For the year ended December 31, 2006
CALGARY, Feb. 27 /CNW/ --------------------------------------------------------------------------
2006 Year-End Highlights
-------------------------------------------------------------------------
- Keyera delivered strong financial results in 2006, with net earnings
of $68.1 million, up 12% compared to 2005.
- Distributions to unitholders in 2006 totaled $86.6 million, or $1.43
per unit, 7% higher than the $1.33 per unit declared in 2005. Fourth
quarter distributions were $21.7 million, or 35.7 cents per unit.
- Distributable cash flow(1) was $99.7 million in 2006, or $1.65 per
unit, and $27.7 million (45.7 cents per unit) in the fourth quarter.
- Both Facilities segments delivered strong results in 2006. Combined
contribution from these segments was $118.7 million, up 9% from 2005.
Contribution from NGL Infrastructure was 35% higher than last year
and, despite the significant planned maintenance work, the Gathering
and Processing segment was down only slightly compared to 2005.
- Over $70 million of capital was invested in growth capital projects
in 2006, making this year the most active in Keyera's history. These
projects will underpin future growth, and the majority of them
immediately contributed to cash flow.
- Keyera is well positioned for the future, with strong performance at
year-end from the Gathering and Processing and NGL Infrastructure
segments. As well, the Marketing segment is strengthening with
improved NGL markets and continued growth in Keyera's crude oil
midstream business.
(1) See page 6 "Note Regarding Non-GAAP Financial Measures".Message to Unitholders
It gives me great pleasure to share Keyera's strong 2006 results and
provide an update on our business activities. In 2006, we focused on growing
our business through internal opportunities and completed an active
maintenance program at several facilities. I am pleased with what we have
accomplished this year and excited about what I see ahead.
In 2006 net earnings were $68.1 million, 12% higher than 2005. We
declared distributions to unitholders of $86.6 million, or $1.43 per unit, 7%
higher than the $1.33 per unit declared in 2005. Fourth quarter distributions
to unitholders were $21.7 million (35.7 cents per unit). Full year
distributable cash flow was $99.7 million, or $1.65 per unit, slightly lower
than the $1.67 per unit in 2005. Fourth quarter distributable cash flow was
$27.7 million (45.7 cents per unit), 13% higher than the 40.3 cents per unit
posted in the fourth quarter of 2005.
Our two Facilities segments had a good year with combined contribution of
$118.7 million, up 9% from 2005. The majority of this increase was in our NGL
Infrastructure business, which contributed $45.1 million, a 35% increase
compared to last year. Despite the significant planned maintenance work,
contribution from our Gathering and Processing segment was $73.6 million, only
2% lower than 2005. Our Marketing segment contributed $24.7 million this year,
down 36% from the record set last year, largely the result of tighter product
margins in the third and fourth quarters.
Fourth quarter results in our NGL Infrastructure and Gathering and
Processing business segments were particularly encouraging. Results from these
segments were up significantly as a result of increasing activity around our
facilities and cash flows from recent growth capital projects. Plant
throughput levels are up 4% compared to last year and producers are continuing
to pursue opportunities around a number of Keyera facilities. In our Marketing
segment, NGL markets firmed up at the beginning of 2007 and we continue to
grow our crude oil midstream business.
In 2006, we invested a record $71 million of growth capital in a number
of projects. These projects position us to capture new opportunities in the
future and the majority of them had an immediate impact on cash flow. The most
significant of these projects, our Caribou North Gas Gathering System and our
brine pond construction at Fort Saskatchewan, will allow us to capture new
business opportunities for many years to come. In 2007 we expect to spend
between $40 and $60 million in growth capital on projects with similar
economic characteristics.
Drilling activity in most of the areas around Keyera's facilities on the
western side of Alberta and northeastern British Columbia increased in 2006.
In B.C. and the foothills front regions, wells drilled in 2006 were 2% higher
than 2005, new records for those regions. In central Alberta, wells drilled
were 23% lower than 2005, largely due to a decline in shallow gas and coal bed
methane drilling, which was more severely affected by lower gas prices.
Longer term, we continue to believe that the Western Canadian Sedimentary
Basin will remain a key supply basin and that we are well positioned to take
advantage of the new drilling activity expected on the western side of Alberta
over the next decade. We are also strategically positioned to take advantage
of business opportunities in the Fort Saskatchewan area associated with the
significant oil sands development expected over the next 10 to 20 years.
There has been considerable speculation regarding the future of income
trusts since the Government of Canada announced a proposed tax on flow-through
entities in 2011. The Government's actions have resulted in a significant drop
in Keyera's unit price, causing economic hardship to many unitholders. I would
like to reassure unitholders that Keyera's business remains strong. While
Keyera's management continues to evaluate the implications of the tax for
Keyera, our strategy is based on a commitment to create long-term value for
our unitholders.
On behalf of the Fund's directors and management team, I thank you for
your continued support and look forward to another successful year in 2007.
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 NGL and crude oil
pipelines, terminals, processing and storage facilities in Edmonton and Fort
Saskatchewan, Alberta, one of North America's major NGL 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
most 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.-------------------------------------------------------------------------
Contribution by Operating Three months ended Twelve months ended
Segment December 31, December 31,
(in thousands of dollars) 2006 2005 2006 2005
$ $ $ $
-------------------------------------------------------------------------
Gathering and Processing(1)
Revenue 44,523 38,244 170,184 142,916
Operating expenses (22,312) (20,331) (96,558) (67,469)
-------------------------------------------------------------------------
Gathering and Processing
contribution 22,211 17,913 73,626 75,447
-------------------------------------------------------------------------
NGL Infrastructure(1)
Revenue 19,742 17,132 69,072 57,759
Operating expenses (6,099) (7,994) (23,956) (24,296)
-------------------------------------------------------------------------
NGL Infrastructure
contribution 13,643 9,138 45,116 33,463
-------------------------------------------------------------------------
Marketing(2)
Revenue 286,325 317,863 1,161,899 1,013,334
Operating expenses (284,348) (305,123) (1,134,677) (972,704)
General & administration (631) (565) (2,524) (1,871)
-------------------------------------------------------------------------
Marketing contribution 1,346 12,175 24,698 38,759
-------------------------------------------------------------------------
Total contribution 37,200 39,226 143,440 147,669
-------------------------------------------------------------------------
Other expenses(3) (19,197) (22,399) (76,997) (79,654)
-------------------------------------------------------------------------
Earnings before tax and
non-controlling interest 18,003 16,827 66,443 68,015
-------------------------------------------------------------------------
Notes:
Gathering and Processing, NGL Infrastructure and Marketing contribution,
as defined below, are not standard measures under Canadian generally
accepted accounting principles. Therefore, these measures may not be
comparable with the calculation of similar measures for other entities.
Contribution does not include the elimination of inter-co transactions as
required by GAAP and refers to operating revenues less operating expenses
(Gathering and Processing expenses, NGL Infrastructure expenses and
Marketing expenses, where applicable). Management believes contribution
provides an accurate portrayal of profitability by operating segment.
Additional disclosure regarding segment results is contained in financial
statement note 16, Segmented information.
(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.
Fourth Quarter Results
Statements of Earnings
(in thousands of dollars)
-------------------------------------------------------------------------
(unaudited)
Three months ended Twelve months ended
December 31, December 31,
2006 2005 2006 2005
$ $ $ $
-------------------------------------------------------------------------
Operating revenues
Marketing sales 286,325 317,863 1,161,899 1,013,334
Gathering and Processing 43,621 37,278 166,736 139,274
NGL Infrastructure 10,855 10,349 39,888 34,959
-------------------------------------------------------------------------
340,801 365,490 1,368,523 1,187,567
Operating expenses
Marketing cost of goods
sold 274,559 297,375 1,102,045 946,263
Gathering and Processing 22,312 20,331 96,558 67,469
NGL Infrastructure 6,099 7,994 23,956 24,296
-------------------------------------------------------------------------
302,970 325,700 1,222,559 1,038,028
-------------------------------------------------------------------------
37,831 39,790 145,964 149,539
General and administrative 3,453 8,528 18,892 25,217
Interest expense 5,153 4,146 18,156 16,213
Depreciation and
amortization 10,413 9,502 39,843 36,887
Accretion expense 809 788 2,257 2,048
Impairment expense - - 373 1,160
-------------------------------------------------------------------------
19,828 22,964 79,521 81,525
-------------------------------------------------------------------------
Earnings before tax and
non-controlling interest 18,003 16,826 66,443 68,014
Income tax (recovery)
expense 2,840 1,160 (2,660) 6,630
-------------------------------------------------------------------------
Earnings before
non-controlling interest 15,163 15,666 69,103 61,384
Non-controlling interest 235 175 1,025 704
-------------------------------------------------------------------------
Net earnings 14,928 15,491 68,078 60,680
-------------------------------------------------------------------------
Statements of Cash Flows
(in thousands of dollars)
-------------------------------------------------------------------------
(unaudited)
Three months ended Twelve months ended
December 31, December 31,
2006 2005 2006 2005
Net inflow (outflow) of cash: $ $ $ $
-------------------------------------------------------------------------
Operating activities
Net earnings 14,928 15,491 68,078 60,680
Items not affecting cash:
Depreciation and
amortization 10,413 9,502 39,843 36,887
Accretion expense 809 788 2,257 2,048
Impairment expense - - 373 1,160
Unrealized (gain) loss on
financial instruments 153 783 (491) 280
Future income tax
(recovery) expense 1,800 231 (7,042) 2,411
Non-controlling interest 235 175 1,025 704
Asset retirement obligation
expenditures (79) (78) (160) (183)
-------------------------------------------------------------------------
28,259 26,892 103,883 103,987
Changes in non-cash
operating working capital 13,871 444 6,773 (41,840)
-------------------------------------------------------------------------
42,130 27,336 110,656 62,147
-------------------------------------------------------------------------
Investing activities
Additions to property,
plant and equipment (8,138) (40,388) (73,868) (52,870)
Additions to intangibles - - (1,115) -
Proceeds on sale of assets - - - 907
Changes in non-cash
working capital 2,649 3,529 (651) 4,951
-------------------------------------------------------------------------
(5,489) (36,859) (75,634) (47,012)
-------------------------------------------------------------------------
Financing activities
Proceeds from credit
facilities (13,399) 35,000 41,984 54,000
Issuance of trust units 904 1,598 4,252 2,175
Distributions paid to
unitholders (21,724) (20,662) (86,509) (77,013)
Distributions or dividends
paid to others (240) (240) (479) (506)
-------------------------------------------------------------------------
(34,459) 15,696 (40,752) (21,344)
-------------------------------------------------------------------------
Net cash (outflow) inflow 2,182 6,173 (5,730) (6,209)
Cash (bank indebtedness),
beginning of period (2,278) (539) 5,634 11,843
-------------------------------------------------------------------------
Cash (bank indebtedness),
end of period (96) 5,634 (96) 5,634
-------------------------------------------------------------------------
-------------------------------------------------------------------------Management's Discussion and Analysis
The following management's discussion and analysis ("MD&A") was prepared
as of February 27, 2007 and is a review of the results of operations and the
liquidity and capital resources of Keyera Facilities Income Fund (the "Fund"
or "Keyera"). It should be read in conjunction with the accompanying audited
consolidated financial statements of the Fund for the year ended December 31,
2006 and the notes thereto as well as the consolidated financial statements of
the Fund for the year ended December 31, 2005 and the related management's
discussion and analysis. Additional information related to the Fund, including
the Fund's Annual Information Form, is filed on SEDAR at www.sedar.com.
NOTE REGARDING NON-GAAP FINANCIAL MEASURES
This discussion and analysis refers to certain financial measures that
are not determined in accordance with Canadian Generally Accepted Accounting
Principles ("GAAP"). These measures do not have standardized meanings and may
not be comparable to similar measures presented by other trusts or
corporations. Measures such as operating margin (operating revenues minus
operating expenses), EBITDA (earnings before interest, taxes, depreciation and
amortization) and distributable cash flow (net income adjusted for items not
affecting cash less maintenance capital expenditures, expenditures related to
asset retirement or site reclamation and the distributable cashflow
attributable to any non-controlling interest) are not standard measures under
GAAP and therefore may not be comparable with the calculation of similar
measures for other entities. Management believes that these supplemental
measures facilitate the understanding of the Fund's results of operations and
financial position. Investors are cautioned, however, that these measures
should not be construed as an alternative to net earnings determined in
accordance with GAAP as an indication of the Fund's performance.
FORWARD-LOOKING STATEMENTS
Certain statements contained in this 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. Management believes that its
assumptions and analysis are reasonable and that the expectations reflected in
the forward-looking statements contained herein are also reasonable. However,
Keyera cannot assure readers that these expectations will prove to be correct.
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 2007 Annual Information Form filed on SEDAR.
In addition, this MD&A and accompanying documents may contain forward-
looking statements attributed to third party sources. For example, the
discussion on proposed changes in trust tax legislation is based solely on the
general information found in the background paper issued by the Department of
Finance at the time of the October 31, 2006 announcement by Minister Flaherty,
the proposed "normal growth" guidelines issued by the Department of Finance on
December 15, 2006, and the draft amendments to the Tax Act released on
December 21, 2006 (collectively the "October 31 Proposals"). No assurance can
be given that any final legislation implementing the proposed tax changes will
be consistent with the October 31 Proposals or that Canadian federal income
tax law respecting income trusts and other flow-through entities will not be
further changed in a manner which adversely affects Keyera and its
Unitholders. To the extent that proposed or other changes are implemented,
such changes could result in the income tax considerations described in this
MD&A being materially different.
Readers are cautioned that they should not unduly rely on the
forward-looking statements included in this MD&A and accompanying documents.
Further, readers are cautioned that the forward-looking statements contained
herein 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
www.sedar.com.
INTRODUCTION
The statement of earnings contained in the audited consolidated financial
statements includes the results of operations of the Fund, Keyera Energy
Partnership ("the Partnership"), Keyera Energy Facilities Limited ("KEFL"),
Keyera Energy Ltd. ("KEL"), Keyera Energy Management Ltd. ("KEML"), Keyera
Energy Inc. ("KEI") and Rimbey Pipe Line Co. Ltd. ("Rimbey Pipe Line") for the
twelve months ended December 31, 2006. The Fund and its subsidiaries are
collectively referred to as "Keyera". The information for the comparative
twelve months ended December 31, 2005 includes the results of operations of
the Fund, the Partnership, KEFL, KEL, KEML, KEI, EnerPro Midstream Company
("EnerPro") and Rimbey Pipe Line for the twelve months ended December 31,
2005. A diagram of Keyera's organizational structure and descriptions of the
Fund and its subsidiaries can be found in the Fund's 2007 Annual Information
Form which is available at www.sedar.com.
BUSINESS ENVIRONMENT
Canada experienced another active year of oil and gas drilling in 2006,
with 23,441 wells drilled during the year. Although drilling levels overall
were 6% lower than last year, in the foothills front and British Columbia
regions, where most of Keyera's facilities are located, the number of wells
drilled increased by 2% compared to last year, setting new records for these
areas.
Low natural gas prices in 2006 affected some producer drilling programs
during the year, particularly in the central and eastern side of the Western
Canadian Sedimentary Basin ("WCSB"). In the central Alberta region, where
Keyera has operations, drilling of natural gas wells decreased 23% compared to
2005, largely the result of a curtailment of shallow gas and coal bed methane
drilling. The average depth of wells drilled in the central Alberta region
increased by 10% in 2006, as producers continued to target deeper reservoirs.
Keyera was not significantly affected in 2006 by the drilling slowdown in this
area, as gas from shallow sweet wells does not contribute significantly to
Keyera's cash flow.
Over the long-term, natural gas fundamentals are expected to support an
active drilling program in the WCSB. This is particularly true on the western
side of the basin. This area is relatively under-developed, has more gas prone
zones at deeper depths and often has larger reserves containing hydrogen
sulphide and natural gas liquids ("NGLs"). The majority of Keyera's facilities
are able to process both sweet and sour gas and extract NGLs from the raw gas
stream, making them well-suited to process gas from this region.
The high levels of activity around Keyera's facilities over the last
several years have resulted in a material amount of natural gas being
discovered but, for a variety of reasons, production to date from these
discoveries has been limited. Producers in several areas have initiated
drilling programs and production from these sources is expected to come on
stream in 2007.
The expected increases in bitumen and heavy oil production from
northeastern Alberta over the next 10 to 20 years are expected to increase the
demand for condensate, for use as diluent in heavy oil transportation, as well
as generate opportunities to provide storage and logistics services in the
Fort Saskatchewan area. Keyera's facilities in Edmonton and Fort Saskatchewan
experienced increased demand for these products and services during 2006, and
are well positioned to provide additional services over the longer term as the
oil sands sector evolves.
On October 31, 2006, the Government of Canada announced a new tax on a
portion of the distributions of publicly-traded Canadian income trusts and
limited partnerships. Assuming legislation is passed to enact this new tax,
Keyera, as an existing income trust, will be subject to the new tax as of
January 2011. Details of the Government's proposed changes can be found in the
Government's website at http://www.fin.gc.ca/news06/06-061e.html.
According to the announcement, effective January 1, 2011 a tax of 31.5%
will be payable by Keyera on the portion of its distributions that is ordinary
taxable income. For a Canadian resident taxpayer, this portion of Keyera's
distributions will be treated as dividend income for tax purposes. The
announcement also indicates that there will be no change in taxation of
Keyera's distributions that are considered to be a return of capital or
dividend income.
If enacted as proposed, the taxation of Keyera commencing in 2011 will
depend upon the composition of its distributions. The composition of the
distributions will vary depending upon levels of profitability, capital
expenditures and other factors.
As at January 1, 2006, Keyera had over $375 million of unutilized tax
pools and deductions, consisting mostly of class 41 undepreciated capital
costs, available for deduction by the Fund's subsidiaries. Keyera's practice
has been to minimize taxes payable by the Fund and its subsidiaries. Keyera is
reviewing the implications of the government's announcement and, should the
proposed tax changes become law, Keyera will continue to adopt strategies that
are intended to enhance long-term value.
PRODUCTIVE CAPACITY
Keyera's Gathering and Processing segment has interests in 16 gas
processing plants in Western Canada with 1,663 million cubic feet per day
("mmcf/d") of licensed gross raw gas processing capacity (1,328 mmcf/d net),
of which an average of 819 mmcf/d was utilized in 2006. Actual available raw
gas processing capacity can be less than the licensed capacity, particularly
if current gas composition or plant operating conditions are significantly
different than the original plant design. Each plant has a number of
functional units, each of which performs one or more operations, such as NGL
recovery, gas treating and sulphur recovery. The constraint on actual
available capacity depends on the capacity of each functional unit at each
plant. Additional information on the capacities and constraints for Keyera's
plants is provided in Keyera's 2007 Annual Information Form, which is
available on SEDAR.
Associated with these gas plants, Keyera owns interests in over
2,500 kilometres of four to twelve inch diameter raw gas gathering pipelines
that deliver raw gas to the gas plants for processing.
Keyera also owns an integrated NGL infrastructure consisting of
pipelines, processing, storage, and rail and truck loading facilities in
Edmonton and Fort Saskatchewan, Alberta. Keyera has a total net NGL processing
capacity of 65,170 bbls/d and net storage capacity of 7 million barrels.
Several of Keyera's sour gas plants rely on acid gas injection to dispose
of the hydrogen sulphide and 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 particular process is dependent upon the availability of suitable
reservoirs. Keyera routinely monitors its existing reservoirs at the Brazeau
River, West Pembina, Bigoray, Caribou and Paddle River gas plants to determine
whether sufficient capacity remains available. If capacity were to become
unavailable, alternate processes would be required or the capacity of the
plant would be reduced.
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. In 2006 Keyera and its partners spent $31.0 million to maintain the
productive capacity of its facilities, $26.5 million of which was expensed and
$4.5 million capitalized. Keyera's net share of these expenditures was
$22.5 million, $19.5 million of which was expensed and $3.0 million of which
was capitalized. In 2007, Keyera's net share of expenditures related to the
maintenance of productive capacity (both capitalized and expensed) is expected
to be between $27 million and $33 million. A large portion of these
maintenance costs will be recovered through the fee structure at each plant in
2007. With ongoing maintenance and repair, it is anticipated that Keyera's
plants and facilities can continue to operate safely for decades to come.
RESULTS OF OPERATIONS
Keyera's midstream activities are conducted through three business
segments. The Gathering and Processing segment provides natural gas gathering
and processing services to producers. The NGL Infrastructure segment provides
NGL processing, transportation and storage services to producers, marketers
(including Keyera) and others. 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 Fund's 2007 Annual
Information Form, which is available at www.sedar.com.
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
weakening product prices.
Consolidated net earnings for the fourth quarter of 2006 were
$14.9 million, down $0.6 million from the same period in 2005. The strong
operating margin earned from the Gathering and Processing and NGL
Infrastructure segments largely mitigated the weaker results seen in the
Marketing segment. Significantly lower general and administrative costs
partially offset by higher interest, depreciation and income taxes also
mitigated the effect of the lower Marketing results.
Gathering and Processing
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 in the West Central Region; increased sour 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.
In the fourth quarter of 2006, Gathering and Processing revenue was
$43.6 million, an increase of $6.3 million, or 17%, compared to the same
period in 2005. The increase was due primarily to higher throughput at the
Brazeau River, Caribou and Gilby plants. At Caribou and Gilby the increase in
volumes was attributable to the completion of new gathering systems earlier in
the year and the plant expansion undertaken at Caribou. The Brazeau River
plant also saw higher acid gas injection volumes and higher fees from firm
commitment contracts and to recover maintenance costs incurred earlier in the
year. Also contributing to growth was the incremental ownership interest in
the Strachan gas plant.
Gathering and Processing operating expenses were $96.6 million, an
increase of $29.1 million, or 43%, compared to previous year. Approximately
$21.1 million of this increase was attributable to the turnarounds conducted
at the Caribou, Chinchaga and Strachan gas plants and the substantial amount
of additional maintenance work to refurbish the sulphur handling facilities at
the Strachan gas plant. This work positioned the plant to provide increased
sour gas processing capability in a safe, reliable and environmentally
responsible manner. The remainder of the increase was due to increased
operating costs resulting from the higher throughput in the West Central
region and compressor repairs at the Brazeau River plant.
In the fourth quarter of 2006, Gathering and Processing operating
expenses were $22.3 million, an increase of $2.0 million compared to the same
period in 2005. The increase was due to higher volumes and activity levels at
the Brazeau River and Caribou gas plants.
Much of the revenue from the Gathering and Processing segment is
generated on a cost-of-service basis. On a percentage basis, the increase in
operating costs was higher than the increase in revenue, primarily due to
timing differences that occur as a result of the cost-of-service fee
structure. At the Strachan gas plant, where the most significant maintenance
and turnaround activities occurred, costs are recovered over a four year
period. At the Caribou plant, many of the contractual arrangements are on a
fixed-fee basis where certain costs incurred in the year are not directly
recoverable.
Average gross processing throughput in 2006 was 819 million cubic feet
per day, 4% higher than 2005. Fourth quarter throughput of 808 million cubic
feet per day was up 1% from the same period last year.
Gathering and Processing - West Central Region
The West Central Region continued to deliver strong performance in 2006,
increasing cash flows and executing a number of growth initiatives. Annual raw
gas throughput for the region increased 5% compared to 2005. Fourth quarter
throughput in the region was virtually unchanged from the same period a year
ago.
In the Rimbey area, a number of initiatives were completed in 2006 which
provide Keyera with greater control over its gathering pipelines and enhance
its ability to deliver raw gas to the Rimbey gas plant. For example, Keyera
acquired additional ownership interests in the Medicine River and Gull Lake
pipelines, bringing its ownership to 87% and 100% respectively. These
pipelines capture raw gas from areas currently experiencing active drilling
programs for delivery to the Rimbey gas plant.
Inlet compression was added at the Rimbey gas plant during the year to
accommodate additional volumes. These projects enable the pipelines to operate
at lower operating pressures, which allows more low pressure gas wells to
deliver gas to the plant.
In April 2006, Keyera completed the construction of the 20-kilometre
Aurora pipeline. Upon completion, the pipeline immediately began delivering
incremental raw gas to the Gilby gas plant from an active area west of the
plant.
Producer activity in the area near Keyera's Brazeau North, West Pembina
and Bigoray plants progressed at high levels in 2006. Piping and compression
modifications were completed during the year at the Brazeau North and West
Pembina gas plants, which provided increased inlet capabilities and resulted
in an incremental 5 million cubic feet per day of raw gas throughput at those
facilities. In the fourth quarter, work continued on the conversion of an out-
of-service sales pipeline into an additional gathering pipeline for the
Bigoray gas plant.
In 2007, maintenance turnarounds will be completed at the Rimbey,
Bigoray, Brazeau North and Medicine River gas plants. With the exception of
the Rimbey gas plant, where maintenance costs are recovered over a four year
period, the majority of these costs will be recovered in 2007.
Gathering and Processing - Foothills Region
In the Foothills region, drilling activity near Keyera's facilities
continued during the year and 2006 throughput for the region was up 4% over
2005. Fourth quarter throughput was also up 4% from the same quarter in 2005.
The Strachan gas plant underwent extensive work during 2006 in order to
prepare for incremental sour gas volumes over the next several years. During
the second quarter, Strachan's scheduled maintenance shutdown was completed,
with necessary inspections, routine repairs and numerous modifications being
performed. The "A" sulphur plant was also refurbished to enable both the "A"
and "B" sulphur plants to process sour gas volumes from the Tay River
discovery south of the plant. Pipeline modifications began in the fourth
quarter to accommodate the water associated with the increased raw gas
volumes. Keyera expects these modifications to be completed in the first
quarter of 2007. In February 2007, deliveries of gas from the Tay River
discovery increased to rates exceeding 50 million cubic feet per day. At these
throughput levels, Strachan's sulphur handling facilities were operating near
their capacity.
The 48-kilometre Caribou North Gas Gathering System was completed in
2006, extending the capture area of the Caribou gas plant to the north. The
pipeline opened a 1,000 square kilometer area which lacked gathering and
processing infrastructure. To accommodate expected incremental volumes from
the area, the Caribou gas plant was expanded in June from 40 to 65 million
cubic feet per day while the plant was off-line for its scheduled maintenance
shutdown. Two producer-owned compressor sites were connected to the pipeline
in the second half of the year. A third producer-owned compressor site began
delivering new volumes into the gathering system in January 2007. Several
producers currently have drilling programs underway along the pipeline.
In the Pembina area, activity continued during the year on the Nisku oil
play and three producer-owned batteries became operational. Regulatory and
operational issues at these batteries resulted in lower than expected volumes
at the Brazeau River gas plant during the year. Volumes increased during the
fourth quarter and this trend has continued through the first two months of
2007. As a result, the sour gas handling facilities at the Brazeau River gas
plant have been operating at or near capacity. During the third and fourth
quarters of 2006, a number of processing agreements were put in place which
secure processing capacity for producers and processing revenues for Keyera.
The Chinchaga gas plant was off-line during the third quarter of 2006 to
perform its scheduled maintenance turnaround. In 2007, the Brazeau River gas
plant will undergo its scheduled maintenance turnaround and these costs will
be fully recovered in 2007.
NGL Infrastructure
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.
NGL Infrastructure operating expenses for 2006 were $24.0 million, a
decrease of $0.3 million or 1% compared to 2005. Lower fuel gas and
electricity costs throughout most of the year accounted for the decrease.
In the third quarter, Keyera completed construction of a 3.9 million
barrel brine pond at the Fort Saskatchewan processing and storage facility.
This brine pond enables a better utilization of the existing underground
storage at Fort Saskatchewan and will allow Keyera to take advantage of the
increasing long-term demand for condensate and butane storage. In anticipation
of the completion of the brine pond, Keyera entered into multi-year storage
contracts. These contracts, together with other shorter term arrangements,
resulted in an increase in storage revenues in 2006.
Also, in the third quarter of 2006, Keyera completed the construction of
an expansion to the rail rack facility at the Edmonton terminal. The expansion
allows the offloading of up to 10,000 barrels per day of condensate, intended
to supply the diluent market in Alberta.
In the fourth quarter of 2006, NGL Infrastructure results were up
significantly from the same period in 2005. Operating margin for the fourth
quarter of 2006 was $4.8 million, an increase of $2.4 million compared to last
year. At the Fort Saskatchewan fractionation facility, lower fuel and
electricity costs contributed to significantly lower operating expenses, while
revenues showed a modest increase. The Edmonton terminal had an active fourth
quarter, as propane was withdrawn from storage and delivered, via rail and
truck, to markets throughout North America.
Marketing
Marketing revenue for 2006 was $1,162 million, an increase of
$148.6 million compared to the previous year. 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 of and the 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.
The tables below outline the composition of the revenues generated from
Keyera's Marketing business and the changes in the fair value of the
derivative financial contracts.Composition of Marketing Revenue
(in thousands of dollars) 2006
-------------------------------------------------------------------------
Physical sales 1,154,853
Financial instruments 7,046
-------------------------------------------------------------------------
Marketing revenue 1,161,899
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Changes in Fair Value of Energy Derivative Contracts
(in thousands of dollars)
-------------------------------------------------------------------------
Fair value at December 31, 2005 (280)
Change in the fair value of contracts 6,835
Fair value of new contracts entered into in 2006 211
Realized gains (6,555)
-------------------------------------------------------------------------
Fair value at December 31, 2006(1) 211
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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, 2006.NGL sales volumes for 2006 averaged 52,200 barrels per day compared to
50,700 barrels per day in 2005, as all products experienced modest growth. In
the fourth quarter of 2006, NGL sales volumes averaged 55,400 barrels per day
compared to 55,000 barrels per day in the fourth quarter of 2005.
The cost of goods sold for 2006 was $1,102 million, an increase of
$155.8 million compared to the previous year. The increase was due primarily
to the inclusion of crude oil midstream costs and higher NGL sales volumes and
supply costs compared to 2005. Also included in the cost of goods sold was
$3.2 million related to inventory writedowns, $2.2 million in the third
quarter and $1.0 million at year end. These writedowns were required as a
result of the significant price drop in crude oil and product prices in the
third and fourth quarters of 2006.
NGL product inventories of $53.9 million were $0.7 million higher than
the previous year due to higher volumes partially offset by lower prices at
year end. A significant portion of this inventory was sold in early 2007.
Inventory has been valued at the lower of cost or net realizable value at
December 31, 2006.
Propane demand followed normal season trends in 2006. Despite warmer than
usual weather throughout most of North America during the fourth quarter,
Keyera was able to utilize its infrastructure and marketing and logistics
expertise to access niche markets where unseasonable weather created higher
demand.
Demand for butane was relatively strong for the first three quarters of
the year. Butane is required to support western Canadian crude oil production
and for use in winter gasoline blending. During the fourth quarter,
operational problems at a large industrial facility resulted in decreased
demand and lower prices for butane in the Edmonton market. During this time,
Keyera placed product into storage at its facilities in Fort Saskatchewan.
During the first half of 2006, condensate demand was strong as heavy oil
producers continued to purchase condensate for use as diluent to enable heavy
crude oil to flow in pipelines. Beginning in the third quarter, condensate
demand and prices weakened significantly in part due to falling crude oil
prices, an outage at a major heavy oil field in Alberta, and an increase in
the supply of diluent in Alberta. This combination resulted in losses on the
physical sale of condensate and a writedown of inventory values.
Marketing operating margins in the fourth quarter of 2006 were
$11.8 million, down $8.7 million from the same period in 2005. Warm weather in
the eastern U.S. contributed to lower propane prices, while butane and
condensate markets also remained soft. As well, adjustments relating to the
voidance of a butane cavern in the fourth quarter reduced margins by $0.8
million. However, by year end, the supply/demand fundamentals for propane,
butane and condensate began improving and the market demand for these products
is currently at more typical levels.
In the second quarter of 2006 Keyera acquired three propane terminals in
the U.S. to expand its NGL marketing business in key propane markets. This
acquisition allowed Keyera to vertically integrate its business, diversify its
geographic markets and expand its wholesale customer base. During the last
half of 2006, these terminals played a key role in delivering propane into the
Pacific Northwest, which was experiencing unseasonably cold weather.
Keyera's crude oil midstream business continued to develop in 2006.
Volumes delivered to field oil terminals remained steady and quality
differentials were strong throughout the year, enabling the business to
contribute approximately $8.5 million to operating margins. The midstream
joint venture project that was initiated with Pembina Pipeline Corporation
("Pembina") at the Edmonton terminal in late 2005 contributed a significant
portion of the operating margin in 2006. Another similar project was
undertaken with Pembina in 2006 and construction of the required facilities
was completed by year end. The new facilities were commissioned in early
January 2007.
Non-operating expenses and other earnings
General and administrative expenses for 2006 were $18.9 million, down
$6.3 million from the previous year. Long-term incentive plan costs were
$7.6 million lower than in 2005, reflecting a decline in unit price and no
change in distributions per unit. Excluding the effect of the long-term
incentive plan, general and administrative expenses increased $1.3 million
compared to the previous year. Severance costs and higher legal and consulting
costs were primarily responsible for the increase. Severance costs were
incurred in accordance with an employment agreement.
Interest expense, net of interest revenue, was $18.2 million for 2006,
$1.9 million greater than in 2005. The increase was due to the higher short
term borrowings used to fund capital projects, partially offset by a reduction
in interest paid on lower convertible debenture balances.
Depreciation and amortization expense was $39.8 million for 2006,
$3.0 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 year.
Income tax recovery for 2006 was $2.7 million, compared to an expense of
$6.6 million in the previous year. The reduction in tax expense was due to a
decrease in future tax liabilities attributable to the lowering of statutory
income tax rates and the recognition of the long-term incentive plan costs as
a future tax asset. The plan costs became eligible for deduction from taxable
income in future years when Keyera began purchasing units in the market for
delivery under the plan. The deductibility of future unit purchase costs
created a tax asset. Current income tax expense, primarily attributable to
Rimbey Pipe Line, was $4.4 million, up slightly from the previous year.
On October 31, 2006 the federal government announced its intention to
impose a new tax on distributions from existing public income trusts effective
in 2011. Legislation to implement the proposed tax has been released for
comment but has not been enacted, and the accounting guidance for future
income taxes in flow-through entities has not been finalized. However, if the
new legislation is put into effect, it is estimated that the Fund's future
income tax liability may increase, with a corresponding decrease to net income
in the period when the legislation is substantively enacted.
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, 2006, operating revenues and accounts receivable for the
Gathering and Processing and NGL Infrastructure segments contained an estimate
of $19.5 million for December 2006 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, 2006, operating expenses and accounts payable contained
an estimate of $10.0 million for December 2006 operations.
Estimation of Gathering and Processing and NGL Infrastructure
equalization adjustments:
Much of the revenue from the Gathering and Processing and NGL
Infrastructure assets is generated on a cost-of-service basis. Under this
method, the operating component of the fee is a pro rata share of the
operating costs for the facility, calculated based upon total throughput.
Users of each facility are charged a fee per unit based upon estimated costs
and throughput, with an adjustment to actual 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 $6.4 million at December 31, 2006. Operating expenses and
accounts payable contained an estimate of $3.4 million.
Estimation of Marketing revenues:
The majority of the Marketing sales revenues are 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, 2006, the Marketing sales and accounts receivable
contained an estimate for December 2006 revenues of $43.6 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 $77.2 million at December 31, 2006.
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 life. 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, 2006, the total undiscounted
amount required to settle the asset retirement obligations is $183.2 million
compared to $168.2 million at December 31, 2005. The discounted net present
value of this obligation at December 31, 2006 is $34.5 million compared to
$27.8 million at December 31, 2005. The increase in the undiscounted and the
discounted amount is primarily due to changes in the estimated future
liabilities.
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 2007 Annual Information Form, which
is available on SEDAR.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity and working capital
Cash provided by operating activities before changes in non-cash
operating working capital was $103.9 million during 2006. The Fund paid
$87.0 million of distributions and dividends during the year and required
$68.9 million for capital expenditures, additions to intangibles, inventory
and other non-cash working capital. The resulting cash requirement of
$52.0 million was funded by $42.1 million of short-term debt, $4.3 million of
proceeds from the Distribution Reinvestment Plan ("DRIP") and $5.6 million of
internal cash.
A deficiency of $41.1 million in cash and working capital existed at
December 31, 2006 compared to a surplus of $9.7 million last year. The
decrease in working capital resulted from the use of short-term debt to
finance growth capital expenditures.Twelve months ended
Additions to Property, Plant and Equipment December 31
(in millions of dollars) 2006 2005
-------------------------------------------------------------------------
Growth capital expenditures 70.9 48.4
Maintenance capital expenditures 3.0 4.5
-------------------------------------------------------------------------
Total capital expenditures 73.9 52.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------In 2006, additions to property, plant and equipment amounted to
$73.9 million, consisting of $3.0 million of maintenance capital and
$70.9 million of growth capital. The maintenance capital expenditures were
related to numerous small projects. In addition to maintenance capital
expenditures, Keyera incurred maintenance and repair expenses of $19.5 million
that are included in operating costs. In 2007, Keyera expects to spend
approximately $3 to $5 million for maintenance capital projects. In addition,
it is anticipated that Keyera will spend between $24 and $28 million for
expensed maintenance work.
Keyera's capital program was largely directed at opportunities identified
from its existing asset base. The construction projects extended capture
areas, expanded capacities and introduced new services at existing plants and
facilities. In general, Keyera's engineering team was able to complete these
projects on time and on budget, during a year when engineering, procurement
and construction challenges were common.
Growth was also achieved through acquisition. Keyera acquired three
propane terminals in the United States to expand and vertically integrate its
existing NGL marketing business and acquired incremental ownership interests
in two pipelines to increase our future share of operating results.The following were the significant 2006 growth capital expenditures:
- $21.8 million to construct the Caribou North Gas Gathering System and
the Aurora pipeline which have extended the capture areas of the
plants.
- $12.0 million to acquire storage and terminal facilities in the U.S.
- $13.7 million for plant process improvements, the addition of new
compression facilities and the acquisition of incremental ownership
interests in the Rimbey Gull Lake pipeline and the Medicine River
pipeline.
- $7.6 million to construct the rail facility expansion at the Edmonton
terminal to enable the delivery of incremental condensate volumes.
- $4.1 million to complete the Fort Saskatchewan brine pond expansion,
to increase the utilization of the underground storage caverns.
- $1.6 million to upgrade the amine and control systems at the Caribou
gas plant, increasing plant capacity by 25 million cubic feet per
day.The expected growth capital expenditures for 2007 are between $40 and
$60 million, but the actual level of growth capital investment is dependent
upon available opportunities.
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 $81 million. In addition to the working
capital required for inventory, Keyera typically utilizes approximately $25 to
$35 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 WCSB and have high barriers to entry for new competitors.
Keyera's cash flows may also be adversely affected by the occurrence of
common hazards 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.
For a further discussion of the risks identified in this MD&A, other
risks and trends that could affect the financial 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 to Keyera's 2007 Annual Information Form,
which is 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 2007 capital expenditures and distributions to
be funded by cash flow from operations and borrowing on available debt
facilities.
Debt Covenants
In order for Keyera to manage seasonal fluctuations in cash flow and
working capital, fund growth capital expenditures and stabilize distributions,
if required, Keyera has established credit facilities consisting of a
$150 million revolving term facility that matures on April 21, 2009 and
$25 million of revolving demand facilities. As at December 31, 2006, $101
million was drawn under these credit facilities. Management expects that, upon
maturity of these facilities, adequate replacement facilities will be
established.
These credit facilities are 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 this agreement provide for the deduction of net working capital
in the calculation of debt. Following are the ratios as calculated in
accordance with the covenants as at December 31, 2006:-------------------------------------------------------------------------
Covenant Position as at December 31, 2006
-------------------------------------------------------------------------
Debt to EBITDA not to exceed 3.50 2.18
-------------------------------------------------------------------------
Debt to Capitalization not to exceed 0.55 0.26
-------------------------------------------------------------------------Keyera has $215 million of unsecured senior notes. Of that amount,
$20 million matures in August 2008 and bears interest at 5.42%, $90 million
matures in October 2009 and bears interest at 5.23%, $52.5 million matures in
August 2010 and bears interest at 5.79%, and $52.5 million matures in August
2013 and bears interest at 6.16%. These notes are subject to three major
financial covenants: Debt to EBITDA, EBITDA to Interest Charges and Priority
Debt to Total Assets. The calculations for each of these ratios are based on
specified definitions. Following are the ratios as calculated in accordance
with the covenants as at December 31, 2006:-------------------------------------------------------------------------
Covenant Position as at December 31, 2006
-------------------------------------------------------------------------
Debt to EBITDA not to exceed 3.50 2.81
-------------------------------------------------------------------------
EBITDA to interest charges not less than 3.00 9.38
-------------------------------------------------------------------------
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.
Also, a subsidiary of the Partnership has an unsecured revolving credit
facility in the amount of $7 million. As at December 31, 2006, $7 million had
been drawn under this credit facility. Management expects that upon maturity
of these facilities, adequate replacement facilities will be established.
Regulatory risk
On October 31, 2006 the Government of Canada announced a new tax on a
portion of the distributions of publicly-traded Canadian income trusts and
limited partnerships. The effects of this proposed tax on Keyera are discussed
in the Business Environment section of this management's discussion and
analysis. A more complete discussion of regulatory risks can be found in
Keyera's 2007 Annual Information Form, available on SEDAR.
Credit risk
Credit risk is the risk of loss resulting from non-performance of
contractual 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, 2006, the accounts receivable
from Keyera's two largest customers accounted for less than 1% of accounts
receivable (2005 - less than 1%).
With respect to counterparties for financial instruments used for
economic hedging purposes, Keyera limits its credit risk through dealing with
recognized futures exchanges or investment grade financial institutions and by
maintaining credit policies which significantly minimize overall counterparty
credit risk.
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 volatility 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 can lessen certain 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 product
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 risk associated with these
activities. If Keyera hedges its commodity price exposure, it may also forego
the benefits that may otherwise be experienced if commodity prices were to
increase. 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
59% of 2006 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$313.2 million of sales
were priced in U.S. dollars in 2006.
Commitments
Keyera has assumed various contractual obligations in the normal course
of its operations. At December 31, 2006, the obligations that represent known
future cash payments that are required under existing contractual arrangements
are as follows:Contractual obligations Payments Due by Period
(in thousands of dollars)
-------------------------------------------------------------------------
2 - 3 4 - 5 After
Total 1 Year Years Years 5 Years
-------------------------------------------------------------------------
Long-term debt(1) 215,000 - 110,000 52,500 52,500
Capital lease obligations - - - - -
Operating leases(2) 31,197 8,480 13,046 6,171 3,500
Purchase obligations(3) - - - - -
-------------------------------------------------------------------------
Total contractual
obligations 246,197 8,480 123,046 58,671 56,000
(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 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 twelve years and in general obligate Keyera to
purchase all product produced at specified locations on a best
efforts basis. The purchase prices are based on then current period
market prices. The future volumes and prices for these contracts
cannot be reasonably determined.Control Environment
Disclosure Controls and Procedures
As of December 31, 2006, 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, 2006, 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, 2006, there have been no material changes in internal control
over financial reporting.
Unitholder Distributions
Keyera pays distributions to unitholders from its distributable cash
flow. The Fund declared $86.6 million of distributions to unitholders in 2006.
The Fund's distributable cash flow of $99.7 million was sufficient to fund all
the distributions made to unitholders. In determining the level of
distributions to unitholders, the Board of Directors takes into consideration
current and expected future levels of cash flow, growth capital expenditures,
debt repayments, working capital requirements and other factors.
The following table presents the calculation of "distributable cash flow"
for the Fund. Keyera management believes that the distributable cash flow is
an appropriate measure of the Fund's cash flow available for distribution to
Unitholders. Because distributable cash flow is a non GAAP measure, it may not
be comparable to similar measures reported by other business entities.
Therefore, when assessing Keyera's performance relative to other entities,
"cash flow from operating activities" as presented in the Fund's Consolidated
Statements of Cash Flows may be a more comparable measure.Distributable Cash Flow
(in thousands of dollars) Three months ended Twelve months ended
(unaudited) December 31, December 31,
2006 2005 2006 2005
$ $ $ $
-------------------------------------------------------------------------
Net earnings 14,928 15,491 68,078 60,680
Add (deduct):
Depreciation and amortization 10,413 9,502 39,843 36,887
Accretion expense 809 788 2,257 2,048
Impairment expense - - 373 1,160
Unrealized (gain) loss on
financial instruments 153 783 (491) 280
Future income tax
(recovery) expense 1,800 231 (7,042) 2,411
Non-controlling interest 235 175 1,025 704
Asset retirement obligation
expenditures (79) (78) (160) (183)
Maintenance capital (288) (2,902) (3,011) (4,472)
Non-controlling interest
distributable cash flow (285) (188) (1,153) (782)
-------------------------------------------------------------------------
Distributable cash flow 27,686 23,802 99,719 98,733
-------------------------------------------------------------------------
Distributions to unitholders 21,742 21,062 86,605 78,541The business of the Fund is subject to operational and commercial risks
that could adversely affect future operating results, earnings, cash flow and
distributions to unitholders. These risks include declines in throughput,
operational problems and hazards, cost overruns, increased competition,
regulatory intervention, environmental considerations, uncertainty of
abandonment costs and dependence upon key personnel. These risks are
identified and discussed in greater detail in the most recent Annual
Information Form available on www.sedar.com as well as in the "Business
Environment", "Results of Operations - Marketing" and "Liquidity and Capital
Resources" sections of this MD&A.
Standard and Poor's has assigned the Fund an SR-3 stability rating,
indicating the expectation of a high level of stability in distributions.
Units and Convertible Debentures
During 2006, $7.2 million of convertible debentures (before adjustment
for deferred financing costs) were converted into 597,563 trust units and
207,997 trust units were issued under the DRIP in consideration of
$4.3 million, bringing the total units outstanding at December 31, 2006 to
60,930,753. Convertible debentures outstanding at year end were $23.5 million.
Subsequent to December 31, 2006, a further $0.2 million of convertible
debentures were converted into 20,664 trust units, and 33,021 trust units were
issued to unitholders enrolled in the DRIP in consideration for $0.5 million,
bringing the total units outstanding at February 23, 2007 to 60,984,438.
Convertible debentures outstanding at February 23, 2007 were $23.3 million,
which if converted would add 1,941,166 trust units to those outstanding.
NEW ACCOUNTING PRONOUNCEMENTS
Financial Instruments
In 2005, the CICA issued the following sections in order to increase
harmonization with U.S and International accounting standards:- 1530, Comprehensive Income;
- 3251, Equity;
- 3855, Financial Instruments - Recognition and Measurement; and
- 3865, Hedges.Effective January 1, 2007, the Trust will be adopting these new
standards. All financial assets will be measured at fair value, with the
exception of accounts receivable, which will be measured at cost. All
financial liabilities, including derivatives, will be measured at fair value
when they are classified as held for trading. The new standards expand the
definition of derivatives to include both financial and non-financial
contracts. Non-financial contracts would include an agreement to buy or sell a
commodity for a fixed price at a future date.
Gains and losses on financial instruments measured at fair value will be
recognized in net income in the periods they arise.
Section 3865, Hedges, addresses how hedge accounting is to be performed
and requires all gains and losses relating to ineffective hedges to be
recorded in net income immediately. Unrealized gains and losses relating to
effective cash flow hedges are recognized in "other comprehensive income".
As of January 1, 2007, Keyera will determine the fair value of the
existing natural gas and electricity hedge contracts, as well as the fair
value of all fixed price commodity contracts not previously recognized. On
January 1, 2007, Keyera recorded $1.0 million as an asset held for trading and
$0.1 million as a liability held for trading to recognize the fair values of
these contracts. A corresponding adjustment will be made to opening retained
earnings. Subsequent changes in the fair value of the positions will be
recorded in net income.
Convergence of Canadian GAAP with International Financial Reporting
Standards
In 2006, Canada's Accounting Standards Board ratified a strategic plan
that will result in Canadian GAAP, as used by public companies, being
converged with International Financial Reporting Standards over a transitional
period. The Accounting Standards Board is expected to develop and publish a
detailed implementation plan with a transition period expected to be
approximately five years. This convergence initiative is in its early stages
as of the date of these annual consolidated financial statements. Accordingly,
it would be premature to assess the impact of the initiative, if any, on
Keyera at this time.SELECTED FINANCIAL INFORMATION
The following table presents selected annual financial information for
the Fund:
(in thousands of dollars, except per unit information)
-------------------------------------------------------------------------
2004 2005 2006
-------------------------------------------------------------------------
Operating revenues:
- Marketing 631,696 1,013,334 1,161,899
- Facilities(1) (Gathering and
Processing and NGL Infrastructure) 112,906 174,233 206,624
Net earnings 22,738 60,680 68,078
Net earnings per unit ($/unit):
- Basic 0.63 1.03 1.12
- Diluted 0.55 0.96 1.10
Distributions to unitholders 42,037 78,541 86,605
Distributions to unitholders
per unit ($/unit) 1.16 1.33 1.43
Trust Units outstanding (thousands)
- Weighted average (basic) 36,199 58,947 60,604
- Weighted average (diluted) 40,941 63,075 62,794
Total assets 1,146,757 1,218,160 1,223,012
Total long-term financial liabilities 371,000 345,955 338,499
-------------------------------------------------------------------------
(1) For 2004, revenue from the facilities segment includes $598 of equity
earnings relating to Rimbey Pipe Line.2006 compared to 2005
For 2006 revenues from Marketing were $1,162 million, an increase of
$148.6 million compared to the previous year. 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 in the West Central Region, 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 prices.
The Fund declared $86.6 million of distributions to unitholders in 2006,
an increase of $8.1 million. The increase was due to a higher number of units
outstanding as a result of conversions of debentures, the DRIP and higher
average distributions per unit in 2006.
2005 compared to 2004
For 2005, revenues from Marketing were $1,013 million, up $381.6 million
compared to 2004. Approximately $169.0 million of this increase was due to the
consolidation of the Partnership beginning on April 1, 2004. The remainder of
the increase was largely due to higher sales volumes and historically high
commodity prices.
Revenues from facilities were $174.2 million, up $61.3 million compared
to 2004. Approximately $28.4 million of this increase was attributable to the
inclusion of revenue from the Partnership and Rimbey Pipe Line, which were not
consolidated until April 1, 2004 and July 2, 2004 respectively. The remainder
of the increase was largely due to the inclusion of the facilities acquired
from EnerPro for the full year of 2005.
Net earnings for 2005 were $60.7 million, up $38.0 million compared to
2004. The increase in net earnings was largely due to the consolidation of the
Partnership, Rimbey Pipe Line and the EnerPro assets for the full year of
2005. In addition, stronger Marketing results also contributed to higher net
earnings in 2005. This growth was partly offset by higher general and
administrative costs, interest expense and depreciation charges.
In 2005, distributions to unitholders increased by $36.5 million due to a
higher number of units outstanding as a result of conversions of debentures
into trust units. In addition, the Fund increased per unit distributions by
approximately 16% compared to 2004.The following table presents selected financial information for the Fund:
Three months ended (in thousands of dollars)
-------------------------------------------------------------------------
Mar 31, Jun 30, Sep 30, Dec 31,
2005 2005 2005 2005
-------------------------------------------------------------------------
Operating revenues:
- Marketing 228,767 223,590 243,114 317,863
- Gathering and Processing 30,552 35,516 35,927 37,278
- NGL Infrastructure 8,829 7,276 8,506 10,349
Net earnings 17,832 11,157 16,200 15,491
Net earnings per
unit ($/unit)
Basic 0.31 0.19 0.27 0.26
Diluted 0.28 0.17 0.25 0.23
Trust units outstanding
(thousands)
Weighted average (basic) 57,761 58,596 59,475 59,926
Weighted average (diluted) 62,989 62,988 63,194 63,246
Distributions to unitholders 17,924 19,332 20,223 21,062
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 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
-------------------------------------------------------------------------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.
In the fourth quarter of 2006, Gathering and Processing revenue of
$43.6 million decreased by $0.7 million due to lower revenues at the Chinchaga
and Strachan plants. This decrease was partly offset by higher revenues
experienced in the West Central region.
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
Third quarter Marketing revenues of $279.5 million increased from the
prior quarter by $0.3 million. This increase was primarily due to the
settlement of financial contracts partly offset by lower NGL sales volumes.
Gathering and Processing revenue of $44.3 million increased by
$3.5 million due to higher throughput in the West Central Region, 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 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 higher throughput volumes in the West Central
Region and 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.
March 31, 2006 compared to December 31, 2005
Marketing revenues of $316.8 million decreased by $1.0 million due to a
slight softening of propane margins attributed to warmer than seasonal
weather.
Gathering and Processing revenue for the first quarter of 2006 was
$38.1 million, an increase of $0.8 million from the prior quarter. The
increase was due to higher throughput volumes and the acquisition of an
incremental 25% ownership interest in the Strachan gas plant in December 2005.
For the first quarter of 2006, operating revenues from NGL Infrastructure
were $9.6 million, down $0.7 million from the prior quarter. This decrease was
primarily due to lower fractionation revenues, and the result of lower
throughput caused by equipment fouling at the Fort Saskatchewan facility. This
decrease was partly offset by a non-recurring final adjustment upon expiration
of a long-term contract.
Net earnings were $15.4 million, a decrease of $0.1 million from the
previous quarter. This decrease was primarily due to higher income tax
expenses. The effect of the higher income tax was partly offset by higher
operating margins and lower general and administrative costs.
December 31, 2005 compared to September 30, 2005
For the fourth quarter of 2005, Marketing revenues of $317.9 million
increased by $74.7 million compared to the previous quarter. This increase was
largely due to the seasonal increase in sales volumes.
For the fourth quarter of 2005, Gathering and Processing revenues of
$37.3 million increased by $1.4 million compared to the previous quarter. NGL
Infrastructure revenues of $10.3 million increased by $1.8 million compared to
the previous quarter. These increases were primarily due to higher throughput
volumes and increased flow-through of operating costs.
Net earnings were $15.5 million in the fourth quarter of 2005, down
$0.7 million from the previous quarter. This decrease was primarily due to
higher general and administrative costs, interest and depreciation charges.
The effect of these higher costs was partly offset by the strong Marketing
results achieved in the fourth quarter.
September 30, 2005 compared to June 30, 2005
For the third quarter of 2005, Marketing revenues of $243.1 million
increased by $19.5 million compared to the previous quarter. This increase was
largely due to continued demand for butane and condensate. The price of
propane also strengthened in the third quarter of 2005.
For the third quarter of 2005, operating revenues from the Gathering and
Processing segment was $35.9 million, up $0.4 million compared to the previous
quarter. Operating revenues from the NGL Infrastructure segment were
$8.5 million, up $1.2 million compared to the previous quarter. These
increases were due to prior period fee recoveries and higher revenues from
services.
Net earnings were $16.2 million in the third quarter of 2005, up
$5.0 million from the previous quarter. This increase was primarily due to
stronger results from facilities in the third quarter as well as lower general
and administrative costs and the recognition of an impairment expense of
$1.2 million in the second quarter of 2005.
June 30, 2005 compared to March 31, 2005
For the second quarter of 2005, Marketing revenues of $223.6 million
decreased by $5.2 million compared to the prior quarter. The decrease in
revenues was primarily due to a seasonal decrease in sales volumes that was
partially offset by strong condensate and butane price premiums.
Operating revenues from Gathering and Processing for the second quarter
of 2005 was $35.5 million, up $5.0 million from the previous quarter. This
increase in revenue was largely due to the return of volumes from the Caribou
and Strachan plants that experienced unplanned outages in the first quarter of
2005. In addition, volumes were redirected to the Strachan plant in the second
quarter due to third party plant turnarounds. This increase was partly offset
by a decrease of NGL Infrastructure revenue of $7.3 million, down $1.6 million
from prior quarter.
Net earnings were $11.2 million in the second quarter, down by
$6.7 million compared to the first quarter of 2005. This decrease was
primarily due to weaker Marketing results and an increase in general and
administrative costs. General and administrative costs were higher in the
second quarter due to higher incentive plan costs. Also in the second quarter,
an impairment expense of $1.2 million was recorded to reflect management's
decision to dispose of a small, non-core gas processing plant.
Investor Information
DISTRIBUTIONS TO UNITHOLDERS
Distributions to Unitholders were $0.357 per unit in the fourth quarter
and $1.43 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 2006 were 57% return of capital, 8.8% dividend income and 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.
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.
YEAR-END 2006 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 2006
results at 8:00 am MST (10:00 am EST) on February 28, 2007. Callers may
participate by either dialing 800-814-4859 or 416-644-3417. A recording of the
call will be available for replay until midnight, March 7, 2007 by dialing
877-289-8525 or 416-640-1917 and entering pass code 21219242 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
(All amounts expressed in thousands of Canadian dollars)
2006 2005
$ $
-------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents - 5,634
Accounts receivable 160,112 191,259
Inventory 53,939 53,205
Asset held for sale (note 4) 4,200 -
Other current assets 4,327 4,042
-------------------------------------------------------------------------
222,578 254,140
Property, plant and equipment (note 3) 924,947 881,330
Asset held for sale (note 4) - 4,573
Intangible assets (note 5) 75,487 78,117
-------------------------------------------------------------------------
1,223,012 1,218,160
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities
Bank indebtedness 96 -
Accounts payable and accrued liabilities 148,318 171,316
Distributions payable (note 11) 7,251 7,155
Credit facilities (note 6) 107,984 66,000
-------------------------------------------------------------------------
263,649 244,471
Long-term debt (note 6) 215,000 215,000
Convertible debentures (note 7) 23,542 30,713
Asset retirement obligation (note 8) 34,533 27,776
Future income tax liability (note 9) 65,424 72,466
-------------------------------------------------------------------------
602,148 590,426
-------------------------------------------------------------------------
Non-controlling interest 2,744 2,198
Unitholders' equity
Unitholders' capital (note 10) 677,025 665,914
Accumulated earnings 159,083 91,005
Accumulated cash distributions to unitholders
(note 11) (217,988) (131,383)
-------------------------------------------------------------------------
618,120 625,536
-------------------------------------------------------------------------
1,223,012 1,218,160
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Commitments and contingencies (note 14)
See accompanying notes to the consolidated financial statements
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 Earnings and Accumulated Earnings
For the Years Ended December 31
(All amounts expressed in thousands of Canadian dollars, except per unit
information)
2006 2005
$ $
-------------------------------------------------------------------------
Operating revenues
Marketing sales 1,161,899 1,013,334
Gathering and Processing 166,736 139,274
NGL Infrastructure 39,888 34,959
-------------------------------------------------------------------------
1,368,523 1,187,567
Operating expenses
Marketing cost of goods sold 1,102,045 946,263
Gathering and Processing 96,558 67,469
NGL Infrastructure 23,956 24,296
-------------------------------------------------------------------------
1,222,559 1,038,028
-------------------------------------------------------------------------
145,964 149,539
General and administrative 18,892 25,217
Interest expense 18,156 16,213
Depreciation and amortization 39,843 36,887
Accretion expense (note 8) 2,257 2,048
Impairment expense 373 1,160
-------------------------------------------------------------------------
79,521 81,525
-------------------------------------------------------------------------
Earnings before tax and non-controlling interest 66,443 68,014
Income tax (recovery) expense (note 9) (2,660) 6,630
-------------------------------------------------------------------------
Earnings before non-controlling interest 69,103 61,384
Non-controlling interest 1,025 704
-------------------------------------------------------------------------
Net earnings 68,078 60,680
Accumulated earnings, beginning of year 91,005 30,325
-------------------------------------------------------------------------
Accumulated earnings, end of year 159,083 91,005
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Weighted average number of units (thousands)
(note 10)
- basic 60,604 58,947
- diluted 62,794 63,075
Net earnings per unit (note 10)
- basic 1.12 1.03
- diluted 1.10 0.96
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements
Keyera Facilities Income Fund
Consolidated Statements of Cash Flows
For the Years Ended December 31
(All amounts expressed in thousands of Canadian dollars)
2006 2005
Net inflow (outflow) of cash: $ $
-------------------------------------------------------------------------
Operating activities
Net earnings 68,078 60,680
Items not affecting cash:
Depreciation and amortization 39,843 36,887
Accretion expense 2,257 2,048
Impairment expense 373 1,160
Unrealized (gain) loss on financial instruments (491) 280
Future income tax (recovery) expense (note 9) (7,042) 2,411
Non-controlling interest 1,025 704
Asset retirement obligation expenditures (note 8) (160) (183)
Changes in non-cash operating working capital 6,773 (41,840)
-------------------------------------------------------------------------
110,656 62,147
-------------------------------------------------------------------------
Investing activities
Additions to property, plant and equipment (73,868) (52,870)
Additions to intangibles (1,115) -
Proceeds on sale of assets - 907
Changes in non-cash working capital (651) 4,951
-------------------------------------------------------------------------
(75,634) (47,012)
-------------------------------------------------------------------------
Financing activities
Proceeds from credit facilities 41,984 54,000
Issuance of trust units (note 10) 4,252 2,175
Distributions paid to unitholders (note 11) (86,509) (77,013)
Distributions or dividends paid to others (479) (506)
-------------------------------------------------------------------------
(40,752) (21,344)
-------------------------------------------------------------------------
Net cash (outflow) inflow (5,730) (6,209)
Cash and cash equivalents, beginning of year 5,634 11,843
-------------------------------------------------------------------------
Cash (bank indebtedness), end of year (96) 5,634
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements
See note 15 for cash interest and taxes paid
Keyera Facilities Income Fund
Notes to Consolidated Financial Statements
For the years ended December 31, 2006 and 2005
(All amounts expressed in thousands of Canadian dollars, except where
otherwise noted)
1. Structure of the Fund
Keyera Facilities Income Fund (the "Fund") is an unincorporated
open-ended trust established under the laws of the Province of
Alberta pursuant to the Fund Declaration of Trust dated April 3,
2003. The Fund indirectly owns a 100% interest in Keyera Energy
Partnership (the "Partnership").
The Partnership is involved in the business of natural gas gathering
and processing, as well as natural gas liquids ("NGLs") and crude oil
processing, transportation, storage and marketing in Canada and the
U.S. Its wholly-owned subsidiaries include Keyera Energy Facilities
Ltd. ("KEFL"), Keyera Energy Ltd. ("KEL") and Keyera Energy Inc.
("KEI").
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 are equal to the pro rata share of the distribution
received indirectly from the Partnership and, in the event of the
termination of the Fund, participating pro rata in the net assets
remaining after satisfaction of all liabilities.
2. Summary of significant accounting policies
Principles of consolidation
These consolidated financial statements have been prepared by
management in accordance with Canadian generally accepted accounting
principles ("GAAP"). The consolidated financial statements include
the accounts of the Fund and all controlled entities. All subsidiary
companies, with the exception of Rimbey Pipe Line Co. Ltd. ("RPL"),
are wholly-owned. The non-Fund ownership interest in RPL has been
included in the consolidated financial statements and is shown as a
non-controlling interest. 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 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 consisting primarily of marketing NGLs and crude oil
midstream activities, is recognized based on volumes delivered to
customers at contractual delivery points and rates.
Gathering and Processing revenue
Gathering and Processing revenue is recognized through fixed fee
arrangements or flow-through arrangements that are designed to
recover operating costs and provide 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 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.
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.
Financial instruments
Derivative financial instruments are utilized by the Fund through its
ownership in the Partnership to mitigate its exposure to fluctuations
in the price of natural gas, NGLs, electricity and currency exchange
rates. The Fund uses a variety of instruments to manage these
exposures including swaps and options. Gains and losses related to
derivative contracts are recognized in Marketing revenue.
The Fund may elect to use hedge accounting. To be accounted for as a
hedge, a derivative financial instrument must be designated and
documented as a hedge and must be effective at inception and on an
ongoing basis. The documentation defines the relationships between
the hedging items and the hedged items and documents the objectives
and strategies for undertaking various hedge transactions. The
process includes linking derivative financial instruments to specific
anticipated transactions. The Fund also formally assesses, both at
the inception of the hedge and on an ongoing basis, whether the
instrument used is highly effective in offsetting changes in cash
flows or fair values of the hedged item. Hedge effectiveness is
achieved if the cash flows from the hedging item substantially offset
the cash flows of the hedged item and the timing of the cash flows is
similar or if changes in the fair value of the financial instrument
substantially offset changes in the fair value of the related asset
or liability.
If designated as a hedge, gains and losses on these instruments are
deferred and recognized in earnings in the same period as the hedged
item. The fair value of derivative financial instruments qualifying
for hedge accounting is not recorded on the consolidated statements
of financial position. When a hedging derivative financial instrument
matures, expires, is sold, terminated or cancelled and is not
replaced as part of the Fund's hedging strategy, the termination gain
or loss is deferred and recognized when the gain or loss on the
hedged item is recognized. If a designated hedged item matures,
expires, is sold, extinguished or terminated and the hedged item is
no longer probable of occurring, any previously deferred amounts
associated with the hedging item are recognized in current earnings
along with the corresponding gains or losses recognized on the hedged
item. If a hedging relationship is terminated or ceases to be
effective, hedge accounting is not applied to subsequent gains or
losses. Any previously deferred amounts are carried forward and
recognized in earnings in the same period as the underlying hedged
item.
Where a financial instrument is not designated as a hedge or does not
meet the criteria for hedge accounting, it is recorded on the
consolidated statement of financial position at its fair value,
either as an asset or as a liability. Changes in the fair value of
these financial instruments are recognized in earnings in the period
in which they occur.
Cash and cash equivalents
Cash and cash equivalents include short-term investments with
maturity of three months or less when purchased.
Inventory
Inventory is comprised primarily of NGL product for sale through the
marketing operations. Inventory is valued at the lower of cost and
net realizable value. Cost is determined on a weighted average cost
basis, calculated monthly.
Property, plant and equipment
Property, plant and equipment consist 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 six to thirty-three years for
Gathering and Processing, thirteen to thirty-two years for NGL
Infrastructure, three to twenty-five years for Marketing and seven to
twenty-three years for corporate assets.
Impairment on property, plant and equipment is measured in a two-step
process. Step one calculates the fair value, 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.
Intangible assets
Goodwill
Keyera's goodwill resulted from business combinations and represents
the portion of purchase price that was in excess of the fair value of
net assets acquired. Goodwill is recorded at cost and is not subject
to amortization. It is tested at least annually for impairment by
comparing the estimated future cash flows of a reporting unit, to
which the goodwill is attributable, to its book value.
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.
Deferred financing costs
Deferred financing fees consist of transaction costs incurred to
obtain financing. These assets were recorded at cost and are being
amortized on a straight-line basis over the term of their related
debt offering.
Asset retirement obligation
The asset retirement cost, deemed to be the fair value of the asset
retirement obligation, is capitalized as part of the cost of the
related long-lived asset and allocated to expense on a basis
consistent with depreciation and amortization. Amortization of asset
retirement costs is included in depreciation and amortization in the
consolidated statement of earnings. The amount of the liability is
revised periodically in accordance with changes in the assumptions
and estimates underlying the calculations. Increases in the asset
retirement obligation resulting from the passage of time are recorded
as accretion expense in the consolidated statement of earnings, over
the estimated time period until settlement of the obligation. Actual
expenditures incurred are charged against the asset retirement
obligation.
Income taxes
Under the terms of the Canadian Income Tax Act, the Fund is
considered to be a "mutual fund trust" and is taxable only to the
extent that its income is not distributed or distributable to its
unitholders. The Fund is contractually committed to distribute to its
unitholders all or virtually all of its taxable income and taxable
capital gains that would otherwise be taxable in its hands.
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 12. The LTIP is a stock appreciation right as defined by the
Canadian Institute of Chartered Accountants. The difference between
the market price of the trust units and the grant price for the
outstanding units multiplied by the number of rights is recognized as
compensation expense, over the vesting period. Fluctuations in the
price of the trust units will change the accrued compensation expense
and are recognized when they occur.
Net earnings per unit
Basic net earnings per unit are calculated by dividing net earnings,
by the weighted average number of units outstanding during the
period. For the calculation of the weighted average number, trust
units are determined to be outstanding from the date they are issued.
Diluted net earnings per unit is calculated by adding the weighted
average number of units outstanding during the period to the
additional units that would have been outstanding if potentially
dilutive units had been issued, using the "treasury stock" method.
Distributions to unitholders
The monthly amount of the distributions to unitholders of the Fund is
defined in the Fund Declaration of Trust. The computation of the
distributions to unitholders is comprised of cash amounts received or
receivable as distributions or interest income and any net proceeds
from the issuance of trust units, less any amounts that relate to the
redemption of trust units and any expenditures of the Fund.
3. Property, plant and equipment
Accumulated Net Book
Cost Depreciation Value
As at December 31, 2006 $ $ $
---------------------------------------------------------------------
Gathering and Processing 859,540 (145,251) 714,289
NGL Infrastructure 231,709 (36,467) 195,242
Marketing 12,179 (254) 11,925
Corporate and other 8,616 (5,125) 3,491
---------------------------------------------------------------------
Total 1,112,044 (187,097) 924,947
---------------------------------------------------------------------
Accumulated Net Book
Cost Depreciation Value
As at December 31, 2005 $ $ $
---------------------------------------------------------------------
Gathering and Processing 808,225 (117,014) 691,211
NGL Infrastructure 216,932 (28,760) 188,172
Marketing - - -
Corporate and other 6,860 (4,913) 1,947
---------------------------------------------------------------------
Total 1,032,017 (150,687) 881,330
---------------------------------------------------------------------
Costs associated with assets under development, excluded from costs
subject to depreciation, totaled $1,757 as at December 31, 2006 (2005
- $10,823).
4. Asset held for sale
Asset held for sale consists of an interest in an electrical
generator. In 2005, a portion of the equipment was sold for proceeds
of $162. 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 $4,200.
5. Intangible assets
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 and other (c) 3,333 (1,847) 1,486
---------------------------------------------------------------------
Total 87,557 (12,070) 75,487
---------------------------------------------------------------------
Accumulated Net Book
Cost Amortization Value
As at December 31, 2005 $ $ $
---------------------------------------------------------------------
Gathering and Processing (a) 39,219 - 39,219
NGL Infrastructure (a) 25,715 - 25,715
Marketing (b) 18,175 (7,178) 10,997
Corporate and other (c) 3,645 (1,459) 2,186
---------------------------------------------------------------------
Total 86,754 (8,637) 78,117
---------------------------------------------------------------------
(a) Gathering and Processing and NGL Infrastructure segments intangible
assets consist of goodwill.
(b) The Marketing segment intangible assets are other intangible assets.
Other intangible assets 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 less than a year
to seven years.
(c) The corporate segment intangible assets relate to deferred financing
fees. Long-term debt deferred financing fees are discussed further in
note 6. Convertible debenture deferred financing fees are discussed
further in note 7.
6. Credit facilities and long-term debt
2006 2005
As at December 31 $ $
---------------------------------------------------------------------
Bank credit facilities (a) 100,984 63,000
Revolving demand loan (d) 7,000 3,000
---------------------------------------------------------------------
Total credit facilities 107,984 66,000
---------------------------------------------------------------------
---------------------------------------------------------------------
---------------------------------------------------------------------
Long-term debt (b & c) 215,000 215,000
---------------------------------------------------------------------
---------------------------------------------------------------------
(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, 2009, 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 rate for the year ended December 31, 2006 was 5.43%
(2005 - 4.40%). As at December 31, 2006, the balance outstanding on
the bank credit facilities was $100,984 (2005 - $63,000).
(b) In 2003, $125,000 of unsecured senior notes were issued by the
Partnership and KEFL in three parts: Series A of $52,500 due in
2010, bearing interest at 5.79%, Series B of $52,500 due in 2013,
bearing interest at 6.16%, and $20,000 due in 2008, bearing interest
at 5.42%. Interest is payable monthly. Financing costs of $1,215 have
been deferred and are amortized over the remaining terms of the
related debt. Amortization expense of $163 has been recorded for the
year ended December 31, 2006 (2005 - $163).
(c) 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 over the
term of the debt. Amortization expense of $114 has been recorded for
the year ended December 31, 2006 (2005 - $114).
(d) A subsidiary of the Partnership has an unsecured revolving demand
loan facility with a major Canadian chartered bank in the amount of
$7,000, of which $7,000 was drawn as at December 31, 2006 (2005 -
$3,000). Borrowings under the loan facility bear interest based on
the lender's rates for Canadian prime commercial loans or Bankers'
Acceptances rates. The weighted average interest rate for the year
ended December 31, 2006 was 5.07% (2005 - 4.13%).
7. Convertible debentures
In 2004, the Fund issued convertible unsecured subordinated
debentures in the principal amount of $100,000. 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, 2006 $76,458
debentures had been converted to trust units (2005 - $69,287).
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. Upon
conversion of the debentures, the financing cost related to the
principal amount of debt converted is adjusted and is recognized as a
debit to unitholders' equity. As a result of conversions to date at
December 31, 2006, $2,782 has been reclassified to unitholders'
equity (2005 - $2,470). Amortization expense of $111 has been
recorded for the year ended December 31, 2006 (2005 - $624)
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 $1,776 has been accrued for the year ended
December 31, 2006 (2005 - $2,958).
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.
2006 2005
For the year ended December 31 $ $
---------------------------------------------------------------------
Asset retirement obligation, beginning of year 27,776 24,188
Liabilities acquired 151 744
Liabilities settled (160) (183)
Revisions in estimated cash flows 4,509 979
Accretion expense 2,257 2,048
---------------------------------------------------------------------
Asset retirement obligation, end of year 34,533 27,776
---------------------------------------------------------------------
The total undiscounted amount of cash flows required to settle the
asset retirement obligations is $183,159 which has been discounted
using a credit- adjusted risk-free rate of 7% (2005 - $168,150). 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
The Fund is a unit trust for income tax purposes. As such, the Fund
is only taxable on any taxable income not allocated to the
unitholders. Each unitholder resident in Canada will be required to
include in computing income for tax purposes for a particular
taxation year the pro rata share of the Fund's income that was paid
or payable in that year to the unitholder and that was deducted by
the Fund in computing its income.
The following is a reconciliation of income taxes, calculated at the
combined federal and provincial income tax rates, to the income tax
provision included in the consolidated statements of earnings.
2006 2005
$ $
---------------------------------------------------------------------
Earnings before tax and non-controlling interest 66,443 68,014
Income from the Fund distributed to unitholders (36,061) (42,653)
---------------------------------------------------------------------
Income before taxes - operating subsidiaries 30,382 25,361
---------------------------------------------------------------------
Income tax at statutory rate of 34.49%
(2005 - 37.62%) 10,479 9,541
Non-deductible items excluded from income for
tax purposes (142) 2,083
Rate adjustments and changes in estimates (10,356) (2,467)
Benefit of long-term incentive plan previously
not recorded (2,202) -
Benefit of non-capital losses previously not
recorded (46) 442
Resource allowance 3 (51)
Adjustments to tax pool balances (198) (3,554)
Other (198) (392)
Large corporation tax - 1,028
---------------------------------------------------------------------
(2,660) 6,630
---------------------------------------------------------------------
---------------------------------------------------------------------
Classified as:
Current 4,382 4,219
Future (7,042) 2,411
---------------------------------------------------------------------
Income tax expense (2,660) 6,630
---------------------------------------------------------------------
---------------------------------------------------------------------
For income tax purposes, the subsidiaries of the Fund have non-
capital losses carried forward of approximately $11,987 (2005 -
$2,773) 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, 2006.
The future income tax liability relates to the (taxable) deductible
temporary differences in the carrying values and tax bases as
follows:
2006 2005
As at December 31 $ $
---------------------------------------------------------------------
Property, plant and equipment (71,611) (75,827)
Asset retirement obligation 4,308 4,104
Long-term incentive plan 1,513 -
Non-capital losses 3,475 -
Intangible assets (616) (956)
Other (2,493) 213
---------------------------------------------------------------------
Future income tax liability (65,424) (72,466)
---------------------------------------------------------------------
---------------------------------------------------------------------
The unrecorded future tax liability attributable to the Partnership
at December 31, 2005 was $72,882 (2005 - $84,612).
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 can be used solely for
providing voting rights to persons holding securities that are
directly or indirectly exchangeable for units and that, by their
terms, have voting rights in the Fund.
The trust units are redeemable at the holder's option at an amount
equal to the lesser of: (i) 90% of the weighted average price per
unit during the period of the last 10 trading days during which the
units were traded on the Toronto Stock Exchange; and (ii) an amount
equal to (a) the closing market price of the units; (b) an amount
equal to the average of the highest and lowest prices of units on the
date on which the units were tendered for redemption; or (c) the
average of the last bid and ask prices if there was no trading on the
date on which the units were tendered for redemption.
Redemptions are subject to a maximum of $50 cash redemptions in any
particular month. Redemptions in excess of this amount will be paid
by way of a distribution in specie of assets of the Fund that may
include Commercial Trust Series 1 notes.
In 2005, the Fund instituted a Distribution Reinvestment and Optional
Unit Purchase Plan ("DRIP") that permits unitholders to reinvest cash
distributions for additional units. This plan allows eligible
participants an opportunity to reinvest distributions into trust
units at a 3% discount to a weighted average market price, so long as
units are issued from treasury under the DRIP. The Fund has the right
to notify participants that units will be acquired in the market, in
which case units will be purchased at the weighted average market
price. Eligible unitholders can also make optional unit purchases
under the optional unit purchase component of the plan at the
weighted average market price.
Number
Trust units issued and unitholders' capital of Units $
---------------------------------------------------------------------
Balance, January 1, 2005 57,414,677 633,604
Units issued on conversion of convertible
debentures 2,586,968 30,135
Units issued pursuant to DRIP 88,223 1,598
Units issued pursuant to LTIP 35,325 577
---------------------------------------------------------------------
Balance, December 31, 2005 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
---------------------------------------------------------------------
---------------------------------------------------------------------
Net earnings per unit
Basic per unit calculations for the years ended December 31, 2006 and
2005 were based on the weighted average number of units outstanding
for the applicable year. Convertible debentures were in the money for
the years ended December 31, 2006 and 2005 and attributed to the
increase in diluted weighted average number of units for 2006 and
2005.
Beginning in the second quarter of 2006, incentive awards have been
excluded from the calculation of diluted weighted average number of
units as units are delivered by acquiring them on the market rather
than issuing them from treasury.
(thousands) 2006 2005
---------------------------------------------------------------------
Weighted average number of units - basic 60,604 58,947
Net additional units if incentive awards vested - 485
Additional units if debentures converted 2,190 3,643
---------------------------------------------------------------------
Weighted average number of units - diluted 62,794 63,075
---------------------------------------------------------------------
---------------------------------------------------------------------
11. Accumulated cash distributions to unitholders
$
---------------------------------------------------------------------
Balance, January 1, 2005 52,842
---------------------------------------------------------------------
Unitholders' distributions declared and paid 71,386
Unitholders' distributions declared 7,155
---------------------------------------------------------------------
Balance, December 31, 2005 131,383
---------------------------------------------------------------------
Unitholders' distributions declared and paid 79,354
Unitholders' distributions declared 7,251
---------------------------------------------------------------------
Balance, December 31, 2006 217,988
---------------------------------------------------------------------
---------------------------------------------------------------------
12. 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 $3,017 for the year ended December 31,
2006 (2005 - $10,589).
During the year ended December 31, 2006, 161,731 units were purchased
on the market at a cost of $3,351 and delivered to plan participants
under the plan. In addition, the equivalent of 106,132 unit awards
were settled in cash.
(a) Performance Unit Awards
Performance Unit Awards will vest 100% on the third anniversary of
the effective date of each award, July 1, 2004, July 1, 2005 and
July 1, 2006. The number of units to be delivered will be determined
by the financial performance of the Fund over the three-year period.
The number of units to be delivered will be 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, 2004 July 1, 2005 July 1, 2006 Payout
Grant Grant Grant Multiplier
---------------------------------------------------------------------
Less than 1.15 Less than 1.32 Less than 1.42 Nil
First range 1.15 - 1.22 1.32 - 1.39 1.42 - 1.51 50% - 99%
Second range 1.23 - 1.38 1.40 - 1.55 1.52 - 1.71 100% - 199%
Third range 1.39 and 1.56 and 1.72 and
greater greater greater 200%
---------------------------------------------------------------------
As of December 31, 2006, 529,867 Performance Unit Awards were
outstanding (2005 - 478,172): 161,737 effective July 1, 2004,
197,330 effective July 1, 2005 and 170,800 effective July 1, 2006.
The compensation cost recorded for these units for the year ended
December 31, 2006 was $1,431 using the applicable closing market
price of a unit of the Fund (2005 - $8,246).
(b) Time Vested Unit Awards ("Restricted Unit Awards")
Restricted Unit Awards will vest automatically, over a three-year
period from the effective date of each award, July 1, 2004, July 1,
2005 and July 1, 2006 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, 2006, 98,735 Restricted Unit Awards were
outstanding (2005 - 123,427): 26,049 effective July 1, 2004, 29,086
effective July 1, 2005 and 43,600 effective July 1, 2006. The
compensation cost recorded for these units for the year ended
December 31, 2006 was $1,586 using the applicable closing market
price of a unit of the Fund (2005 - $2,343).
13. Financial instruments
Energy price risk management
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.
Price swap agreements require payments to (or receipts from) counter
parties based on the differential between fixed and variable prices
for commodities. Forward currency exchange contracts require the
exchange of currencies between counter-parties at previously agreed
upon exchange rates.
The fair values of the derivatives designated as hedges 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
Carrying Average Notional Fair
2006 Amount $ Price Volume Value $
---------------------------------------------------------------------
Natural gas:
Price swaps (maturing by
March 31, 2007) - $7.78/GJ 90,000 GJs (130)
Electricity:
Price swaps (maturing by
December 31, 2008) - $55/MWh 43,860 MWhs 1,031
---------------------------------------------------------------------
---------------------------------------------------------------------
2005
Natural gas:
Price swaps - - - -
Electricity:
Price swaps - - - -
---------------------------------------------------------------------
---------------------------------------------------------------------
Where the financial instrument is not designated as a hedge or does
not meet the criteria for hedge accounting, it is recorded on the
consolidated statement of financial position at its fair value,
either as an asset or a liability under accounts receivable or
accounts payable and accrued liabilities, respectively. Changes in
the fair value of these financial instruments are recognized in
earnings in the period in which they occur.
In 2006, Keyera realized and recorded $6.6 million of proceeds in
Marketing revenue related to the settlement of financial instruments.
A further $0.5 million of unrealized gains on financial contracts was
recorded in Marketing revenue. The fair value of the financial
instruments which do not qualify or have not been designated as
hedges are listed below. The carrying amounts are recorded in
accounts receivable and accounts payable, respectively.
Weighted
Carrying Average Notional Fair
2006 Amount $ Price Volume Value $
---------------------------------------------------------------------
NGLs:
Price swaps (maturing
between January 31, 2007
and March 30, 2007) 211 $72.25/Bbl 450,000 Bbls 211
Currency:
Forward contracts
(maturing between
January 3, 2007 and
January 26, 2007) (287) $1.1477/USD US$16,350 (287)
---------------------------------------------------------------------
---------------------------------------------------------------------
2005
NGLs:
Price swaps (maturing
by March 31, 2006) (280) $69.06/Bbl 60,000 Bbls (280)
Currency:
Forward contracts
(maturing between
January 5, 2006 and
January 31, 2006) (60) $1.1613/USD US$13,000 (60)
---------------------------------------------------------------------
---------------------------------------------------------------------
The estimated fair value of all financial instruments is based on
quoted market prices and, if not available, on estimates from
third-party brokers or dealers.
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, 2006, the accounts receivable from the two
largest customers amounted to less than 1% of accounts receivable
(2005 - less than 1%). Revenue from the two largest customers
amounted to 11% of operating revenue in 2006 (2005 - 12%). With
respect to counterparties for financial instruments used for economic
hedging purposes, 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.
Interest rate risk
Fixed and floating rate debt are used to finance operations. The
floating rate debt creates exposures to changes in interest payments
as interest rates fluctuate. At December 31, 2006, fixed rate
borrowings comprised 67% of total debt outstanding (2005 - 77%). The
fair value of the senior fixed rate debt at December 31, 2006 was
$224,457 (2005 - $222,074). The fair value of the Fund's unsecured
convertible debentures at December 31, 2006 was $31,782 (2005 -
$55,591).
Fair value
The carrying values of cash and cash equivalents, accounts receivable
and accounts payable and accrued liabilities approximate their fair
values because the instruments are near maturity or have no fixed
repayment terms. The fair value of the bank credit facilities
approximates fair value due to their floating rates of interest.
Foreign currency rate risk
The 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$313,191 of sales were priced in
U.S. dollars for the year ended December 31, 2006 (2005 -
US$238,584). In 2006, the Fund realized and recorded $0.7 million of
realized foreign currency loss in operating expenses. A further
$0.8 million of unrealized foreign currency loss was also recorded in
operating expenses.
14. Commitments and contingencies
The Fund, through its operating entities, is involved in various
contractual agreements with a major oil and gas producer. The
agreements range from one to twelve years and comprise the processing
of the producer's natural gas and the purchase of its 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. The estimated annual minimum operating lease
rental payments from these commitments are as follows:
$
---------------------------------------------------------------------
2007 8,480
2008 7,870
2009 5,176
2010 3,761
2011 2,410
Thereafter 3,500
---------------------------------------------------------------------
31,197
---------------------------------------------------------------------
---------------------------------------------------------------------
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.
15. Supplemental cash flow information
The 2005 amounts were reclassified to reflect the nature of the
changes in non-cash working capital. As a result, changes in non-cash
operating activities decreased by $7,909, changes in non-cash
investing activities increased by $4,951 and changes in non-cash
financing activities increased by $2,958.
2006 2005
Other cash flow information $ $
---------------------------------------------------------------------
Interest paid 18,486 14,933
Taxes paid 4,601 4,024
---------------------------------------------------------------------
16. Segmented information
The Fund has three reportable segments: Gathering and Processing,
NGL Infrastructure and Marketing. Gathering and Processing includes
natural gas gathering and processing. NGL Infrastructure includes NGL
and crude oil processing, transportation, and storage. The Marketing
business consists of marketing of NGLs, sulphur and crude oil. The
accounting policies of the segments are the same as those described
in the summary of significant accounting policies. Intersegment sales
and expenses are recorded at current market prices.
Gathering NGL
Year ended and Infrastruc-
December 31, Processing ture Marketing Corporate Total
2006 $ $ $ $ $
-------------------------------------------------------------------------
Revenue 170,184 69,072 1,161,899 - 1,401,155
Inter-segment
revenue (3,448) (29,184) - - (32,632)
-------------------------------------------------------------------------
External
revenue 166,736 39,888 1,161,899 - 1,368,523
Operating
expenses (96,558) (23,956) (1,134,677) - (1,255,191)
Inter-segment
expenses - - 32,632 - 32,632
-------------------------------------------------------------------------
External
operating
expenses (96,558) (23,956) (1,102,045) - (1,222,559)
-------------------------------------------------------------------------
70,178 15,932 59,854 - 145,964
General and
administrative,
interest and
other - - - (37,048) (37,048)
Depreciation and
amortization (28,237) (7,707) (3,299) (600) (39,843)
Accretion
expense (1,950) (297) (10) - (2,257)
Impairment
expense (373) - - - (373)
-------------------------------------------------------------------------
Earnings (loss)
before tax
and non-
controlling
interest 39,618 7,928 56,545 (37,648) 66,443
Income tax
recovery
(expense) - (4,133) (143) 6,936 2,660
-------------------------------------------------------------------------
Earnings (loss)
before non-
controlling
interest 39,618 3,795 56,402 (30,712) 69,103
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Identifiable
assets 819,416 232,076 163,826 7,694 1,223,012
-------------------------------------------------------------------------
Capital
expenditures 45,498 14,573 12,040 1,757 73,868
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Gathering NGL
Year ended and Infrastruc-
December 31, Processing ture Marketing Corporate Total
2005 $ $ $ $ $
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Revenue 142,916 57,759 1,013,334 - 1,214,009
Inter-segment
revenue (3,642) (22,800) - - (26,442)
-------------------------------------------------------------------------
External
revenue 139,274 34,959 1,013,334 - 1,187,567
Operating
expenses (67,469) (24,296) (972,704) - (1,064,469)
Inter-segment
expenses - - 26,441 - 26,441
-------------------------------------------------------------------------
External
operating
expenses (67,469) (24,296) (946,263) - (1,038,028)
-------------------------------------------------------------------------
71,805 10,663 67,071 - 149,539
General and
administrative,
interest and
other - - - (41,430) (41,430)
Depreciation and
amortization (25,838) (6,990) (2,301) (1,758) (36,887)
Accretion
expense (1,784) (264) - - (2,048)
Impairment
expense (1,160) - - - (1,160)
-------------------------------------------------------------------------
Earnings (loss)
before tax
and non-
controlling
interest 43,023 3,409 64,770 (43,188) 68,014
Income tax
(expense) - (5,297) - (1,333) (6,630)
-------------------------------------------------------------------------
Earnings (loss)
before non-
controlling
interest 43,023 (1,888) 64,770 (44,521) 61,384
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Identifiable
assets 794,792 222,708 184,878 15,782 1,218,160
-------------------------------------------------------------------------
Capital
expenditures 43,122 8,761 - 987 52,870
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2006 2005
$ $
-------------------------------------------------------------------------
Marketing revenue derived from
export sales to the U.S. 84,577 74,689
Property, plant and equipment
located in the U.S. 11,925 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
17. Subsequent Event
The Government of Canada has announced a proposed tax on the income
of publicly-traded Canadian income trusts and limited partnerships.
As an existing income trust, the new tax will not apply to the Fund
until January, 2011. The imposition of this tax will reduce the
amount of cash that the Fund would otherwise have available for
distribution after January 1, 2011.
Legislation to impose this tax has not been introduced and there is
no assurance that the tax will be imposed. Substantive enactment of
this legislation is expected to increase future income tax
liabilities, and reduce future net income in the periods after
substantive enactment.
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, West Central Region
Robert B. Catell
Chairman and CEO Steven B. Kroeker
KeySpan Corporation Vice President, Corporate Development
New York, New York
Bradley W. Lock
Michael B.C. Davies(2) Vice President, Engineering &
Principal Operational Services
Davies & Co.
Banff, Alberta David A. Sentes
Vice President, Comptroller
Nancy M. Laird(3)(4)
Corporate Director K. Jamie Urquhart
Calgary, Alberta Vice President, Foothills Region
H. Neil Nichols(2)(3) Stock Exchange Listing
Management Consultant The Toronto Stock Exchange
Mississauga, Ontario Trading Symbols KEY.UN; KEY.DB
William R. Stedman(3)(4) Unit Trading Summary Q4 2006
Chairman and CEO ---------------------------------------
ENTx Capital Corporation TSX:KEY.UN - Cdn $
Calgary, Alberta ---------------------------------------
High $21.90
Wesley R. Twiss(2) Low $15.51
Corporate Director Close December 29, 2006 $16.64
Calgary, Alberta Volume 15,671,635
Average Daily Volume 252,768
(1) Chairman of the Board
(2) Member of the Audit Auditors
Committee Deloitte & Touche LLP
(3) Member of the Compensation Chartered Accountants
and Governance Committee Calgary, Canada
(4) Member of the Health,
Safety and Environment Investor Relations
Committee Contact:
John Cobb or Avery Reiter
Toll Free: 1-888-699-4853
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
