.0 ------------------------------------------------------------------------- Total capital expenditures 25.3 73.9 Acquisitions of non-controlling interest 6.7 - ------------------------------------------------------------------------- Total capital additions and acquisitions 32.0 73.9 ------------------------------------------------------------------------- ------------------------------------------------------------------------- In the fourth quarter of 2007, additions to property, plant and equipment including acquisitions amounted to $9.0 million, most of which was growth capital. Keyera incurred maintenance and repair expenses of $3.2 million that were included in operating costs during the fourth quarter of 2007. The growth capital expenditures included $2.0 million for the acquisition of an acid gas disposal well for the Brazeau River plant, $1.6 million for the expansion of the truck terminal at Fort Saskatchewan, $1.2 million for the acquisition of pipe and design work for the Caribou North Trutch Pipeline project, $0.7 million for work done on the construction of a fourth pipeline between our Fort Saskatchewan facility and Edmonton terminal, and $0.4 million related to the construction of new camp facilities at the Caribou plant and various other small projects. Total capital additions and acquisitions amounted to $32.0 million in 2007, consisting of $1.4 million of maintenance capital, $23.9 million of growth capital and $6.7 million of acquisitions. In addition to maintenance capital expenditures, Keyera incurred maintenance and repair expenses of $28.0 million that were included in operating costs. In 2007, Keyera invested in the following significant growth projects: - $6.7 million related to the acquisition of additional ownership interests in Rimbey Pipeline Limited Partnership, bringing Keyera's ownership to 100% - $4.4 million for new gathering pipelines in the Foothills Region - $4.2 million at the Bigoray, Brazeau River and Nordegg River gas plants to upgrade systems and equipment and expand acid gas disposal capacity - $2.6 million for upgrades and expansion of equipment at the Rimbey gas plant - $2.2 million for the expansion of the truck terminal at Fort Saskatchewan - $2.1 million for the acquisition of a site in northeast B.C. close to the Caribou North gathering system to enable future expansion - $1.9 million related to modifications at the Rimbey gas plant to enable the tie-in of equipment required for the ethane extraction project In 2008, Keyera anticipates investing between $80 million and $100 million on growth capital projects, but the actual level of growth capital investment is dependent upon a number of factors including available opportunities, timing of regulatory approvals and agreements with customers. The 2008 spending includes commitments and carry over from the unfinished 2007 capital program. Sufficient capacity is available in the current credit facilities to fund the 2008 expenditures. 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 $84 million. In addition to the working capital required for inventory, Keyera typically utilizes approximately $25 to $45 million to finance the other components of working capital. Risks 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 most fee structures, which provide a mechanism for the recovery of operating costs. The most significant exposure faced by the Gathering and Processing and NGL Infrastructure businesses over the long term is related to declines in throughput volumes. Without reserve additions, third party production will decline over time as reserves are depleted. 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 Western Canada Sedimentary Basin and have high barriers to entry for new competitors. Keyera's cash flows may also be adversely affected by the occurrence of common hazards and environmental risks related to the natural gas gathering, 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. 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. In addition, 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. The most significant exposure faced by the Marketing business is fluctuation in the prices of the commodities that Keyera buys and sells. (See "Marketing Risk Management" in this MD&A.) For a further discussion of the risks identified in this MD&A, other risks and trends that could affect the performance of the Fund and the steps that Keyera takes to mitigate these risks, readers are referred to the descriptions in this MD&A and Keyera's Annual Information Form available on SEDAR. Keyera's future debt levels are primarily dependent on operating cash flows, working capital requirements and capital investment programs. Management expects the Fund's 2008 capital expenditures and distributions to be funded by cash flow from operations and borrowing on available debt facilities. Debt covenants Keyera has established credit facilities consisting of a $150 million committed unsecured revolving term facility that matures on April 21, 2010 and $30 million of unsecured revolving demand facilities. These 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. As of December 31, 2007 there were no drawings under these Credit Facilities. The bank credit facilities contain a covenant that the Fund and its subsidiaries will not distribute in any twelve month period more than 105% of the distributable cash flow attributable to that twelve month period. For the year ended December 31, 2007, Keyera distributed 66% of its distributable cash flow, using the definitions in the bank credit facilities. Those facilities are also subject to two major financial covenants: "Debt to EBITDA" and "Debt to Capitalization". The calculation for each ratio is based on specific definitions, is not in accordance with GAAP and cannot be readily replicated by referring to the Fund's financial statements. The definitions in the credit agreements provide for the deduction of net working capital items in the calculation of debt. The following are the ratios as calculated in accordance with the covenants as at December 31, 2007: ------------------------------------------------------------------------- Covenant Position as at December 31, 2007 ------------------------------------------------------------------------- Debt to EBITDA not to exceed 3.5 1.59 ------------------------------------------------------------------------- Debt to Capitalization not to exceed 0.55 0.26 ------------------------------------------------------------------------- Keyera has $335 million of long-term senior unsecured notes as follows: $20 million bearing interest at 5.42% and maturing in August 2008; $90 million bearing interest at 5.23% and maturing in October 2009; $52.5 million bearing interest at 5.79% and maturing in August 2010; $52.5 million bearing interest at 6.155% and maturing in August 2013; $60 million bearing interest at 5.89% and maturing in December 2017; and $60 million bearing interest at 6.14% and maturing in December 2022. These notes are subject to three major financial covenants: "Consolidated Debt to Consolidated EBITDA", "Consolidated EBITDA to Consolidated Interest Charges" and "Priority Debt to Consolidated Total Assets". The calculations for each of these ratios are based on specified definitions. The following are the ratios calculated in accordance with the covenants as at December 31, 2007 for the notes maturing in 2008, 2009, 2010 and 2013: ------------------------------------------------------------------------- Covenant Position as at December 31, 2007 ------------------------------------------------------------------------- Debt to EBITDA not to exceed 3.5 2.14 ------------------------------------------------------------------------- EBITDA to Interest Charges not less than 3.0 10.90 ------------------------------------------------------------------------- Priority Debt to Total Assets not to exceed 15% 0% ------------------------------------------------------------------------- The following are the ratios calculated in accordance with the covenants as at December 31, 2007 for the notes maturing in 2017 and 2022: ------------------------------------------------------------------------- Covenant Position as at December 31, 2007 ------------------------------------------------------------------------- Debt to EBITDA not to exceed 5.0 1.42 ------------------------------------------------------------------------- EBITDA to Interest Charges not less than 2.0 8.35 ------------------------------------------------------------------------- Priority Debt to Total Assets not to exceed 15% 0% ------------------------------------------------------------------------- Failure to adhere to the covenants described above may impair Keyera's ability to pay distributions. Management expects that upon maturity of the credit facilities, adequate replacement facilities will be established. Regulatory risk Keyera is subject to a range of laws and regulations imposed by various levels of government and regulatory bodies in the jurisdictions in which it operates. In 2007, regulatory changes in the areas of taxation and the environment have had the most direct impact on Keyera. (See "Business Environment"). While these laws and regulations affect all dimensions of Keyera's activities, Keyera does not believe that they affect its operations in a manner materially different from other comparable businesses operating in the same jurisdictions. A more complete discussion of regulatory risks can be found in the Annual Information Form available on SEDAR. Credit risk Credit risk is the risk of loss resulting from non-performance of contractual payment obligations by a customer or counterparty. The majority of Keyera'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 Keyera's overall credit risk; however, there can be no assurance that these processes will protect against all losses from non-performance. At December 31, 2007, the accounts receivable from Keyera's two largest customers accounted for less than 1% of accounts receivable (2006 - less than 1%). With respect to counterparties for financial instruments used for economic hedging purposes, Keyera limits its credit risk by dealing with recognized futures exchanges or investment grade financial institutions and by maintaining credit policies that significantly reduce overall counterparty credit risk. Marketing risk management Keyera enters into contracts to purchase and sell natural gas, NGLs and crude oil. Most of these contracts are priced at floating market prices. These activities expose Keyera to market risks resulting from movements in commodity prices between the time volumes are purchased and the time they are sold and from fluctuations in the margins between purchase prices and sales prices. The prices of the products that are marketed by Keyera are subject to fluctuations as a result of such factors as seasonal demand changes, changes in crude oil and natural gas markets and other factors. In many circumstances, particularly in NGL marketing, purchase and sale contracts are not perfectly matched as they are entered into at different times, locations and values. Further, Keyera normally has a long position in most of the NGL products that it markets and may store NGLs in order to meet seasonal demand and take advantage of seasonal pricing differentials, thereby resulting in inventory risk. Because crude oil margins are earned by capturing spreads between different qualities of crude oil, Keyera's crude oil midstream business is subject to variability in price differentials between crude oil streams. In both Keyera's NGL and crude oil marketing businesses, margins can vary significantly from period to period and volatility in the markets for these products may cause distortions in financial results from period to period that are not replicable. To some extent, Keyera reduces elements of risk exposure through the integration of its Marketing business with its Facilities businesses. In spite of this integration, Keyera remains exposed to market and commodity price risk. Keyera manages this commodity risk in a number of ways, including the use of financial contracts and by offsetting some physical and financial contracts in terms of volumes, timing of performance and delivery obligations. For example, in the context of NGL marketing, because NGL product prices are related to the price of crude oil, crude oil financial contracts are one of the more common hedging strategies that Keyera uses. This strategy is subject to basis risk between the prices of crude oil and the NGL products and therefore cannot be expected to fully offset future propane, butane and condensate price movements. Further, there is no guarantee that hedging and other efforts to manage the marketing and inventory risks will generate profits or mitigate all the market and inventory risks associated with these activities. To the extent that Keyera engages in these kinds of hedging activities, it is also subject to credit risks associated with counterparties with whom it contracts. Foreign currency rate risk The Gathering and Processing and NGL Infrastructure segments generated 56% of 2007 operating margin and are not subject to foreign currency rate risk. All sales and virtually all purchases are denominated in Canadian dollars. In the Marketing business, approximately US$240.1 million of sales were priced in U.S. dollars in 2007. Commitments Keyera has assumed various contractual obligations in the normal course of its operations. At December 31, 2007, the obligations that represent known future cash payments that are required under existing contractual arrangements are as follows: Payments Due by Period ------------------------------------------------------------------------- After Contractual Total 2008 2009 2010 2011 2012 2012 obligations $ $ $ $ $ $ $ ------------------------------------------------------------------------- Long-term debt(1) 335,000 20,000 90,000 52,500 - - 172,500 Operating leases(2) 33,845 8,749 7,926 6,359 4,964 3,915 1,932 Purchase obligations(3) - - - - - - - ------------------------------------------------------------------------- Total contractual obligations 368,845 28,749 97,926 58,859 4,964 3,915 174,432 (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, terminal lease space and natural gas transportation. (3) Keyera is involved in various contractual agreements with ConocoPhillips and other producers to purchase NGLs. These agreements range from one to eleven 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 market prices. The future volumes and prices for these contracts cannot be reasonably determined. Unitholder Distributions Comparison of distributions paid to cash flow from operating activities and net earnings The following table presents a comparison of distributions paid to net earnings and cash flow from operating activities: Three months ended (Thousands of Canadian Dec. 31, Twelve months ended Dec. 31, dollars) 2007 2007 2006 2005 ------------------------------------------------------------------------- Cash flow from operating activities 45,497 119,825 110,656 62,147 Net earnings 40,027 14,479 68,078 60,680 Cash distributions paid 22,952 89,799 86,509 77,013 ------------------------------------------------------------------------- Excess (shortfall) of cash flow from operating activities over dist- ributions paid 22,545 30,026 24,147 (14,866) Excess (shortfall) of net earnings over dist- ributions paid 17,075 (75,320) (18,431) (16,333) ------------------------------------------------------------------------- In 2007, cash flow from operating activities was $119.8 million, $30.0 million greater than distributions paid. Included in the calculation of cash flow from operating activities was $25.5 million to fund an increase in non-cash working capital. In the fourth quarter of 2007, cash flow from operating activities was $45.5 million, including $3.9 million generated from a decrease in non-cash working capital. Cash flow from operating activities both in the fourth quarter of 2007 and for the year were sufficient to fund cash distributions paid. Cash distributions paid for 2007 of $89.8 million exceeded net earnings by $75.3 million. The shortfall is attributable to the inclusion of non-cash items for future income taxes ($72.6 million), depreciation, amortization and accretion ($44.5 million) and unrealized losses on financial instruments ($12.6 million) in the calculation of net income. In the fourth quarter of 2007, net earnings of $40.0 million exceeded cash distributions by $17.0 million. Future income taxes can fluctuate from period to period as a result of changes in tax laws and rates (such as the enactment in the second quarter of 2007 of the tax on distributions of flow-through entities or the reduction of income tax rates in 2006 and 2007) or changes in the operating results of the underlying operating entities of Keyera. These items do not affect cash flow generated in the current period. Non-cash charges such as depreciation and amortization are based upon the historical cost of Keyera's property, plant and equipment and do not accurately represent the fair market value or the replacement cost of the assets in today's economic environment, nor do they affect cash flow generated in the current period. Non-cash unrealized gains and losses on financial instruments result from Keyera's use of financial contracts, such as energy-related forward sales, price swaps, physical exchanges and options to manage some of the commodity price risk inherent in the marketing business. Their fair value is determined based upon estimates of future prices. The change in fair value of these contracts during the current period has no effect on cash flow generated. Upon settlement in future periods, the unrealized estimate is reversed and the realized gain or loss is included in earnings. Due to the inclusion of such non-cash charges in net earnings, distributions paid may exceed net earnings. Although non-cash charges do not affect current period cash generation, any excess of distributions over net earnings would be a return of unitholders' capital. Distributable Cash Flow Distributable cash flow is not a standard measure under GAAP and therefore may not be comparable to similar measures reported by other entities. Distributable cash flow is used to assess the level of cash flow generated from ongoing operations and to evaluate the adequacy of internally generated cash flow to fund distributions. Following is a reconciliation of distributable cash flow to its most closely related GAAP measure, cash flow from operating activities. Distributable Cash Flow Three Months Ended Twelve months ended (Thousands of Canadian December 31, December 31, dollars) 2007 2006(1) 2007 2006(1) ------------------------------------------------------------------------- Cash flow from operating activities 45,497 42,130 119,825 110,656 Add (deduct): Changes in non cash working capital (3,885) (13,584) 25,450 (6,545) Maintenance capital (192) (288) (1,437) (3,011) Non-controlling interest distributable cash flow - (285) (369) (1,153) ------------------------------------------------------------------------- Distributable cash flow 41,420 27,973 143,469 99,947 ------------------------------------------------------------------------- Distributions to unitholders 22,965 21,742 90,206 86,605 (1) The calculation of distributable cash flow for the comparative period has been amended to consider the non-cash effect of unrealized foreign exchange gains and losses. For the three and twelve months ended December 31, 2006, $287 and $228 of unrealized foreign exchange gains have been included in the change in non-cash working capital. Distributable cash flow of $41.4 million in the fourth quarter of 2007 and $143.5 million for the year exceeded distributions to unitholders of $18.5 million and $53.3 million in the respective periods. Changes in non-cash working capital are excluded from the determination of distributable cash flow because they are primarily the result of seasonal fluctuations in product inventories or other temporary changes and are generally funded with short-term debt. Also deducted from distributable cash flow are maintenance capital expenditures that are funded from current operating cash flow. Distribution policy In determining the level of cash distributions to unitholders, Keyera's Board of Directors takes into consideration current and expected future levels of distributable cash flow (including income tax), capital expenditures, borrowings and debt repayments, changes in working capital requirements and other factors. Changes in non-cash working capital are primarily the result of seasonal fluctuations in product inventories or other temporary changes and are generally funded with short-term debt. These changes in non-cash working capital are therefore excluded in the determination of distributable cash flow. Over the long-term, Keyera expects to pay distributions from distributable cash flow. Growth capital expenditures will be funded from retained operating cash flow, along with proceeds from additional debt or equity, as required. Although Keyera intends to continue to make regular monthly cash distributions to its unitholders, these distributions are not guaranteed. Sustainability of productive capacity Keyera's Gathering and Processing and NGL Infrastructure segments operate long-life infrastructure assets consisting of natural gas processing plants and gathering systems, NGL processing plants, storage facilities and transportation facilities. These facilities provide services to numerous energy producers over a wide geographic area. Throughput at each natural gas processing plant is dependent upon the natural gas production of third party producers within the capture area or franchise area of the plant. Demand for fractionation, storage and transportation services is dependent upon the supply of NGL mix obtained from the processing of third party raw natural gas and the market demand for end-use products (propane, butane and condensate). Keyera has comprehensive inspection, monitoring and maintenance programs in place. The objectives of these programs are to keep the facilities in good working order and to maintain their ability to operate reliably for many years. These maintenance and repair expenditures totaled $3.4 million in the fourth quarter of 2007 and $29.5 million for the year. Of these amounts, $3.2 million and $28.0 million were included in operating costs and will be recovered through the fee structure over varying periods of time, depending upon the fee structure. At these levels of maintenance and repair, Keyera's plants and facilities can continue to operate safely for decades to come. Significant capital expenditures are not normally required to maintain the existing productive capacity, but may be required if significant changes are made in regulatory requirements. Several of Keyera's sour gas plants rely on acid gas injection to dispose of the hydrogen sulphide and other waste products removed during processing. Acid gas injection involves the injection and sequestration of carbon dioxide and hydrogen sulphide into depleted underground reservoirs. The sustainability of this process is dependent upon the availability of suitable reservoirs. If suitable reservoirs were not available, alternate processes would be required, the capacity of the plant could be reduced or expenditures required to replace the lost capacity would be necessary. These alternatives would have an adverse effect on cash flow. Cash flows from operating activities are determined primarily by the quantity and composition of product throughput at the facility and the fee structure. Throughput is influenced by the ongoing development activities of numerous third parties who may increase production volumes by drilling new wells, tying in previously drilled wells, completing new zones in existing wells or enhancing production volumes through stimulation or enhanced recovery techniques. If third parties are unsuccessful in their development activities, Keyera's cash flow could be adversely affected despite having physical capacity available. Growth capital expenditures are generally undertaken to expand capture areas, add new capacity or introduce new services. If Keyera is unsuccessful in extending capture areas or adding new capacity and services, cash flow from operating activities may be reduced. Standard and Poor's has assigned the Fund an SR-3 stability rating, indicating the expectation of a high level of stability in distributions. Additional information on the capacities and constraints related to Keyera's plants, other risks and trends that could affect the financial performance of Keyera and the steps taken to mitigate these risks, readers are referred to the descriptions in this MD&A and to Keyera's 2007 Annual Information Form, which is available on SEDAR. Units and Convertible Debentures During 2007, $1.7 million of convertible debentures (before adjustment for deferred financing costs) were converted into 143,321 trust units and 190,298 trust units were issued under the DRIP in consideration of $3.3 million, bringing the total units outstanding at December 31, 2007 to 61,264,372. Convertible debentures outstanding at December 31, 2007 were $21.8 million. FUND REORGANIZATION In June 2007, Unitholders approved an internal reorganization of Keyera's legal structure (the "Reorganization"). Due to interpretation issues surrounding the SIFT Legislation, Keyera amended certain elements of the Reorganization prior to implementation. On January 2, 2008, upon receipt of a favourable advance ruling from the Canada Revenue Agency and the final order from the Alberta Court of Queen's Bench approving the plan of arrangement for the amended Reorganization, the Reorganization was completed. The Reorganization is described in detail in the Material Change Report as filed on SEDAR (www.sedar.com) on January 11, 2008. The Reorganization streamlined Keyera's legal structure and simplified accounting, legal reporting and income tax compliance, all of which is expected to reduce the general and administrative costs associated with these activities. As a result of the amendments to the Reorganization, there were not any significant immediate tax savings within Keyera's structure, but the new structure does permit Keyera to defer the utilization of some tax pools until after January 1, 2011. This enhanced tax planning flexibility should enable Keyera to minimize the amount of cash taxes payable in 2011, when Keyera is expected to become taxable under the SIFT Legislation. Keyera is looking at a variety of options to continue to enhance it tax planning flexibility, including the possibility of undertaking a further restructuring depending on whether amendments are made to the SIFT Legislation. (See "Business Environment - New Tax on Flow-through Entities"). As well, Keyera plans to reduce the use of its available tax deductions from 2008 through 2010, thereby increasing deductions available for the years after 2010. Accounting Matters and Controls Changes in Accounting Policies On January 1, 2007, we adopted the following Canadian Institute of Chartered Accountants ("CICA") Handbook Sections: - Section 1530, Comprehensive Income; - Section 3251, Equity; - Section 3855, Financial Instruments - Recognition and Measurement; - Section 3861, Financial Instruments - Presentation and Disclosure; and - Section 3865, Hedges. For a description of the new accounting policies and the impact on the Fund's financial statements including the impact on the Fund's deferred financing fees, long-term debt and opening accumulated deficit refer to note 2 of the Consolidated Financial Statements for the year ended December 31, 2007. Future Accounting and Reporting Changes Convergence of Canadian GAAP with International Financial Reporting Standards In 2006, Canada's Accounting Standards Board (AcSB) ratified a strategic plan that will result in the convergence of Canadian GAAP, as used by public companies, with International Financial Reporting Standards over a transitional period. The AcSB has developed and published a detailed implementation plan, with a changeover date for fiscal years beginning on or after January 1, 2011. This initiative is in its early stages as of the date on these annual Consolidated Financial Statements. Accordingly, it would be premature to assess the impact of the initiative on the Fund at this time. Financial Instruments - Disclosures and Presentation The AcSB has issued CICA Handbook Sections 3862 and 3863, Financial Instruments - Disclosures, and Financial Instruments - Presentation. Section 3862 requires entities to provide disclosures in their financial statements that enable users to evaluate the significance of financial instruments to the entity's financial position and performance. It also requires that entities disclose the nature and extent of risks arising from financial instruments and how the entity manages those risks. Section 3863 establishes standards for presentation of financial instruments and non-financial derivatives and deals with the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, losses and gains, and the circumstances in which financial assets and financial liabilities are offset. These standards will be effective for the Fund for periods ending after January 1, 2008. Capital Disclosures The AcSB has issued CICA Handbook Section 1535, Capital Disclosures, which requires entities to disclose their objectives, policies and processes for managing capital and whether they are in compliance with any externally imposed capital requirements. This standard will be effective for the Fund for periods ending after January 1, 2008. Inventories The AcSB has issued CICA Handbook Section 3031, Inventories, which essentially modifies guidance relating to the scope, measurement and allocation of costs for inventory. The Fund is currently evaluating the impact of the adoption of this new Section on its consolidated financial statements. This standard will be effective for the Fund for periods ending after January 1, 2008. Goodwill and Intangible Assets In February 2008, the AcSB issued CICA Handbook Section 3064, Goodwill and Intangible Assets, replacing existing guidance (Sections 3062 and 3450) for these areas. This new section establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. The Fund is currently evaluating the impact of the adoption of this new Section on its consolidated financial statements. This standard will be effective for the Fund for periods ending after January 1, 2009. Control Environment Disclosure Controls and Procedures As of December 31, 2007, 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. Internal Control Over Financial Reporting As of December 31, 2007, under the supervision of and with the participation of Keyera's management, including the Chief Executive Officer and the Chief Financial Officer, internal control over financial reporting has been designed and maintained in order to provide reasonable assurance regarding the reliability of financial reporting. During the quarter ended December 31, 2007, there have been no material changes in internal control over financial reporting. Selected Financial Information The following table presents selected annual financial information for the Fund: ------------------------------------------------------------------------- (Thousands of Canadian dollars, except per unit information) 2005 2006 2007 ------------------------------------------------------------------------- Operating revenues - Marketing 1,013,334 1,161,899 1,250,541 - Gathering and Processing 139,274 166,736 187,490 - NGL Infrastructure 34,959 39,888 41,110 Net earnings 60,680 68,078 14,479 Net earnings per unit ($/unit): - Basic 1.03 1.12 0.24 - Diluted 0.96 1.10 0.24 Distributions to unitholders 78,541 86,605 90,206 Distributions to unitholders per unit ($/unit) 1.33 1.43 1.48 Trust Units outstanding (thousands) - Weighted average (basic) 58,947 60,604 61,098 - Weighted average (diluted) 63,075 62,794 61,098 Total assets 1,218,160 1,223,012 1,330,999 Total long-term financial liabilities 345,955 338,499 517,740 ------------------------------------------------------------------------- 2007 compared to 2006 For 2007 revenues from Marketing were $1,250.5 million, an increase of $88.6 million compared to the previous year. Higher prices, partially offset by lower volumes, and the growing contribution from the crude oil midstream business accounted for the increase. Also included in 2007 revenues were $20.0 million of charges related to the settlement and change in fair value of financial contracts that were part of Keyera's risk management program. Revenues from facilities were $228.6 million, up $22.0 million compared to 2006. Gathering and Processing revenue for 2007 was $187.5 million, an increase of $20.8 million, or 12%, compared to the previous year. The increase was due primarily to higher throughput in the Foothills Region, the flow through of turnaround costs incurred at the Rimbey, Brazeau River and Bigoray gas plants, the conversion of fixed fee arrangements to flow-through arrangements and incremental fees from the new compression added at the Rimbey gas plant in late 2006 and early 2007. NGL Infrastructure revenue for 2007 was $41.1 million, an increase of $1.2 million, or 3%, compared to the previous year. The increase is primarily due to higher storage revenues at Keyera's Fort Saskatchewan facility. Consolidated net earnings for 2007 were $14.5 million, a decrease of $53.6 million from 2006. The decrease was due primarily to the non-cash future income tax expense, higher general and administrative costs, interest expense and depreciation charges, partially offset by strong operating margins in all segments. The Fund declared $90.2 million of distributions to unitholders in 2007, an increase of $3.6 million due to an increase in the distributions paid per unit in May 2007, as well as a greater number of units outstanding resulting from conversions of debentures and the DRIP. 2006 compared to 2005 For 2006, revenues from Marketing were $1,161.9 million, an increase of $148.6 million compared 2005. Approximately $52.3 million of the increase was due to the growth of the crude oil midstream business that commenced operation in the fourth quarter of 2005. Also included in revenue was $7.0 million related to the settlement and change in fair value of financial contracts that were part of Keyera's risk management program. The remainder was primarily due to higher NGL volumes and prices compared to last year. Revenues from facilities were $206.6 million, up $32.4 million compared to 2005. Gathering and Processing revenue for 2006 was $166.7 million, an increase of $27.5 million, or 20%, compared to the previous year. The increase was due primarily to higher throughput increasing sour raw gas volumes, which attract a higher processing fee, at the Brazeau River gas plant, the recovery of expenses incurred during the Chinchaga and Strachan gas plant maintenance turnarounds and increased ownership in the Strachan gas plant for the full year. NGL Infrastructure revenue for 2006 was $39.9 million, an increase of $4.9 million, or 14%, compared to the previous year. The increase was primarily due to higher storage revenues at Keyera's Fort Saskatchewan facility, as well as a non-recurring adjustment of approximately $1 million earned upon the expiration of a long-term contract in the first quarter of 2006. Consolidated net earnings for 2006 were $68.1 million, an increase of $7.4 million from 2005. This increase was primarily attributable to the strong contribution of the storage business in the NGL Infrastructure segment, lower long-term incentive plan costs in the general and administrative expenses and the recovery of future income taxes in the second quarter of 2006. Partially offsetting this were lower operating margins experienced in the third and fourth quarters of 2006 in the Marketing segment, primarily attributable to the weakening of product margins. The Fund declared $86.6 million of distributions to unitholders in 2006, an increase of $8.1 million. The increase was due to higher average distributions per unit in 2006, as well as a higher number of units outstanding resulting from conversions of debentures and the DRIP. The following table presents selected quarterly financial information for the Fund: Three months ended (Thousands of Canadian dollars) ------------------------------------------------------------------------- Mar 31, Jun 30, Sep 30, Dec 31, 2006 2006 2006 2006 ------------------------------------------------------------------------- Operating revenues: - Marketing 316,841 279,241 279,492 286,325 - Gathering and Processing 38,053 40,772 44,290 43,621 - NGL Infrastructure 9,606 8,549 10,878 10,855 Net earnings(1) 15,384 25,969 11,797 14,928 Net earnings per unit ($/unit) Basic 0.26 0.43 0.19 0.25 Diluted 0.22 0.39 0.16 0.24 Trust units outstanding (thousands) Weighted average (basic) 60,291 60,560 60,692 60,865 Weighted average (diluted) 63,321 62,768 62,817 62,869 Distributions to unitholders 21,553 21,631 21,679 21,742 ------------------------------------------------------------------------- Three months ended (Thousands of Canadian dollars) ------------------------------------------------------------------------- Mar 31, Jun 30, Sep 30, Dec 31, 2007 2007 2007 2007 ------------------------------------------------------------------------- Operating revenues: - Marketing 307,342 292,326 276,957 373,916 - Gathering and Processing 41,949 44,277 50,744 50,520 - NGL Infrastructure 9,692 9,525 10,044 11,849 Net earnings(1) 19,012 (59,870) 15,310 40,027 Net earnings per unit ($/unit) Basic 0.31 (0.98) 0.25 0.65 Diluted 0.31 (0.95) 0.25 0.64 Trust units outstanding (thousands) Weighted average (basic) 60,972 61,061 61,136 61,219 Weighted average (diluted) 62,918 62,967 63,011 63,059 Distributions to unitholders 21,773 22,538 22,931 22,965 ------------------------------------------------------------------------- (1) Since the adoption of the new accounting standards effective January 1, 2007, Keyera has had no transactions that required the use of other comprehensive income and therefore comprehensive income equals net earnings. December 31, 2007 compared to September 30, 2007 Marketing revenues of $373.9 million in the fourth quarter of 2007 increased from the third quarter of 2007 by $96.9 million. This increase was due to the seasonal increase in sales volumes and higher prices. Net earnings were $40.0 million, an increase of $24.7 million due primarily to the strong operating margins earned in the Marketing segment and the recognition of a $11.7 million future income tax recovery. September 30, 2007 compared to June 30, 2007 Third quarter Marketing revenues of $277.0 million decreased from the prior quarter by $15.4 million. This decrease was due to a combination of lower NGL volumes, particularly in butane and condensate, and the effect of the $5.7 million of unrealized loss on financial instruments. Gathering and Processing revenue of $50.7 million increased by $6.5 million due to higher throughput at most plants and higher fees at the Bigoray and Brazeau River gas plants. Furthermore, volumes at the Rimbey gas plant improved over the previous quarter as it was taken offline for a 17-day turnaround in the second quarter. Net earnings were $15.3 million, an increase of $75.2 million from previous quarter. This increase was primarily due to the recording of $80.2 million of future income taxes in the second quarter as a result of the Canadian government enacting taxation on publicly traded income trusts. Without the effect of this non-cash future income tax expense, net earnings for the third quarter decreased by $5.1 million from the second quarter, largely due to lower Marketing operating margins. June 30, 2007 compared to March 31, 2007 For the second quarter of 2007, Marketing revenues of $292.3 million decreased by $15.0 million from the prior quarter. This decrease in revenues was due primarily to a seasonal decline in sales volumes. Gathering and Processing revenue of $44.3 million increased by $2.3 million primarily due to higher throughput volumes in the Foothills Region, despite maintenance turnarounds at the Rimbey gas plant, Keyera's largest facility, and the Brazeau North gas plant. NGL Infrastructure revenue of $9.5 million remained relatively unchanged from the first quarter of 2007, reflecting the long-term storage contracts established in early 2007. A net loss of $59.9 million was recorded, a decrease of $78.9 million from the prior quarter. This loss was due to the recording of an $80.2 million provision for future income tax expense resulting from the enactment of the Canadian government's tax on publicly traded income trusts starting in 2011. March 31, 2007 compared to December 31, 2006 Marketing revenues of $307.3 million increased by $21.0 million due to strong seasonal demand for propane over the last quarter of 2006. First quarter butane margins and demand continued to improve over the previous quarter, along with the market conditions for condensate. Keyera's crude oil midstream also contributed to the increase in Marketing revenue. Gathering and Processing revenue for the first quarter of 2007 was $41.9 million, a decrease of $1.7 million from the last quarter of 2006. The decrease in revenue was due to a slight decrease in throughput volume in the West Central Region offset by higher volumes in the Foothills Region. Operating revenues from NGL Infrastructure were $9.7 million, a decrease of $1.2 million from the fourth quarter of 2006. This decrease was primarily due to lower fractionation revenues, particularly at the Fort Saskatchewan facility. Net earnings were $19.0 million, an increase of $4.1 million from the previous quarter. This increase was primarily due to stronger marketing operating margins offset by higher general and administrative costs. December 31, 2006 compared to September 30, 2006 Marketing revenues of $286.3 million in the fourth quarter of 2006 increased from the third quarter of 2006 by $6.8 million. This increase was largely due to the seasonal increase in sales volumes. NGL Infrastructure revenue of $10.9 million was consistent with the prior quarter. Net earnings were $14.9 million, an increase of $3.1 million due to higher margins experienced in the NGL Infrastructure segment and lower Gathering and Processing expenses. September 30, 2006 compared to June 30, 2006 Gathering and Processing revenue of $44.3 million increased by $3.5 million due to higher throughput, the increasingly sour gas at the Brazeau River gas plant which attracts a higher processing fee and the recovery of expenses incurred during the Chinchaga gas plant turnaround. NGL Infrastructure revenue of $10.9 million increased by $2.3 million primarily due to increased NGL storage revenues at Fort Saskatchewan. Net earnings were $11.8 million, a decrease of $14.2 million from the previous quarter. This decrease was primarily due to the recovery of future income taxes experienced in the second quarter. June 30, 2006 compared to March 31, 2006 For the second quarter of 2006, Marketing revenues of $279.2 million decreased by $37.6 million from the prior quarter. This decrease in revenues was due primarily to a seasonal decline in sales volumes. Gathering and Processing revenue of $40.8 million increased by $2.7 million primarily due to increased ownership in the Strachan gas plant. NGL Infrastructure revenue of $8.5 million decreased by $1.1 million in comparison to the first quarter of 2006 due to a non-recurring final contract adjustment experienced in the first quarter. Net earnings were $26.0 million, an increase of $10.6 million from the prior quarter. This increase in earnings was primarily attributable to the recovery of future income taxes resulting from the reduction of statutory tax rates in future years. Investor Information Distributions to Unitholders Distributions to Unitholders were $0.375 per unit in the fourth quarter and $1.48 per unit for the full year. The Fund is focused on stable long-term distributions that grow over time. The Board of Directors will consider increasing the level of cash distributions when it is confident that such increase can be sustained. Taxability of Distributions For income tax purposes, distributions paid and declared to Canadian residents in 2007 were 66.2% return of capital with the remainder ordinary income. Additional information is available on Keyera's website under "Investor Information". Both Canadian and non-resident unitholders should seek independent tax advice in respect of the consequences to them of acquiring, holding and disposing of units. Keyera currently anticipates distributions will be largely or fully taxable for Canadian non-exempt unitholders in 2008. This outlook is affected by Keyera's organizational structure and is subject to change, depending on the levels of profitability and capital expenditures in each of Keyera's operating entities. Both Canadian and non-resident unitholders should seek independent tax advice in respect of the consequences to them of acquiring, holding and disposing of units. Factors that could affect the performance of the Fund and the taxability of the distributions are discussed in the Fund's Annual Information Form. Supplementary Information A breakdown of Keyera's operational and financial results, including volumetric and contribution information by major business unit, is available on our website at www.keyera.com under Investor Information, Financial Information. In the third quarter, Keyera realigned its Gathering and Processing assets into new business regions, the Foothills Region and the North Central Region. To assist in analysis, Keyera has reformatted its historical supplementary information to conform to the new business regions. YEAR-END 2007 Results Conference Call and Webcast Keyera will be conducting a conference call and webcast for investors, analysts, brokers and media representatives to discuss the year-end 2007 results at 8:00 am Mountain (10:00 am Eastern) on Wednesday, February 27, 2008. Callers may participate by either dialing 800-732-9303 or 416-644-3417. A recording of the call will be available for replay until midnight, March 5, 2008 by dialing 877-289-8525 or 416-640-1917 and entering pass code 21260574 followed by the pound key. Internet users can listen to the call live on Keyera's website at www.keyera.com under Investor Information, Webcasts. Shortly after the call, an audio archive will be posted on the website for 90 days. Questions We welcome questions from interested parties. Calls should be directed to Keyera's Investor Relations Department at 403-205-7670, toll free at 888-699-4853 or via email at ir@keyera.com. Information on Keyera can also be found on our website at www.keyera.com. Keyera Facilities Income Fund Consolidated Statements of Financial Position As at December 31 (Thousands of Canadian dollars) 2007 2006 As at: $ $ ------------------------------------------------------------------------- ASSETS Current assets Cash 15,657 - Accounts receivable 243,889 160,112 Inventory 76,594 53,939 Asset held for sale (note 7) - 4,200 Other current assets 2,299 4,327 ------------------------------------------------------------------------- 338,439 222,578 Property, plant and equipment (note 3) 914,087 924,947 Intangible assets (note 4) 6,394 10,553 Goodwill (note 4) 71,234 64,934 Future income tax assets (note 9) 845 - ------------------------------------------------------------------------- 1,330,999 1,223,012 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES AND UNITHOLDERS' EQUITY Current liabilities Bank indebtedness - 96 Accounts payable and accrued liabilities 235,124 148,318 Distributions payable (note 12) 7,658 7,251 Credit facilities (note 5) - 107,984 Current portion of long-term debt (note 5) 20,000 - ------------------------------------------------------------------------- 262,782 263,649 Long-term debt (note 5) 313,243 215,000 Convertible debentures (note 6) 21,476 23,542 Asset retirement obligation (note 8) 37,807 34,533 Future income tax liabilities (note 9) 145,214 65,424 ------------------------------------------------------------------------- 780,522 602,148 ------------------------------------------------------------------------- Non-controlling interest (note 18) - 2,744 Unitholders' equity Unitholders' capital (note 10) 681,925 677,025 Deficit (131,448) (58,905) ------------------------------------------------------------------------- 550,477 618,120 ------------------------------------------------------------------------- 1,330,999 1,223,012 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the consolidated financial statements Commitments and contingencies (note 15) Subsequent event (note 19) Approved on behalf of the Fund by its administrator, Keyera Energy Management Ltd.: (Signed) Wesley R. Twiss (Signed) James V. Bertram Director Director Keyera Facilities Income Fund Consolidated Statements of Net Earnings, Comprehensive Income and Deficit For the Year Ended December 31 (Thousands of Canadian dollars, except unit information) 2007 2006 $ $ ------------------------------------------------------------------------- Operating revenues Marketing 1,250,541 1,161,899 Gathering and Processing 187,490 166,736 NGL Infrastructure 41,110 39,888 ------------------------------------------------------------------------- 1,479,141 1,368,523 Operating expenses Marketing 1,172,010 1,102,045 Gathering and Processing 103,792 96,558 NGL Infrastructure 24,253 23,956 ------------------------------------------------------------------------- 1,300,055 1,222,559 ------------------------------------------------------------------------- 179,086 145,964 General and administrative 21,882 18,892 Interest expense on long-term indebtedness 16,077 13,838 Other interest expense 4,099 4,318 Depreciation and amortization 42,040 39,843 Accretion expense (note 8) 2,482 2,257 Impairment expense 728 373 ------------------------------------------------------------------------- 87,308 79,521 ------------------------------------------------------------------------- Earnings before income tax and non-controlling interest 91,778 66,443 Income tax expense (recovery) (note 9) 76,993 (2,660) ------------------------------------------------------------------------- Earnings before non-controlling interest 14,785 69,103 Non-controlling interest 306 1,025 ------------------------------------------------------------------------- Net earnings 14,479 68,078 Other comprehensive income - - ------------------------------------------------------------------------- Comprehensive income (note 2) 14,479 68,078 Deficit, beginning of year (58,905) (40,378) Change in accounting policies (note 2) 3,184 - Distributions to unitholders (note 12) (90,206) (86,605) ------------------------------------------------------------------------- Deficit, end of year (131,448) (58,905) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Weighted average number of units (thousands) (note 11) - basic 61,098 60,604 - diluted 61,098 62,794 Net earnings per unit (note 11) - basic 0.24 1.12 - diluted 0.24 1.10 ------------------------------------------------------------------------- See accompanying notes to the consolidated financial statements Keyera Facilities Income Fund Consolidated Statements of Cash Flows For the Years Ended December 31 (Thousands of Canadian dollars) 2007 2006 Net inflow (outflow) of cash: $ $ ------------------------------------------------------------------------- Operating activities Net earnings 14,479 68,078 Items not affecting cash: Depreciation and amortization 42,040 39,843 Accretion expense 2,482 2,257 Impairment expense 728 373 Unrealized loss (gain) on financial instruments 12,563 (263) Loss on sale of assets 245 - Future income tax expense (recovery) (note 9) 72,645 (7,042) Non-controlling interest 306 1,025 Asset retirement obligation expenditures (note 8) (213) (160) Changes in non-cash operating working capital (note 16) (25,450) 6,545 ------------------------------------------------------------------------- 119,825 110,656 ------------------------------------------------------------------------- Investing activities Capital expenditures (25,313) (73,868) Acquisition of non-controlling interest (note 18) (6,716) - Proceeds on sale of assets 4,704 - Additions to intangibles - (1,115) Changes in non-cash working capital (note 16) (1,114) (651) ------------------------------------------------------------------------- (28,439) (75,634) ------------------------------------------------------------------------- Financing activities (Repayment) issuance of debt under credit facilities (note 5) (107,984) 41,984 Issuance of long-term debt, net of financing costs (note 5) 118,895 - Issuance of trust units (note 10) 3,255 4,252 Distributions paid to unitholders (note 12) (89,799) (86,509) Distributions or dividends paid to others - (479) ------------------------------------------------------------------------- (75,633) (40,752) ------------------------------------------------------------------------- Net cash inflow (outflow) 15,753 (5,730) (Bank indebtedness) cash, beginning of year (96) 5,634 ------------------------------------------------------------------------- Cash (bank indebtedness), end of year 15,657 (96) ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the consolidated financial statements See note 16 for cash interest and taxes paid Keyera Facilities Income Fund Notes to Consolidated Financial Statements For the Years Ended December 31, 2007 and 2006 (All amounts expressed in thousands of Canadian dollars, except as 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 ("NGLs") and crude oil processing, transportation, storage and marketing in Canada and the U.S. Its subsidiaries include Keyera Energy Facilities Ltd. ("KEFL"), Keyera Energy Ltd. ("KEL"), Keyera Energy Inc. ("KEI"), and Rimbey Pipeline Limited Partnership ("RPLP"). 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 33.83% interest in the Partnership. 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 is 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 ("GAAP"). The consolidated financial statements include the accounts of the Fund and all controlled entities. All material intercompany accounts and transactions have been eliminated upon consolidation. Measurement uncertainty The preparation of financial statements in accordance with GAAP 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. Foreign currency translation Monetary assets and liabilities denominated in foreign currencies are translated into Canadian dollars 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 marketing NGLs and natural gas and from crude oil midstream activities is recognized based on volumes delivered to customers at contracted delivery points and rates and when collection is reasonably assured. Gathering and Processing revenue Gathering and Processing revenue is generated through fixed fee arrangements or flow-through arrangements that are designed to recover operating costs and provide a return on capital. Amounts collected in excess of the recoverable amounts under flow-through arrangements are recorded as a current liability. Recoverable amounts in excess of the amounts collected under flow-through arrangements are recorded as a current receivable. Revenue is recognized when services have been performed and collection is reasonably assured. Revenue from take or pay arrangements is recognized as service is provided or upon expiry of the commitment, whichever occurs later. 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 and collection is reasonably assured. Joint ventures Substantially all 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. Cash and cash equivalents Cash may include cash equivalents such as short-term investments with maturities 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 primarily of natural gas processing and gathering systems, NGL infrastructure facilities and marketing storage 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 depreciation periods range from five to thirty-two years for Gathering and Processing, twelve to thirty-one years for NGL Infrastructure, two to twenty-four years for Marketing and six to twenty-two years for corporate assets. Impairment on property, plant and equipment is measured in a two-step process. Step one calculates the net recoverable amount, determined by the undiscounted future cash flows of the asset or asset group. Step two determines the impairment amount, equal to the difference between the carrying amount and fair value. Fair value is determined by discounting future estimated cash flows. Intangible assets Goodwill Goodwill resulted from business combinations and represents the portion of the purchase price that was in excess of the fair value of net identifiable assets acquired. Goodwill is recorded at cost and is not subject to amortization. It is tested at least annually for impairment. The impairment test for goodwill is a two-step process. Step one consists of a comparison of the fair value of a reporting unit with its carrying amount, including the goodwill allocated to the reporting unit. Measurement of the fair value of a reporting unit is based on one or more fair value measures, including present value calculations of estimated future cash flows and estimated amounts at which the unit as a whole could be bought or sold in a current transaction between willing parties. The Fund also considers its market capitalization as of the date of the impairment test. If the carrying amount of the reporting unit exceeds its fair value, step two requires the fair value of the reporting unit to be allocated to the underlying assets and liabilities of that reporting unit, resulting in an implied fair value of goodwill. If the carrying amount of the reporting unit exceeds the implied fair value of that goodwill, an impairment loss equal to the excess is recorded in net earnings. Other intangible assets Other intangible assets consist of the marketing business contributed by the partners upon formation of the Partnership and marketing business contracts acquired on business combinations and asset purchases. These assets were recorded at fair market value upon initial recognition and are being amortized over their estimated economic life. The unamortized balance of these intangible assets is assessed periodically for impairment based on management's best estimates of future net revenues from the Marketing business. 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 net 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 net earnings, over the estimated time period until settlement of the obligation. Actual expenditures incurred are charged against the asset retirement obligation. Income taxes Under the Canadian Income Tax Act, the Fund is considered to be a "mutual fund trust" and, until December 31, 2010, 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. 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. Unit-based compensation The Fund has a Long Term Incentive Plan ("LTIP"), which is disclosed in note 13. The LTIP is a stock appreciation right as defined by the Canadian Institute of Chartered Accountants. The amount recognized in compensation expense is determined by multiplying the number of units deemed to have been earned by the current market price of the units. 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, 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 are 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 "if-converted" 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. Certain of the comparative figures in prior periods have been reclassified to conform to the presentation in the current period. CHANGES IN ACCOUNTING POLICIES Financial instruments On January 1, 2007, the Fund adopted the following accounting standards issued by the Canadian Institute of Chartered Accountants ("CICA"): - Section 1506, Accounting Changes; - Section 1530, Comprehensive Income; - Section 3251, Equity; - Section 3855, Financial Instruments - Recognition and Measurement; - Section 3861, Financial Instruments - Disclosure and Presentation; and - Section 3865, Hedges. The Fund has adopted these standards in accordance with their transition provisions and comparative consolidated financial statements have not been restated. The Fund has selected January 1, 2004 as the date for identification of embedded derivatives. Transition amounts have been recorded in opening deficit. All financial instruments must initially be recognized at fair value on the balance sheet. Subsequent measurement of the financial instruments is based on their classification. The Fund has classified each financial instrument into one of the following categories: - Financial assets and financial liabilities held for trading - Loans or receivables - Financial assets held to maturity - Financial assets available for sale - Other financial liabilities The classification depends on the characteristics and the purpose for which the financial instruments were acquired. Except in very limited circumstances, the classification of financial instruments is not changed subsequent to initial recognition. Held for trading Financial assets and financial liabilities classified as held for trading are measured at fair value and changes in those fair values are recognized in net earnings. Derivative instruments and cash have been classified as held for trading. Gains and losses related to derivative contracts are recognized in revenue in the period in which they arise. The estimated fair value of assets and liabilities held for trading is determined by reference to quoted market prices and, if not available, to estimates from third-party brokers or dealers. Transaction costs related to financial assets and financial liabilities classified as held for trading are charged to earnings as incurred. Available for sale Financial assets available for sale are measured at fair value, with changes in those fair values recognized in other comprehensive income. Currently, the Fund does not have any financial assets classified as available for sale. Transaction costs related to financial assets classified as available for sale would be charged to earnings as they occur. Held to maturity Financial assets held to maturity are measured at amortized cost using the effective interest rate method of amortization. Currently, the Fund does not have any financial assets classified as held to maturity. Transaction costs related to financial assets held to maturity would be charged to earnings as they occur. Loans or receivables Loans or receivables are measured at amortized cost using the effective interest rate method of amortization. Trade accounts receivables have been classified in this category. The related transaction costs would be charged to earnings as they arise. Other financial liabilities Other financial liabilities include accounts payable, accrued liabilities, distributions payable, short-term debt, convertible debentures and long-term debt. With the exception of derivative instruments, the Fund has classified all financial liabilities as other financial liabilities. Transaction costs relating to short-term liabilities are charged to earnings as they occur. For long-term liabilities, the transaction costs that are directly attributable to the issuance of a financial liability are included with the fair value initially recognized for that financial instrument. These costs are amortized to earnings using the effective interest rate method. As of January 1, 2007, unamortized deferred financing fees of $985 relating to the Fund's long-term debt and $502 relating to convertible debentures have been reclassified for presentation purposes from intangible assets to long-term debt and convertible debentures. These fees are now amortized to earnings using the effective interest rate method. The Fund assesses at each balance sheet date whether a financial asset carried at cost is impaired. If there is objective evidence that an impairment loss exists, the amount of the loss is measured as the difference between the carrying amount of the asset and its fair value. The carrying amount of the asset is reduced and the amount of the loss is recognized in earnings. Derivatives and embedded derivatives Derivative financial instruments are financial contracts that derive their value from underlying changes in interest rates, foreign exchange rates, credit spreads, commodity prices, equities or other financial measures. The Fund uses financial instruments such as commodity price swaps, electricity price swaps, foreign exchange forward contracts, and interest rate swaps to manage its risks. Natural gas, NGL and crude oil contracts that require physical delivery at fixed prices and do not meet the Fund's expected purchase, sale or usage requirements are accounted for as derivative financial instruments. Derivatives may include those derivatives that are embedded in financial or non-financial contracts that are not closely related to the host contracts. With the adoption of the new accounting standards on financial instruments, such embedded derivatives are now to be accounted for separately from the host contract. Derivative instruments, including embedded derivatives, are classified as held for trading and are recorded on the consolidated statements of financial position at fair value. Changes in the fair value of these financial instruments are recognized in earnings in the period in which they arise. Hedge accounting Effective January 1, 2007 the Fund has opted to discontinue the use of hedge accounting. All derivative instruments that previously qualified for hedge accounting have been recognized at fair value and unrealized gains and losses have been recorded in earnings. Adopting these standards on January 1, 2007 resulted in the recognition of an asset held for trading in the amount of $3,314, a liability held for trading in the amount of $130 and a $3,184 reduction to the opening deficit. Assets held for trading are included in accounts receivable and liabilities held for trading are included in accounts payable and accrued liabilities. The effect on basic and diluted net earnings per unit was $0.05. Comprehensive income Comprehensive income consists of net earnings and other comprehensive income ("OCI"). OCI comprises the changes in the fair value of the effective portion of derivatives used as hedging items in a cash flow hedge, changes in the fair value of any available for sale financial instruments and foreign currency translation adjustments of self- sustaining foreign operations. Accumulated other comprehensive income ("AOCI") is a new equity category comprised of the cumulative amounts of OCI. No amounts have been recorded in OCI or AOCI as a result of adopting this accounting standard. Future Accounting and Reporting Changes Convergence of Canadian GAAP with International Financial Reporting Standards In 2006, Canada's Accounting Standards Board (AcSB) ratified a strategic plan that will result in the convergence of Canadian GAAP, as used by public companies, with International Financial Reporting Standards over a transitional period. The AcSB has developed and published a detailed implementation plan, with a changeover date for fiscal years beginning on or after January 1, 2011. This initiative is in its early stages as of the date on these annual Consolidated Financial Statements. Accordingly, it would be premature to assess the impact of the initiative on the Fund at this time. Financial Instruments - Disclosures and Presentation The AcSB has issued CICA Handbook Sections 3862 and 3863, Financial Instruments - Disclosures, and Financial Instruments - Presentation. Section 3862 requires entities to provide disclosures in their financial statements that enable users to evaluate the significance of financial instruments to the entitity's financial position and performance. It also requires that entities disclose the nature and extent of risks arising from financial instruments and how the entity manages those risks. Section 3863 establishes standards for presentation of financial instruments and non-financial derivatives and deals with the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, losses and gains, and the circumstances in which financial assets and financial liabilities are offset. These standards will be effective for the Fund for periods ending after January 1, 2008. Capital Disclosures The AcSB has issued CICA Handbook Section 1535, Capital Disclosures, which requires entities to disclose their objectives, policies and processes for managing capital and whether they are in compliance with any externally imposed capital requirements. This standard will be effective for the Fund for periods ending after January 1, 2008. Inventories The AcSB has issued CICA Handbook Section 3031, Inventories, which essentially modifies guidance relating to the scope, measurement and allocation of costs for inventory. The Fund is currently evaluating the impact of the adoption of this new Section on its consolidated financial statements. This standard will be effective for the Fund for periods ending after January 1, 2008. Goodwill and Intangible Assets In February 2008, the AcSB issued CICA Handbook Section 3064, Goodwill and Intangible Assets, replacing existing guidance (Sections 3062 and 3450) for these areas. This new section establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. The Fund is currently evaluating the impact of the adoption of this new Section on its consolidated financial statements. This standard will be effective for the Fund for periods ending after January 1, 2009. 3. Property, plant and equipment Accumulated Net Book Cost Depreciation Value As at December 31, 2007 $ $ $ --------------------------------------------------------------------- Gathering and Processing 841,671 (166,455) 675,216 NGL Infrastructure 276,807 (53,087) 223,720 Marketing 12,761 (771) 11,990 Corporate 9,311 (6,150) 3,161 --------------------------------------------------------------------- Total 1,140,550 (226,463) 914,087 --------------------------------------------------------------------- --------------------------------------------------------------------- Accumulated Net Book Cost Depreciation Value As at December 31, 2006 $ $ $ --------------------------------------------------------------------- Gathering and Processing 826,591 (141,875) 684,716 NGL Infrastructure 264,658 (39,843) 224,815 Marketing 12,179 (254) 11,925 Corporate 8,616 (5,125) 3,491 --------------------------------------------------------------------- Total 1,112,044 (187,097) 924,947 --------------------------------------------------------------------- --------------------------------------------------------------------- Costs associated with assets under development, excluded from costs subject to depreciation, totaled $7,461 as at December 31, 2007 (2006 - $1,757). During the year, a non-core gas plant was written down to its net realizable value, recognizing a $728 impairment expense. 4. Intangible assets and goodwill Accumulated Net Book Cost Amortization Value As at December 31, 2007 $ $ $ --------------------------------------------------------------------- Gathering and Processing(a) 39,219 - 39,219 NGL Infrastructure(a) 32,015 - 32,015 Marketing(b) 19,290 (12,896) 6,394 --------------------------------------------------------------------- Total 90,524 (12,896) 77,628 --------------------------------------------------------------------- --------------------------------------------------------------------- Accumulated Net Book Cost Amortization Value As at December 31, 2006 $ $ $ --------------------------------------------------------------------- Gathering and Processing(a) 39,219 - 39,219 NGL Infrastructure(a) 25,715 - 25,715 Marketing(b) 19,290 (10,223) 9,067 Corporate(c) 3,333 (1,847) 1,486 --------------------------------------------------------------------- Total 87,557 (12,070) 75,487 --------------------------------------------------------------------- --------------------------------------------------------------------- (a) Intangible assets for the Gathering and Processing and NGL Infrastructure segments consist of goodwill. (b) Intangible assets for the Marketing segment consist of the marketing business contributed by the Partners when the Partnership was first formed, the marketing business of EnerPro acquired in 2004 and the marketing contracts acquired with the U.S. propane terminals in 2006. These assets are being amortized over the remaining economic life of one to six years. Amortization expense for the year ended December 31, 2007 was $2,673 (2006 - $1,930). (c) For 2006, intangible assets for the corporate segment related to deferred financing fees. Upon adoption of the new accounting standards on financial instruments (note 2), deferred financing fees were reclassified to their related debt balances and amortized using the effective interest rate method over the remaining terms of the related debt. Long-term debt deferred financing fees are discussed further in note 5. Convertible debenture deferred financing fees are discussed further in note 6. 5. Credit facilities and long-term debt 2007 2006 As at $ $ --------------------------------------------------------------------- Bank credit facilities(a) - 100,984 Revolving demand loan(a) - 7,000 --------------------------------------------------------------------- Total credit facilities - 107,984 --------------------------------------------------------------------- --------------------------------------------------------------------- Current portion of long-term debt(b) 20,000 - Long-term debt(b) 315,000 215,000 Deferred financing costs(1) (1,757) - --------------------------------------------------------------------- Total long-term debt 333,243 215,000 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) Deferred financing costs have been reclassified to long-term debt upon adoption of the new accounting standards (see note 2). Previously, these costs were included in intangible assets. (a) The Partnership has a $150,000 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, 2010, unless extended. In addition, the Royal Bank of Canada has provided a $15,000 revolving demand facility and the Toronto Dominion Bank has 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 rates for the year ended December 31, 2007 was 5.74% (2006 - 5.43%). As at December 31, 2007, the balance outstanding on the bank credit facilities was $nil (2006 - $107,984). On July 12, 2007, the $7,000 unsecured revolving demand loan facility related to a subsidiary of the Partnership was terminated. (b) In 2003, $125,000 of unsecured senior notes were issued by the Partnership and KEFL in three parts: $20,000 due in 2008 bearing interest at 5.42%, $52,500 due in 2010 bearing interest at 5.79% and $52,500 due in 2013 bearing interest at 6.16%. Interest is payable monthly. Financing costs of $1,215 have been deferred and are amortized using the effective interest rate method over the remaining terms of the related debt. The effective interest rates for the year ended December 31, 2007 were 5.63%, 5.95% and 6.29% for the notes due in 2008, 2010 and 2013 respectively (5.42%, 5.79% and 6.16% for the year ended December 31, 2006). In 2004, $90,000 of unsecured senior notes were issued by KEFL and guaranteed by the Partnership. The notes bear interest at 5.23% and mature on October 1, 2009. Interest is payable semi- annually. Financing costs of $568 have been deferred and are amortized using the effective interest rate method over the remaining term of the debt. The effective interest rate for the year ended December 31, 2007 was 5.37% (2006 - 5.23%). On September 4, 2007, $80,000 of unsecured senior notes were issued by KEFL and guaranteed by the Partnership and the Fund in two tranches: $40,000 due in 2017 bearing interest at 5.89% and $40,000 due in 2022 bearing interest at 6.14%. On December 2, 2007, a further $40,000 of unsecured senior notes were issued by KEFL in two tranches: $20,000 due in 2017 bearing interest at 5.89% and $20,000 due in 2022 bearing interest at 6.14%. Interest is payable semi-annually. Financing costs of $1,104 have been deferred and are amortized using the effective interest rate method over the terms of the related debt. The effective interest rates for the period were 5.94% and 6.18% for the notes due in 2017 and 2022 respectively. 6. Convertible debentures In 2004, the Fund issued convertible unsecured subordinated debentures in the principal amount of $100,000. 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 $1,613 has been accrued for the twelve months ended December 31, 2007 (2006 - $1,776). 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, 2007, $78,178 debentures had been converted to trust units (2006 - $76,458). Financing costs consisting of an underwriters' commission of $4,000 and issuance costs of $332 have been deferred, and when there are no conversions, are being amortized over the term of the debt using the effective interest rate method. Upon conversion of the debentures, the financing cost related to the principal amount of debt converted is adjusted and is recognized as a charge to unitholders' equity. As a result of conversions to date at December 31, 2007, $2,857 has been reclassified to unitholders' equity (2006 - $2,782). As at December 31, 2007, $346 of deferred financing costs remain. The effective interest rate for the year ended December 31, 2007 was 7.36% (2006 - 6.75%). 7. Asset held for sale Asset held for sale consisted of an interest in an electrical generator. In 2006, the equipment was written down to its estimated net realizable value recognizing a $373 charge to impairment expense. On January 23, 2007, the Fund sold its interest in the electrical generator for proceeds of $4,200. 8. 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 Fund's facilities. 2007 2006 For the year ended December 31 $ $ --------------------------------------------------------------------- Asset retirement obligation, beginning of year 34,533 27,776 Liabilities acquired 644 151 Liabilities settled (213) (160) Revisions in estimated cash flows 361 4,509 Accretion expense 2,482 2,257 --------------------------------------------------------------------- Asset retirement obligation, end of year 37,807 34,533 --------------------------------------------------------------------- --------------------------------------------------------------------- The total undiscounted amount of cash flows required to settle the asset retirement obligations is $183,042 which has been discounted using a credit-adjusted risk-free rate of 7% (2006 - $183,159). 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. 9. Income taxes On June 22, 2007, Bill C-52 Budget Implementation Act, 2007 was enacted by the Canadian federal government. This legislation proposes to tax publicly traded trusts in Canada. The new tax is not expected to apply to the Fund until 2011 as the government has provided a transition period for publicly traded trusts that existed prior to November 1, 2006. As a result of the new tax legislation, the Fund recorded an additional $80.2 million future income tax expense and increased its future income tax liability in the second quarter of 2007. This adjustment represents taxable temporary differences of the Partnership that were previously not recorded for future income tax purposes. These temporary differences were originally recorded at a tax-effected rate of 31.5%. During the fourth quarter of 2007, the federal government substantively enacted a 3.5% reduction to its federal corporate income tax rates. Accordingly, the Fund has recorded the temporary differences applicable to the Fund at a rate of 28% resulting in a $5.6 million reduction to the original future income tax expense of $80.2 million recorded in the second quarter of 2007. The following is a reconciliation of income taxes, calculated at the combined federal and provincial income tax rate, to the income tax provision included in the consolidated statements of net earnings. 2007 2006 $ $ --------------------------------------------------------------------- Earnings before tax and non-controlling interest 91,778 66,443 Income from the Fund distributable to unitholders (8,652) (36,061) --------------------------------------------------------------------- Income before taxes - operating subsidiaries 83,126 30,382 --------------------------------------------------------------------- Income tax at statutory rate of 32.12% (2006 - 34.49%) 26,700 10,479 Impact of recording temporary differences of the Partnership 71,305 - Non deductible items excluded from income for tax purposes 4,104 (142) Rate adjustments and changes in estimates (21,281) (10,356) Benefit of long-term incentive plan previously not recorded - (2,202) Benefit of non-capital losses previously not recorded (786) (46) Resource allowance - 3 Adjustments to tax pool balances (3,239) (198) Other 190 (198) --------------------------------------------------------------------- 76,993 (2,660) --------------------------------------------------------------------- Classified as: Current 4,348 4,382 Future 72,645 (7,042) --------------------------------------------------------------------- Income tax expense (recovery) 76,993 (2,660) --------------------------------------------------------------------- --------------------------------------------------------------------- For income tax purposes, the Fund and its subsidiaries have non- capital losses carried forward of approximately $2,981 at December 31, 2007 ($11,987 at December 31, 2006) which are available to offset income of specific entities of the consolidated group in future periods. The benefit of these losses has been recorded at December 31, 2007. During the second quarter of 2007, the Fund recorded a $5,780 future income tax liability with a corresponding increase to goodwill. This adjustment relates to a prior period acquisition that did not reflect a future income tax impact for a temporary difference. A further $520 future tax liability and increase to goodwill was recorded relating to the acquisition of the minority interest in RPLP (see note 18). The future income tax (liabilities) assets relate to losses and to the (taxable) deductible temporary differences in the carrying values and tax bases as follows: 2007 2006 $ $ --------------------------------------------------------------------- Property, plant and equipment (152,747) (71,611) Asset retirement obligation 9,992 4,308 Long-term incentive plan 1,954 1,513 Non-capital losses (38) 3,475 Intangible assets (941) (616) Other (3,434) (2,493) --------------------------------------------------------------------- Future income tax liabilities (145,214) (65,424) --------------------------------------------------------------------- --------------------------------------------------------------------- Property, plant and equipment (444) - Asset retirement obligation 78 - Non-capital losses 832 - Intangible assets 379 - --------------------------------------------------------------------- Future income tax assets 845 - --------------------------------------------------------------------- --------------------------------------------------------------------- 10. Unitholders' capital The 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 will 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 trust 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 if there was trading 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. The Fund has 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 $ --------------------------------------------------------------------- Balance, January 1, 2006 60,125,193 665,914 Units issued on conversion of convertible debentures 597,563 6,859 Units issued pursuant to DRIP 207,997 4,252 --------------------------------------------------------------------- Balance, December 31, 2006 60,930,753 677,025 Units issued on conversion of convertible debentures 143,321 1,645 Units issued pursuant to DRIP 190,298 3,255 --------------------------------------------------------------------- Balance, December 31, 2007 61,264,372 681,925 --------------------------------------------------------------------- --------------------------------------------------------------------- 11. Net earnings per unit Basic per unit calculations for the years ended December 31, 2007 and 2006 were based on the weighted average number of units outstanding for the related period. Convertible debentures were in the money for the years ended December 31, 2007 and 2006 and contributed to the increase in diluted weighted average number of units for these periods. 2007 2006 $ $ --------------------------------------------------------------------- Net earnings - basic 14,479 68,078 Effect of convertible debentures (net of tax)(1) - 1,161 --------------------------------------------------------------------- Net earnings - diluted 14,479 69,239 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) The effect of convertible debentures has been excluded for 2007 as it is anti-dilutive. (thousands) 2007 2006 --------------------------------------------------------------------- Weighted average number of units - basic 61,098 60,604 Additional units if debentures converted(1) - 2,190 --------------------------------------------------------------------- Weighted average number of units - diluted 61,098 62,794 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) The effect of convertible debentures has been excluded for 2007 as it is anti-dilutive. 12. Accumulated distributions to unitholders $ --------------------------------------------------------------------- Balance, January 1, 2006 131,383 Unitholders' distributions declared and paid 79,354 Unitholders' distributions declared 7,251 --------------------------------------------------------------------- Balance, December 31, 2006 217,988 Unitholders' distributions declared and paid 82,548 Unitholders' distributions declared 7,658 --------------------------------------------------------------------- Balance, December 31, 2007 308,194 --------------------------------------------------------------------- --------------------------------------------------------------------- Pursuant to the Fund Declaration of Trust dated April 3, 2003 and its subsequent amendments, the Fund makes monthly distributions to holders of record on the last day of each month. Payments are made on or about the 15th day of the following month. Distributions are paid from "Cash Flow of the Trust", a term that is defined in the Fund Declaration of Trust dated April 3, 2003. The Board of Directors of the Fund may, on or before each Distribution Record Date, declare payable all or any part of the Cash Flow of the Trust for the Distribution Period. The amount and level of distributions to be made for each Distribution Period is determined at the discretion of the Board of Directors of the Fund. In determining its distribution policy, the Board of Directors of the Fund considers several factors, including the Fund's current and future cash flow, capital requirements, debt repayments and other factors. 13. 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 are acquired in the marketplace under the plan. The Plan consists of two types of unit awards, which are described below. Unit awards and the delivery of units under the Plan are accounted for in accordance with the intrinsic value method of accounting for stock-based compensation. The aggregate compensation cost recorded for the Plan was $5,519 for the year ended December 31, 2007 (2006 - $2,319). During the year ended December 31, 2007, 237,294 units were purchased on the market at a cost of $4,429 and 191,327 units were settled in cash for $3,472. (a) Performance Unit Awards The Performance Unit Awards will vest 100% on the third anniversary of the effective date of each award, July 1, 2005, July 1, 2006 and July 1, 2007. The number of units to be delivered will be determined by the financial performance of the Fund over the three-year period and is calculated by multiplying the number of unit awards by an adjustment ratio and a payout multiplier. The adjustment ratio adjusts the number of units to be delivered 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, 2005 July 1, 2006 July 1, 2007 Payout Grant Grant Grant Multiplier ------------------------------------------------------------------------- Less than 1.32 Less than 1.42 Less than 1.44 Nil First range 1.32 - 1.39 1.42 - 1.51 1.44 - 1.51 50%-99% Second range 1.40 - 1.55 1.52 - 1.71 1.52 - 1.67 100%-199% Third range 1.56 and greater 1.72 and greater 1.68 or greater 200% ------------------------------------------------------------------------- As of December 31, 2007, 485,105 Performance Unit Awards (2006 - 529,867) were outstanding: 164,580 effective July 1, 2005, 144,050 effective July 1, 2006 and 176,475 effective July 1, 2007. The compensation cost recorded for these units for the year ended December 31, 2007 was $4,485 using the applicable closing market price of a unit of the Fund (2006 - $1,367). (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, 2005, July 1, 2006 and July 1, 2007, regardless of the performance of the Fund. The number of units to be delivered will be modified 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. As of December 31, 2007, 92,275 Restricted Unit Awards (2006 - 98,735) were outstanding: 14,167 effective July 1, 2005, 26,333 effective July 1, 2006 and 51,775 effective July 1, 2007. The compensation cost recorded for these units for the year ended December 31, 2007 was $1,034 using the applicable closing market price of a unit of the Fund (2006 - $952). 14. Financial instruments Financial instruments include cash, accounts receivable, accounts payable and accrued liabilities, distributions payable, credit facilities, long-term debt, convertible debentures and derivatives held for trading (derivative financial instruments such as foreign exchange contracts, oil price contracts, natural gas price contracts, power price contracts and physical fixed price contracts). Derivatives held for trading Subsidiaries of the Fund enter into contracts to purchase and sell natural gas, NGLs 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. These risks are actively managed 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 exposure to the above risks and regularly reviews its financial instrument activities and all outstanding positions. A significant amount of electricity is consumed by the operating entities at their facilities. Due to the fixed fee nature of some service contracts in place with customers, these entities are unable to flow the cost of electricity to customers in all situations. In order to mitigate this exposure to fluctuations in the price of electricity, price swap agreements may be used. Natural gas, NGL and crude oil contracts that require physical delivery at fixed prices and do not meet the Fund's expected purchase, sale or usage requirements are accounted for as derivative financial instruments. On occasions, the Fund will enter into NGL purchase and sale contracts that are settled in a currency other than the currency that are routinely denominated for such commercial transactions. In these instances, the Fund accounts for these non-financial contracts as embedded derivatives. Derivative instruments held for trading are recorded on the consolidated statement of financial position at fair value. Changes in the fair value of these financial instruments are recognized in earnings in the period in which they arise. As at December 31, 2007, $3,112 of assets held for trading were included in accounts receivable and $12,566 of liabilities held for trading were included in accounts payable and accrued liabilities. Unrealized (losses) gains, representing the change in fair value of derivative contracts are recorded in Marketing operating revenue and NGL Infrastructure operating expense. The unrealized (loss) gain relating to derivative contracts were as follows: Unrealized (loss) gain 2007 2006 $ $ --------------------------------------------------------------------- Marketing (12,007) 263 NGL Infrastructure (556) - --------------------------------------------------------------------- --------------------------------------------------------------------- The fair value of the derivatives are listed below and represent an estimate of the amount that the Fund would receive (pay) if these instruments were closed out at the end of the period. Weighted As at Carrying Fair Average Notional December 31, 2007 Amount $ Value $ Price $ Volume ------------------------------------------------------------------------- Natural gas: Buyer of fixed price swaps (maturing by October 31, 2008) (98) (98) 6.90/GJ 198,000 GJs Electricity: Buyer of fixed price swaps (maturing by December 31, 2008) 444 444 55/MWh 21,960 MWhs NGLs: Seller of fixed price swaps (maturing by March 31, 2008) (11,984) (11,984) 77.97/Bbl 717,345 Bbls Buyer of fixed price swaps (maturing by March 31, 2008) 2,489 2,489 78.43/Bbl 153,999 Bbls Currency: Seller of forward contracts (maturing by January 25, 2008) 111 111 1.0199/USD US$ 6,500 Physical contracts: Seller of fixed price forward contracts (maturing by March 31, 2008) (417) (417) 53.67/Bbl 54,584 Bbls ------------------------------------------------------------------------- ------------------------------------------------------------------------- As at December 31, 2006 Natural gas: Buyer of fixed price swaps (maturing by March 31, 2007) - (130) 7.78/GJ 90,000 GJs Electricity: Buyer of fixed price swaps (maturing by December 31, 2008) - 1,031 55/MWh 43,860 MWhs NGLs: Seller of fixed price swaps (maturing by March 30, 2007) 211 211 72.25/Bbl 450,000 Bbls Currency: Seller of forward contracts (maturing by January 26, 2007) (287) (287) 1.1477/USD US$16,350 Physical contracts: Seller of fixed price forward contracts - - - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- The estimated fair value of all derivatives held for trading is based on quoted market prices and, if not available, on estimates from third-party brokers or dealers. Fair value The carrying values of accounts receivable, accounts payable and accrued liabilities and distributions payable approximate their fair values because the instruments are near maturity or have no fixed repayment terms. The fair value of the credit facilities approximates fair value due to their floating rates of interest. Credit risk The majority of 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 Fund evaluates and monitors the financial strength of its customers in accordance with its credit policy. At December 31, 2007, the accounts receivable from the two largest customers amounted to less than 1% of accounts receivable (2006 - less than 1%). Revenue from the two largest customers amounted to 15% of operating revenue for the year ended December 31, 2007 (2006 - 11%). With respect to counterparties for derivative financial instruments, the credit risk is managed through dealing with recognized futures exchanges or investment grade financial institutions and by maintaining credit policies, which significantly minimize overall counter party credit risk. Foreign currency rate risk The Gathering and Processing and NGL Infrastructure segments, where all sales and virtually all purchases are denominated in Canadian dollars, are not subject to foreign currency rate risk. In the Marketing business, approximately US$240,149 of sales were priced in U.S. dollars for the year ended December 31, 2007 (2006 - US$313,191). The Fund realized and recorded $930 of foreign currency loss in Marketing operating expenses for the twelve months ended December 31, 2007 (2006 - $742). A further $1,488 of unrealized foreign currency gains were recorded in Marketing operating expenses for the year ended December 31, 2007 (2006 - $784). Currency exchange risk is actively managed by using forward currency contracts and swaps. Management monitors the exposure to currency exchange risk and regularly reviews its financial instrument activities and all outstanding positions. Interest rate risk The majority of the Fund's interest rate risk is attributed to its fixed and floating rate debt, which is used to finance operations. The Fund's remaining financial instruments are not significantly exposed to interest rate risk. The floating rate debt creates exposure to interest rate cash flow risk, whereas the fixed rate debt creates exposure to interest rate price risk. At December 31, 2007, fixed rate borrowings comprised 100% of total debt outstanding (2006 - 67%). The fair value of the senior fixed rate debt at December 31, 2007 was $337,589 (2006 - $224,457) based on third party estimates. The fair value of the Fund's unsecured convertible debentures at December 31, 2007 was $32,078 (2006 - $31,782) as determined by reference to quoted market price for the Fund's debentures. 15. Commitments and contingencies The Fund, through its operating entities has assumed various contractual obligations and agreements in the normal course of its operations. The agreements range from one to eleven years and relate to the processing of a major oil and gas producer's 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 operating lease commitments relating to railway tank cars, vehicles, computer hardware, office space, terminal space and natural gas transportation. At December 31, 2007, the obligations that represent known future cash payments that are required under existing contractual arrangements are as follows: Payments Due by Period ------------------------------------------------------------------------- After Contractual Total 2008 2009 2010 2011 2012 2012 obligations $ $ $ $ $ $ $ ------------------------------------------------------------------------- Long-term debt(1) 335,000 20,000 90,000 52,500 - - 172,500 Operating leases(2) 33,845 8,749 7,926 6,359 4,964 3,915 1,932 Purchase obligations(3) - - - - - - - ------------------------------------------------------------------------- Total contractual obligations 368,845 28,749 97,926 58,859 4,964 3,915 174,432 (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, terminal lease space and natural gas transportation. (3) Keyera is involved in various contractual agreements with ConocoPhillips and other producers to purchase NGLs. These agreements range from one to eleven 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 market prices. The future volumes and prices for these contracts cannot be reasonably determined. 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. 16. Supplemental cash flow information: Changes in non-cash working capital As at December 31, 2007 2006 $ $ --------------------------------------------------------------------- Cash provided by (used in): Accounts receivable (92,743) 31,410 Inventory (22,655) (2,232) Other current assets 2,028 (285) Accounts payable and accrued liabilities 86,806 (22,999) --------------------------------------------------------------------- Changes in non-cash working capital (26,564) 5,894 --------------------------------------------------------------------- Relating to: Operating activities (25,450) 6,545 Investing activities (1,114) (651) --------------------------------------------------------------------- Other cash flow information: Interest paid 17,381 18,486 Taxes paid 1,839 4,601 17. Segmented information The Fund has three reportable segments: Marketing, Gathering and Processing and NGL Infrastructure. The Marketing business consists of marketing NGLs, natural gas, sulphur and crude oil. Gathering and Processing includes natural gas gathering and processing. NGL Infrastructure includes NGL and crude oil processing, transportation and storage. The accounting policies of the segments are the same as that described in the summary of significant accounting policies. Inter-segment sales and expenses are recorded at current market prices. Gathering and Year ended Process- NGL Infra- December 31, Marketing ing structure Corporate Total 2007 $ $ $ $ $ ------------------------------------------------------------------------- Revenue 1,250,541 191,164 71,079 - 1,512,784 Inter-segment revenue - (3,674) (29,969) - (33,643) ------------------------------------------------------------------------- External revenue 1,250,541 187,490 41,110 - 1,479,141 Operating expenses (1,205,653) (103,792) (24,253) - (1,333,698) Inter-segment expenses 33,643 - - - 33,643 ------------------------------------------------------------------------- External operating expenses (1,172,010) (103,792) (24,253) - (1,300,055) ------------------------------------------------------------------------- 78,531 83,698 16,857 - 179,086 General and administrative, interest and other - - - (42,058) (42,058) Depreciation and amortization (3,190) (28,211) (9,613) (1,026) (42,040) Accretion expense (6) (2,097) (379) - (2,482) Impairment expense - (728) - - (728) ------------------------------------------------------------------------- Earnings (loss) before income tax and non-controlling interest 75,335 52,662 6,865 (43,084) 91,778 ------------------------------------------------------------------------- Income tax (expense) recovery 987 - (4,680) (73,300) (76,993) ------------------------------------------------------------------------- Earnings (loss) before non- controlling interest 76,322 52,662 2,185 (116,384) 14,785 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Identifiable assets 256,459 782,079 270,160 22,301 1,330,999 ------------------------------------------------------------------------- Capital expenditures 550 19,585 8,150 694 28,979(1) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Total capital expenditures include $3,666 relating to the amount allocated to property, plant and equipment as a result of the acquisition of RPLP (see note 18). Gathering and Year ended Process- NGL Infra- December 31, Marketing ing structure Corporate Total 2006 $ $ $ $ $ ------------------------------------------------------------------------- Revenue 1,161,899 170,184 69,072 - 1,401,155 Inter-segment revenue - (3,448) (29,184) - (32,632) ------------------------------------------------------------------------- External revenue 1,161,899 166,736 39,888 - 1,368,523 Operating expenses (1,134,677) (96,558) (23,956) - (1,255,191) Inter-segment expenses 32,632 - - - 32,632 ------------------------------------------------------------------------- External operating expenses (1,102,045) (96,558) (23,956) - (1,222,559) ------------------------------------------------------------------------- 59,854 70,178 15,932 145,964 General and administrative, interest and other - - - (37,048) (37,048) Depreciation and amortization (3,299) (27,291) (8,653) (600) (39,843) Accretion expense (10) (1,950) (297) - (2,257) Impairment expense - (373) - - (373) ------------------------------------------------------------------------- Earnings (loss) before income tax and non-controlling interest 56,545 40,564 6,982 (37,648) 66,443 ------------------------------------------------------------------------- Income tax recovery (expense) (143) - (4,133) 6,936 2,660 ------------------------------------------------------------------------- Earnings (loss) before non- controlling interest 56,402 40,564 2,849 (30,712) 69,103 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Identifiable assets 163,826 789,843 261,649 7,694 1,223,012 ------------------------------------------------------------------------- Capital expenditures 12,040 45,498 14,573 1,757 73,868 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2007 2006 $ $ ------------------------------------------------------------------------- Marketing revenue derived from export sales to the U.S. 77,583 84,577 Property, plant and equipment located in the U.S. 11,990 11,925 ------------------------------------------------------------------------- 18. Non-controlling interest In the first quarter of 2007, a subsidiary of the Fund purchased an additional ownership interest in Rimbey Pipe Line Co. Ltd. for a purchase price of $1,513. In the second quarter of 2007, Rimbey Pipe Line Co. Ltd. was converted to a limited partnership (RPLP) and a subsidiary of the Fund acquired the remaining interest in RPLP for a purchase price of $5,203 bringing the Fund's ownership in RPLP to 100%. The difference between the fair value of the transactions and the carrying value of RPLP's net assets resulted in a difference of $3,666, which was applied to property, plant and equipment. A future tax liability and corresponding increase to goodwill was recorded in the amount of $520. As a result, the non-controlling interest has been removed from the consolidated statement of financial position. 19. Subsequent Events On January 2, 2008, the Fund completed an internal reorganization of certain of its subsidiaries. As a result of the reorganization, the Partnership is now directly owned by the Fund and KEML no longer has an interest in the Partnership. It is expected that the future income tax liability will increase by approximately $3.5 million in 2008 as a result of the higher future income tax rate applicable to the Fund. This tax rate is approximately 2.5% higher than the future income tax rate recorded by KEML. On January 2, 2008, the Fund's revolving demand facility with the Toronto Dominion Bank was increased from $10,000 to $15,000. The terms of the facility, including interest rates charged, remain unchanged. Corporate Information Board of Directors Officers E. Peter Lougheed(1)(3) Jim V. Bertram Counsel President and Chief Executive Officer Bennett Jones LLP Calgary, Alberta David G. Smith Executive Vice President, Jim V. Bertram(4) Chief Financial Officer and President and CEO Corporate Secretary Keyera Energy Management Ltd. Calgary, Alberta Marzio Isotti Vice President, Foothills Region Robert B. Catell Executive Director and Steven B. Kroeker Deputy Chairman Vice President, Corporate Development National Grid plc New York, New York Bradley W. Lock Vice President, North Central Region Michael B.C. Davies(2) Principal David A. Sentes Davies & Co. Vice President, Comptroller Banff, Alberta Nancy M. Laird(3)(4) Stock Exchange Listing Corporate Director Calgary, Alberta The Toronto Stock Exchange Trading Symbols KEY.UN; KEY.DB H. Neil Nichols(2)(3) Management Consultant Unit Trading Summary Q4 2007 Smiths Cove, Nova Scotia --------------------------------------- TSX:KEY.UN - Cdn $ William R. Stedman(3)(4) --------------------------------------- Chairman and CEO High $19.90 ENTx Capital Corporation Low $16.38 Calgary, Alberta Close December 31, 2007 $19.90 Volume 7,902,560 Wesley R. Twiss(2) Average Daily Volume 125,437 Corporate Director Calgary, Alberta Auditors Deloitte & Touche LLP (1) Chairman of the Board Chartered Accountants (2) Member of the Audit Calgary, Canada Committee (3) Member of the Compensation Investor Relations and Governance Committee Contact: (4) Member of the Health, John Cobb or Bradley White Safety and Environment Toll Free: 1-888-699-4853 Committee Direct: 403-205-7670 Email: ir@keyera.com Head Office Keyera Facilities Income Fund Suite 600, Sun Life Plaza West Tower 144 - 4th Avenue S.W. Calgary, Alberta T2P 3N4 Main phone: 403-205-8300 Website: www.keyera.com %SEDAR: 00019203E

For further information:

For further information: Keyera's Investor Relations Department at (403)
205-7670, toll free at 888-699-4853 or via email at ir@keyera.com; Information
on Keyera can also be found on our website at www.keyera.com


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