AltaGas Income Trust
TSX : ALA.UN

AltaGas Income Trust

February 26, 2010 08:00 ET

AltaGas Reports 2009 Fourth Quarter and Year-End Results

CALGARY, ALBERTA--(Marketwire - Feb. 26, 2010) - AltaGas Income Trust (AltaGas or the Trust) (TSX:ALA.UN) today reported net income for the three months ended December 31, 2009 was $32.1 million ($0.40 per unit - basic), compared to $39.6 million ($0.55 per unit - basic) for the same period of 2008. Excluding the effect of unrealized gain or loss on risk management contracts, fourth quarter 2009 net income was $39.3 million and EBITDA was $66.0 million compared to $33.5 million and $61.2 million respectively, for the same period in 2008.

Net income for the year ended 2009 was $141.3 million ($1.80 per unit - basic), compared to $163.6 million ($2.38 per unit - basic) in 2008. Excluding the effect of unrealized gain on risk management contracts, 2009 net income was $139.7 million and EBITDA was $244.7 million compared to $158.0 million and $245.4 million, respectively, in 2008.

"AltaGas performed well in 2009, reporting same EBITDA as 2008's record year," said David Cornhill, Chairman and CEO of the Trust. "It was a year of challenges and opportunities. We faced these head on and managed our assets to ensure stable cash flow in a volatile and weak economy.

Overall, the Gas Segment performed well. The addition of the Sarnia gas storage facility and the natural gas distribution assets enhanced results and added to the strong performance of our extraction and transmission assets. Weak gas prices combined with volatility in the capital markets impacted drilling activity in the Western Canada Sedimentary Basin and prompted some producers to shut-in production, reducing AltaGas' field processing throughput.

With the hedges in place the Power Segment reported solid results despite weakness in Alberta spot power prices. The addition of the 102-MW Bear Mountain Wind Park in October further supported earnings and is expected to add to earnings in 2010, the first full year in service.

"In 2009, we significantly advanced our growth strategy with the completion of two major capital projects - the 102-MW Bear Mountain Wind Park in northeast British Columbia and the 5.3 Bcf Sarnia natural gas storage facility in southern Ontario - as well as the acquisition of the natural gas distribution assets," said Cornhill. "We remain committed to growing our Gas and Power Segments, with approximately $2 billion of organic growth projects over the next five years."

AltaGas completed several financing initiatives in 2009, including a $100 million equity issuance, a new $250 million credit facility and $300 million in medium term notes. With the addition of long-life, low-risk assets such as the Bear Mountain Wind Park and natural gas distribution assets, as well as credit rating upgrades from both Standard and Poors (S&P) and Dominion Bond Rating Services (DBRS), AltaGas is well positioned to continue to execute its growth strategy of investing in long life energy infrastructure.

AltaGas also declared a distribution of $0.18 per trust unit and exchangeable unit payable on April 15, 2010 to unitholders of record on March 25, 2010. The ex-distribution date is March 23, 2010.The Trust declared total cash distributions of $0.54 per unit in fourth quarter 2009 and $2.16 per unit for full year 2009.

Assuming a unit was held throughout 2009, for income tax purposes the Trust expects 78.8 percent of the total distributions declared in 2009 to be taxed as income, 4.0 percent as capital gains, 0.2 percent as dividend income and 17.0 percent as return of capital. For most unitholders, the return of capital amount will reduce the cost base of their Trust units for purposes of calculating the capital gains amount upon disposition of their units. Unitholders should seek independent tax advice in respect of the consequences to them of acquiring, holding and disposing of units.

FINANCIAL HIGHLIGHTS(1):

- Earnings before interest, taxes, depreciation and amortization (EBITDA) were $58.8 million ($0.73 per unit) for fourth quarter 2009, compared to $70.8 million ($0.99 per unit) for the same quarter in 2008. EBITDA for the full year 2009 was $248.4 million ($3.16 per unit), compared to $256.4 million ($3.73 per unit) in 2008.

- Funds from operations were $51.0 million ($0.64 per unit) for fourth quarter 2009, compared to $53.8 million ($0.75 per unit) for the same period in 2008. Funds from operations for the year were $202.3 million ($2.58 per unit), compared to $216.8 million ($3.15 per unit) in 2008.

- Total net debt on December 31, 2009 was $1,014.7 million, compared to $668.9 million at September 30, 2009 and $582.0 million at December 31, 2008. The Trust's debt to total capitalization ratio as at December 31, 2009 was 49.2 percent, versus 38.7 percent at September 30, 2009 and 37.8 percent at the end of 2008.

(1) Includes Non-GAAP financial measures. See previous public disclosures available at www.altagas.ca or www.sedar.com for definitions

IN THE FOURTH QUARTER:

- DBRS upgraded the Trust's credit rating from BBB (low) with a Positive trend to BBB with a Stable trend.

- The Trust's 102 MW Bear Mountain Wind Park was fully connected to the power grid within the Province of British Columbia and met the conditions of Commercial Operation Date (COD) in order to receive the firm price under the 25 year energy purchase agreement (EPA) with BC Hydro. Owned and operated by AltaGas, the $200 million project is British Columbia's first fully operational wind park.

- Through the acquisitions of AltaGas Utility Group Inc. (Utility Group) and Heritage Gas Limited (Heritage Gas), AltaGas acquired natural gas distribution assets that serve over 71,000 customers in Alberta, the Northwest Territories and Nova Scotia.

SUBSEQUENT TO THE FOURTH QUARTER:

- AltaGas offered to acquire all of the outstanding common shares of Landis Energy Corporation (Landis) in exchange for cash of $0.80 per common share. The Landis acquisition is a good strategic fit, adding quality opportunities to grow the Trust's gas storage capacity, including the Alton natural gas storage facility, located near Truro, Nova Scotia which is in the advanced development phase.

AltaGas will hold a conference call today at 9 a.m. MT (11 a.m. ET) to discuss the fourth quarter and full year 2009 financial and operating results and other general issues and developments concerning the Trust.

Members of the media, investment community and other interested parties may dial (416) 695-6616 or call toll free at 1-800-952-4972. No pass code is required. Please note that the conference call will also be webcast. To listen, please connect here: http://events.digitalmedia.telus.com/altagas/022610/index.php.

Shortly after the conclusion of the call, a replay will be available by dialing (416) 695-5800 or 1-800-408-3053. The passcode is 5262350. The replay expires at midnight (ET) on March 5, 2010. The webcast will be archived for one year.

Forward-Looking Information

The audited consolidated annual financial statements and annual Management's Discussion and Analysis, which contains additional notes and disclosures, are expected to be filed with SEDAR on or about March 2, 2010, at which time a press release to that effect will be issued. The material will also be available on the AltaGas website on that same day (www.altagas.ca).

This news release contains forward-looking statements. When used in this news release the words "may", "would", "could", "will", "intend", "plan", "anticipate", "believe", "seek", "propose", "estimate", "expect", and similar expressions, as they relate to the Trust or an affiliate of the Trust, are intended to identify forward-looking statements. In particular, this news release contains forward-looking statements with respect to, among others things, business objectives, expected growth, results of operations, performance, business projects and opportunities and financial results. Specifically, such forward-looking statements are set forth under: "Consolidated Outlook"; "Gas Outlook"; "Power Outlook"; "Global Capital Market Conditions"; "Growth Capital"; and "Corporate Outlook".

These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Such statements reflect the Trust's current views with respect to future events based on certain material factors and assumptions and are subject to certain risks and uncertainties including without limitation, changes in market competition, governmental or regulatory developments, changes in tax legislation, general economic conditions and other factors set out in the Trust's public disclosure documents.

Many factors could cause the Trust's or any of its business segment's actual results, performance or achievements to vary from those described in this news release, including without limitation those listed above as well as the assumptions upon which they are based proving incorrect. These factors should not be construed as exhaustive. Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially from those described in this news release as intended, planned, anticipated, believed, sought, proposed, estimated or expected, and such forward-looking statements included in this news release herein should not be unduly relied upon. These statements speak only as of the date of this news release. The Trust does not intend, and does not assume any obligation, to update these forward-looking statements except as required by law. The forward-looking statements contained in this news release are expressly qualified as cautionary statements.

Financial outlook information contained in this news release about prospective results of operations, financial position or cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on management's assessment of the relevant information currently available. Readers are cautioned that such financial outlook information contained in this news release should not be used for the purposes other than for which it is disclosed herein.

Additional information relating to AltaGas can be found on its website at www.altagas.ca. The continuous disclosure materials of the Trust, including its annual MD&A and Consolidated Financial Statements, Annual Information Form, Information Circular, and Proxy Statement, material change reports and press releases issued by the Trust, are also available through the Trust's website or directly through the SEDAR system at www.sedar.com.



CONSOLIDATED FINANCIAL RESULTS Three Months Ended Year Ended
(unaudited) December 31 December 31
($ millions) 2009 2008 2009 2008
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Revenue 336.4 424.6 1,268.3 1,816.8
Unrealized gain (loss) on risk
management (7.2) 9.6 3.7 11.0
Net revenue(1) 115.4 125.8 456.6 476.5
EBITDA(1) 58.8 70.8 248.4 256.4
EBITDA before unrealized gain (loss)
on risk management 66.0 61.2 244.7 245.4
Operating income(1) 38.8 53.0 174.2 188.0
Net income 32.1 39.6 141.3 163.6
Net income before tax-adjusted
unrealized gain on risk
management(1) 39.3 33.5 139.7 158.0
Total assets 2,629.1 2,132.3 2,629.1 2,132.3
Total long-term liabilities 719.1 851.6 719.1 851.6
Net additions to capital assets 322.2 47.5 486.5 808.0
Distributions declared(2) 43.0 38.7 170.2 147.1
Cash flows
Cash from operations 45.4 37.7 184.1 205.2
Funds from operations(1) 51.0 53.8 202.3 216.8
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Three Months Ended Year Ended
December 31 December 31
($ per unit) 2009 2008 2009 2008
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EBITDA(1) 0.73 0.99 3.16 3.73
EBITDA before unrealized gain on
risk management(1) 0.82 0.85 3.12 3.57
Net income - basic 0.40 0.55 1.80 2.38
Net income - diluted 0.40 0.56 1.80 2.36
Net income before tax-adjusted
unrealized gain on risk
management(1) 0.49 0.47 1.78 2.30
Distributions declared(2) 0.540 0.540 2.160 2.125
Cash flows
Cash from operations 0.57 0.53 2.34 2.98
Funds from operations(1) 0.64 0.75 2.58 3.15
Units outstanding - basic
(millions)
During the period(3) 80.0 71.6 78.5 68.8
End of period 80.3 71.9 80.3 71.9
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(1) Non-GAAP financial measure; see discussion in Non-GAAP Financial
Measures section of this MD&A.
(2) Distributions declared of $0.18 per unit per month commenced in August
2008. January 2008 to July 2008 distributions of $0.175 per unit per
month were declared.
(3) Weighted average.


CONSOLIDATED FINANCIAL REVIEW

Fourth Quarter

Net income for fourth quarter 2009 was $32.1 million compared to $39.6 million in the same period in 2008. Net income was $0.40 per basic unit for fourth quarter 2009 compared to $0.55 per basic unit for the same period in 2008.

Fourth quarter 2009 was a successful quarter for AltaGas due to the completion of the Utility Group and Heritage Gas acquisitions (natural gas distribution assets) and Bear Mountain Wind Park commencing commercial operations. All of these achievements immediately contribute to the Trust's operating income.

During the quarter, the Gas Segment performed well due to the addition of the natural gas distribution (NGD) assets, contributions from Sarnia natural has storage facility (Sarnia Storage), adjustment to transmission revenues previously deferred, higher fee-for-service revenues and the expiry of a legacy gas marketing contract. These increases were partially offset by lower processing volumes at Field Gathering and Processing (FG&P) facilities as producers reduced drilling activities and shut-in production in response to weak gas prices and lower realized frac spreads in the extraction business. The Power Segment reported lower results primarily due to higher volumes sold at low spot power prices but benefited from lower transmission and environmental costs, as well as contributions from Bear Mountain Wind Park which commenced commercial operations in fourth quarter 2009. Higher investment income offset operating costs in the Corporate Segment. The Corporate Segment reported unrealized losses on risk management contracts compared to unrealized gains in fourth quarter 2008. The Trust reported higher interest expense in fourth quarter 2009 compared to the same period in 2008 due to higher average debt balances, partially offset by a lower average borrowing rate. Income tax expense was lower in fourth quarter 2009 due to the impact for financial instruments and lower income subject to tax.

On a consolidated basis, net revenue for fourth quarter 2009 was $115.4 million compared to $125.8 million in same period 2008. In the Gas Segment, net revenue increased due to the acquisition of NGD assets, higher fee-for-service revenues, contributions from Sarnia Storage, increased rates, expiry of a legacy gas marketing contract, higher frac spreads and NGL volumes and higher transmission fees. These increases were partially offset by lower throughput in most FG&P areas and lower operating cost recoveries. In the Power Segment, net revenue decreased due to lower revenue from the sale of power in Alberta at spot power prices which were lower than the same period last year, the gain on assets sold in 2008 and lower contribution from gas-fired peaking plants, partially offset by the contribution from Bear Mountain Wind Park, strong hedge prices and lower power purchase arrangement (PPA) costs. The Corporate segment reported higher net revenue due to investment income, partially offset by unrealized losses on risk management contracts.

Operating and administrative expense for fourth quarter 2009 was $56.4 million, up from $56.1 million for the same period in 2008. The increase was due to the addition of NGD assets partially offset by lower costs within the Corporate Segment.

Amortization expense for fourth quarter 2009 was $20.3 million compared to $16.8 million in the same period in 2008. The increase was due to the growth in AltaGas' asset base from acquisitions and construction activities.

Interest expense in fourth quarter 2009 was $9.3 million compared to $8.1 million for the same period in 2008. The increase was due to higher average debt balances of $945.3 million compared to $581.6 million for the same period in 2008. The average debt balance was higher due to the Utility Group and Heritage Gas acquisitions in the fourth quarter. The increase was partially offset by a lower average borrowing rate. The average borrowing rate was 4.9 percent in fourth quarter 2009 compared to 6.3 percent in fourth quarter 2008.

In fourth quarter 2009, an income tax recovery of $2.9 million was reported compared to an expense of $6.4 million in fourth quarter 2008. The decrease was due to the impact for financial instruments and lower income subject to tax.

Full Year 2009

Net income for 2009 was $141.3 million compared to $163.6 million in 2008, which included a one-time tax recovery of $13.8 million. Excluding this recovery, net income for 2008 was $149.8 million or $8.5 million higher than the current period. Net income was $1.80 per basic unit for 2009 compared to $2.38 per basic unit for 2008.

During 2009, the Gas Segment performed well due to a reduction of liabilities related to natural gas transactions, higher extraction volumes, the addition of NGD assets in fourth quarter 2009, no major extraction turnarounds and a one-time adjustment to transmission revenues previously deferred. These increases were partially offset by lower processing volumes at FG&P facilities as producers reduced drilling activities and shut-in production in response to weak gas prices and lower realized frac spreads in the extraction business. The Power Segment reported lower results primarily due to declines in realized power prices but benefited from lower transmission and environmental costs as well as contributions from Bear Mountain Wind Park which commenced commercial operations in fourth quarter 2009. The Corporate Segment benefited from higher investment income offset by lower unrealized gains on risk management contracts compared to 2008. The Trust reported higher interest expense in 2009 compared to 2008 due to higher average debt balances and a higher average borrowing rate. Income tax expense was higher in 2009 due to a one-time tax recovery of $13.8 million in 2008, partially offset by the tax impact for financial instruments and lower income subject to tax.

On a consolidated basis, net revenue for 2009 was $456.6 million compared to $476.5 million in 2008. In the Gas Segment, net revenue increased due to the addition of NGD assets in fourth quarter 2009, higher extraction volumes, adjustments to liabilities, previously deferred transmission revenues, contribution from Sarnia Storage and expanded transmission business. These increases were partially offset by lower throughput in most FG&P areas, lower frac spreads and lower operating cost recoveries. In the Power Segment, net revenue decreased due to lower spot power prices in Alberta, the gain on assets sold in 2008 and lower contribution from gas-fired peaking plants, partially offset by strong hedge prices and lower PPA and transmission costs. The Corporate Segment reported higher net revenue due to investment income, partially offset by lower unrealized gains on risk management contracts.

Operating and administrative expense for 2009 was $208.2 million, down from $221.5 million in 2008. The decrease was largely due to fewer turnarounds compared to the prior year, when approximately $7.4 million of turnaround costs were recorded. The decrease is further explained by a $2.6 million charge for project development costs in 2008. Cost control measures have also resulted in a decline in administrative costs. These decreases were partially offset by incremental costs associated with the growth of the Trust including the addition of NGD assets.

Amortization expense for 2009 was $74.1 million compared to $67.0 million last year. The increase was due to the growth in AltaGas' asset base from acquisitions and construction activities.

Interest expense in 2009 was $31.8 million compared to $27.4 million last year. The increase was due to higher average debt balances of $691.5 million compared to $581.0 million in 2008. The average borrowing rate was 5.6 percent in 2009 compared to 5.3 percent in 2008.

Income tax expense in 2009 was $1.2 million compared to a recovery of $1.6 million in 2008. The increase was largely due to a one-time $13.8 million recovery of future income taxes in third quarter 2008 as a result of legal entity ownership changes within the trust structure, partially offset by the tax impact for financial instruments and lower income subject to tax.

Assuming a unit was held throughout 2009, for income tax purposes the Trust expects 78.8 percent of the total distributions declared in 2009 to be taxed as income, 4.0 percent as capital gains, 0.2 percent as dividend income and 17.0 percent as return of capital. For most unitholders, the return of capital amount will reduce the cost base of their Trust units for purposes of calculating the capital gains amount upon disposition of their units. Unitholders should seek independent tax advice in respect of the consequences to them of acquiring, holding and disposing of units.

GLOBAL CAPITAL MARKET CONDITIONS

Although uncertainty in global financial markets persisted in 2009, AltaGas' financial position and ability to generate cash from its operations in the short and long terms have remained strong.

Throughout 2009, the Trust demonstrated its ability to access capital markets. In February AltaGas completed an equity offering which generated gross proceeds of approximately $100 million and in March the Trust secured a new $250 million credit facility with a syndicate of eight banks. AltaGas also completed two issuances of medium-term notes (MTN) in second quarter 2009 for total proceeds of $300 million.

The Trust's liquidity position remains sound, underpinned by highly predictable cash flow from operations, as well as revolving bank lines of $816.0 million, of which $262.2 million was available as at December 31, 2009 and strong participation in the distribution reinvestment program (DRIP).

GROWTH CAPITAL

Based on projects currently under review, development or construction, AltaGas expects capital expenditures for 2010 to be approximately $225 million, 70 percent for gas and 30 percent for power. To date, approximately $80 million of capital has been committed for 2010. Growth capital is funded through AltaGas' cash from operations, DRIP proceeds and credit facilities. The following projects have an expected in-service date post 2010.

Alton Gas Storage Project

AltaGas has made an offer to acquire Landis Energy Corporation (Landis) which is a developer of underground natural gas storage facilities. The most advanced project developed by Landis is the Alton natural gas storage project, located near Truro, Nova Scotia which is expected to serve customers seeking to manage natural gas supply requirements in eastern Canada and the northeast United States.

Walker Ridge Project

AltaGas is developing the 70-MW Walker Ridge wind project in northern California. AltaGas has selected the turbines and a preliminary layout and has completed the preliminary engineering studies. The project is located near existing transmission lines and requires limited system upgrades to interconnect. It is located in Lake Colussa County and is close to the San Francisco load. This project is proceeding with the environment and land permitting process and AltaGas is actively seeking bilateral agreements for sale of the power output.

Glen Ridge Project

AltaGas is developing the 100-MW Glen Ridge wind project located in southeast Alberta. AltaGas has secured a 17,000 acre land package and has made application to Natural Resources Canada for the ecoENERGY renewable initiative (eRPI) funding. AltaGas expects to submit its Alberta Utilities Commission application in early 2010 and has completed its Alberta Electric System Operator transmission system impact study and expects to start the facilities study in Q1 2010. AltaGas is actively seeking a market for its prospective green credits. Once in-service, the project will use these green credits to offset compliance costs associated with the Trust's Sundance B PPA.

Roughrider Project

AltaGas is developing the 90-MW Roughrider wind project in North Dakota. The project holds easements of approximately 27,000 acres on private land. AltaGas is currently in the Western Area Power Administration (WAPA) and Midwest ISO transmission queues and has determined there are limited transmission upgrades required to interconnect to the WAPA transmission system. AltaGas is seeking green credit and energy markets with local and out of state utilities.

AltaGas continues to advance its early stage wind development projects by setting up meteorological towers to collect wind data, and initiating permit applications and transmission studies.

Hydroelectric

AltaGas is developing a portfolio of run of river hydroelectric projects in the Province of British Columbia (B.C.), including three projects in Northwest B.C.; Forrest Kerr, McLymont Creek and Volcano Creek (NW Projects). These NW Projects have a combined generating capacity of approximately 277 MW and are currently the subject of discussions with the Government of B.C. These discussions include considerations relating to the announcement by the Government of B.C. to upgrade and extend the electricity transmission capabilities in B.C.'s Northwest, specifically the Northwest Transmission Line (NTL). The NTL upgrade would extend the British Columbia Transmission Corporation's (BCTC) transmission grid to within 44 km of the NW Projects.

Log and Kookipi Creek Run-of-River Projects

AltaGas is advancing engineering studies, preparing comprehensive environmental submissions, and engaging with First Nations to support the development of the Log and Kookipi Creek projects. Located in southern British Columbia these two 10 MW capacity run-of-river projects have 40-year electricity sales agreements with BC Hydro. Subject to successful conclusion of permitting and other activities, construction of these two projects is expected to begin in 2011 with an in-service in 2013.



RESULTS OF OPERATIONS BY SEGMENT

Operating Income Three Months Ended Year Ended
December 31 December 31
($ millions) 2009 2008 2009 2008
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Gas
Extraction and Transmission 21.6 22.2 88.6 83.8
Field Gathering and Processing 1.6 3.1 6.3 20.4
Natural Gas Distribution 7.4 - 7.4 -
Energy Services 1.4 (0.3) 8.0 (0.6)
Total Gas 32.0 25.0 110.3 103.6
Power 22.9 32.5 88.0 117.9
Corporate (16.1) (4.5) (24.1) (33.5)
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38.8 53.0 174.2 188.0
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GAS

Fourth Quarter

Operating income from the Gas Segment was $32.0 million in fourth quarter 2009 compared to $25.0 million for the same period in 2008. The Trust's Gas Segment focused on the integration of the NGD assets which were acquired in the quarter. Operating income generated from both the newly acquired NGD assets and Sarnia Storage contributed to the increase in operating income. The Trust also focused on existing business units to improve operating income; including increased fee-for-service revenues, higher contracted volumes in the transmission business and higher extraction volumes processed in part due to no major turnarounds in 2009. These increases to operating income were partially offset by lower throughput in most FG&P areas due to lower producer activity and gas well shut-ins in the quarter, lower fixed-price natural gas transportation sales and higher amortization costs related to the growth of the Gas Segment.

Net revenue in the Gas Segment for fourth quarter 2009 was $93.6 million compared to $79.6 million for the same period in 2008. Net revenue increased $13.0 million due to the acquisition of NGD assets in the quarter, $1.8 million in increased fee-for-service revenues in the extraction business, $1.4 million contributed by Sarnia Storage, $1.0 million increased rates in the FG&P business and increases due to higher NGL volumes and higher transmission fees. These increases were partially offset by $4.1 million due to lower throughput in most FG&P areas and $0.8 million in lower fixed-price natural gas transportation sales.

Operating and administrative expense for fourth quarter 2009 was $43.9 million, compared to $40.2 million for the same period in 2008. The increase is largely due to the acquisition of NGD assets.

Amortization expense for fourth quarter 2009 was $17.7 million, compared to $14.3 million for the same period in 2008. The increase was due to the growth in AltaGas' asset base from acquisition and construction activities.

Full Year 2009

Operating income from the Gas Segment was $110.3 million in 2009 compared to $103.6 million in 2008. In 2009, the Gas Segment focused on integrating both acquired and constructed assets. Operating income generated from both the new NGD assets and Sarnia Storage contributed to the increase in operating income. The Trust also focused on optimizing its existing business units to improve operating income; including a positive adjustment to transmission revenues that were previously deferred and liabilities related to natural gas transactions, higher NGL volumes, higher contracted volumes in the transmission business and higher extraction volumes processed in part due to no major turnarounds in 2009. These increases to operating income were partially offset by lower throughput in most FG&P areas due to lower producer activity and gas well shut-ins during 2009. Lower realized frac spreads received, lower fixed-price natural gas transportation sales and one turnaround in the FG&P business also contributed to lowering operating income.

Net revenue in the Gas Segment for 2009 was $340.1 million compared to $334.2 million in 2008. Net revenue increased $9.4 million from a reduction of liabilities related to natural gas transactions, $6.0 million due to higher NGL volumes, $4.5 million due to increased transmission revenues, which included a one-time adjustment of $3.3 million for revenues that were previously deferred and increased contracted volumes, $3.9 million as a result of the 2008 capital program at the Harmattan Complex and $3.8 million due to the addition of Sarnia Storage. Net revenue also increased $7.4 million due to the acquisition of NGD assets in fourth quarter 2009. These increases were partially offset by $12.7 million in lower realized frac spreads, $12.4 million in lower volumes processed at FG&P facilities, $4.3 million due to lower fixed-price natural gas transportation sales, $3.2 million from lower facility service revenues and $1.0 million due to a gas marketing contract which expired in fourth quarter 2009.

Operating and administrative expense for 2009 was $166.4 million, down from $173.2 million in 2008. The decrease was largely due to fewer turnarounds than 2008, when approximately $7.4 million of turnaround costs were recorded. The decrease is further explained by a $2.6 million charge for project development costs in 2008. Cost control measures have also resulted in a decline in administrative costs. These decreases were partially offset by incremental costs associated with the addition of new assets and businesses acquired by the Trust during the second half of 2008 and fourth quarter 2009.

Amortization expense for 2009 was $63.4 million compared to $57.3 million in 2008. The increase was due to the growth in AltaGas' asset base from acquisition and construction activities.

Description of Extraction and Transmission (E&T) Assets

The E&T segment consists of two wholly-owned and four partially-owned interests in ethane and NGL extraction plants, five natural gas and three NGL transmission systems.

E&T Variance Analysis

Fourth Quarter

Operating income in fourth quarter 2009 was $21.6 million compared to $22.2 million reported for the same period in 2008. The decrease was due to $0.7 million in lower realized frac spreads and higher amortization due to capital growth. These decreases were partially offset by $1.8 million in higher fee-for-service revenues, $0.8 million higher NGL volumes and $0.6 million due to the EDS upgrade and higher transmission fees.

Full Year 2009

Operating income in the E&T business for 2009 was $88.6 million compared to $83.8 million in 2008. Operating income increased $6.0 million due to higher NGL volumes, $4.5 million from increased transmission revenues of which $3.3 million was a one-time adjustment for revenues previously deferred and increased contracted transmission volumes, $3.9 million as a result of the 2008 Harmattan Complex capital program, lower operating costs of $2.9 million and $1.3 million due to the EDS upgrade and increased transmission cost-of-service fees. These increases were partially offset by $12.7 million in lower realized frac spreads, $2.7 million of higher amortization related to 2008 capital programs and $0.6 million due to lower fees-for-service revenues in the extraction business.

Description of FG&P Assets

The FG&P segment gathers and processes natural gas from producer-owned wells throughout Western Canada and delivers sales quality gas into downstream pipeline systems that supply North American natural gas markets. AltaGas operates plants in Alberta, Saskatchewan and British Columbia with a combined processing capacity of approximately 1.2 Bcf/d.

FG&P Variance Analysis

Fourth Quarter

Operating income in fourth quarter 2009 was $1.6 million compared to $3.1 million for the same quarter in 2008. Operating income decreased $4.1 million primarily as a result of lower volumes processed due to reduced producer activity and customers shutting-in gas production in response to low natural gas prices. This decrease was partially offset by $1.0 million in higher processing fees and $1.7 million in lower operating and administrative expenses.

Full Year 2009

Operating income from the FG&P business was $6.3 million in 2009 compared to $20.4 million in 2008. Operating income decreased by $12.4 million due to lower throughput, $3.2 million due to lower facility service revenues and $1.0 million due to higher amortization. These decreases were partially offset by $2.5 million from lower operating costs and $1.0 million due to lower turnaround costs in 2009 compared to 2008.

Description of NGD

The NGD business consist of ownership in three natural gas distribution businesses, including 100 percent of both AltaGas Utilities Inc. (AUI) and Heritage Gas Limited (Heritage Gas) and one-third ownership of both Inuvik Gas and the Ikhil Joint Venture. The businesses were acquired in fourth quarter 2009 through the purchase of 80.2 percent of Utility Group not already owned by AltaGas and the subsequent purchase of 75.1 percent of Heritage Gas not already owned by AltaGas.

NGD Variance Analysis

Operating income for the NGD business has been included in 2009 with the acquisition of Utility Group effective October 8, 2009 and the remaining 75.1 percent of Heritage Gas effective November 18, 2009. The results of NGD assets are highly seasonal, with the majority of natural gas deliveries occurring during the winter heating season. For 2009, the NGD business contributed $7.4 million to operating income.

Description of Energy Services

The Energy Services segment consists of two main businesses: an energy management business providing energy consulting and supply management services and arranging gas and power contracts for non-residential end-users; and a gas services business buying and reselling natural gas, transportation and storage. The Energy Services segment also includes AltaGas' 50 percent share of Sarnia Airport Storage Pool Limited Partnership (Sarnia Storage) which owns 5.3 Bcf of gas storage capacity. This storage facility was constructed in 2009 and started receiving natural gas injections on June 25, 2009. The project was delivered on schedule and under budget.

Energy Services Variance Analysis

Fourth Quarter

Operating income in fourth quarter 2009 was $1.4 million compared to an operating loss of $0.3 million for the same quarter in 2008. Operating income increased as a result of $1.4 million from Sarnia Storage and $0.9 million loss in fourth quarter 2008 as a result of a gas marketing contract which expired in early fourth quarter 2009. These increases were partially offset by $0.8 million in lower fixed-price natural gas and transportation sales.

Full Year 2009

Operating income in the Energy Services segment was $8.0 million for 2009 compared to an operating loss of $0.6 million for 2008. Operating income increased approximately $9.4 million as a result of the reduction of liabilities related to natural gas transactions, $3.2 million from Sarnia Storage and $1.0 million loss in 2008 as a result of a gas marketing contract which expired in early fourth quarter 2009. These increases were partially offset by $4.3 million in lower fixed-price natural gas and transportation sales and a one-time loss of $0.8 million for risk management contracts.



Three Months Ended Year Ended
Gas Operating Statistics December 31 December 31
2009 2008 2009 2008
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E&T
Extraction inlet gas processed
(Mmcf/d)(1) 844 790 841 801
Extraction ethane volumes
(Bbls/d)(1) 26,922 23,892 26,817 24,795
Extraction NGL volumes (Bbls/d)(1) 12,890 11,534 13,236 12,242
Total Extraction volumes
(Bbls/d)(1) 27,766 24,682 40,053 37,037
Frac spread - realized
($/Bbl)(1)(2) 25.96 28.41 23.46 26.97
Frac spread - average spot price
($/Bbl)(1) 26.87 18.58 19.51 28.79
Transmission volumes
(Mmcf/d)(1)(3) 320 367 324 379
FG&P
Processing capacity (Mmcf/d)(4) 1,172 1,172 1,172 1,172
Processing throughput (gross
Mmcf/d)(1) 423 521 453 541
Capacity utilization (%)(4) 39 44 39 46
Average working interest (%)(4) 93 92 93 92
NGD
Natural gas deliveries - end-use
(PJ)(5)(6) 6.62 - 6.62 -
Natural gas deliveries -
transportation (PJ)(5)(6) 0.55 - 0.55 -
Service sites at year-end (7) 72,717 - 72,717 -
Degree day variance (%) (8) 9.9 - 9.9 -
Energy Services
Energy management service
contracts(9) 1,748 1,711 1,748 1,711
Average volumes transacted
(GJ/d)(10) 377,580 291,353 354,513 302,392
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(1) Average for the period.
(2) Indicative frac spread or NGL margin, expressed in dollars per barrel of
NGL and which is derived from Edmonton postings for propane, butane and
condensate and the daily AECO natural gas price.
(3) Excludes NGL pipeline volumes.
(4) As at the end of the reporting period.
(5) Petajoule (PJ) is one million gigajoules (GJ).
(6) Deliveries reflect Utility Group as of October 8, 2009 when the Trust
obtained control and 100 percent of the deliveries of Heritage Gas as
of November 18, 2009.
(7) Service sites reflect all of the service sites of AUI, Heritage Gas and
Inuvik Gas.
(8) Degree days relate to AUI's service area. A degree day is the cumulative
extent to which the daily mean temperature falls below 15 degrees
Celsius. Normal degree days are based on a 20-year rolling average.
Positive variances from normal lead to increased delivery volumes from
normal expectations.
(9) Active energy management service contracts at the end of the reporting
period.
(10) Average for the period. Includes volumes marketed directly, volumes
transacted on behalf of other operating segments, and volumes sold in
gas exchange transactions.


Fourth Quarter Gas Operating Statistics

Average ethane and NGL volumes in the extraction business increased by 3,030 Bbls/d and 1,356 Bbls/d respectively in fourth quarter 2009 compared to same quarter 2008, due to increased throughput volumes at the Younger and Joffre Ethane Extraction Plants in part as a result of no turnaround at Joffre Ethane Extraction Plant in 2009. Natural gas volumes transported in the transmission business during the fourth quarter 2009 decreased from the same quarter in 2008 due to lower volumes moved on the Suffield system. However, in the transmission business, pipeline throughput has minimal impact on the financial results due to cost-of-service and take-or-pay contractual arrangements in place.

In FG&P, throughput in the quarter averaged 423 Mmcf/d compared to 521 Mmcf/d in fourth quarter 2008. Of the 19 percent or 98 Mmcf/d decline, approximately 75 percent was due to lower producer activity which resulted in a higher impact from natural declines, approximately 20 percent was due to producers shutting-in natural gas production due to low commodity prices and the remainder was due to planned and unplanned downtime. In the quarter, utilization reported in fourth quarter 2009 was 39 percent compared to 44 percent reported in fourth quarter 2008 primarily due to lower throughput at most facilities.

Full Year 2009 Gas Operating Statistics

Average ethane and NGL volumes in the extraction business increased by 2,022 Bbls/d and 994 Bbls/d respectively in 2009 compared to 2008, due to the completion of projects that attracted approximately 25 Mmcf/d of incremental natural gas at the Harmattan Complex for the full year compared to two months in 2008 and higher throughput at Younger, Harmattan and Joffre due to no turnarounds in 2009. The increases were partially offset by intermittent curtailment of inlet gas at other extraction plants in response to lower frac spreads in early 2009. Natural gas volumes transported in the transmission business in 2009 decreased from 2008 due to lower volumes moved on the Suffield system. However, in the transmission business, pipeline throughput has minimal impact on the financial results due to cost-of-service and take-or-pay contractual arrangements in place.

In FG&P, throughput in 2009 averaged 453 Mmcf/d compared to 541 Mmcf/d in 2008. Approximately 65 percent (57 Mmcf/d) of the decline was due to lower producer activity not offsetting natural declines, approximately 20 percent was due to producers shutting-in natural gas production due to low natural gas prices in the latter half of the year and the remainder was due to planned and unplanned downtime. Utilization reported in 2009 was 39 percent compared to 46 percent in 2008, primarily due to lower throughput at most facilities.

Gas Outlook

In 2010 the Gas Segment is expected to deliver stronger results compared to 2009. This increase is largely due to the addition of NGD assets in fourth quarter 2009. The NGD business is expected to invest over $56 million into property plant and equipment to grow its average mid-year rate base by roughly $47 million or over 18 percent in 2010. AltaGas also expects stronger results due to higher producer activity in the FG&P business along with expansions at AltaGas' existing Pouce Coupe, Ante Creek and Acme gas processing plants, a full year of Sarnia Storage and the expiration of a gas marketing contract. These increases will be partially offset by non-recurring items that provided uplift in 2009 such as the reduction of liabilities related to natural gas transactions and the decrease of Suffield revenue deferral.

In 2010, the Trust anticipates investing $5.0 million into its Acme facility to increase processing capacity by 8 Mmcf/d. In addition, the Trust expects to invest approximately $11.0 million to increase capacity by 8 Mmcf/d at the Ante Creek facility. The Pouce Coupe expansion to be completed in 2010 is expected to cost approximately $24.5 million and will increase capacity at the facility by 18 Mmcf/d. All three projects are expected to be completed and contributing to operating income by third quarter 2010.

In 2010, the Trust estimates that 13 percent of extraction volumes will be exposed to frac spread. Approximately 50 percent of the exposure has been hedged at an average price of $21/Bbl.

Based on management's analysis of historical NGL prices along with NGL published commodity prices and the current forward curve for 2010, management expects NGL frac spread prices averaging approximately $22/Bbl.

POWER

Description of Power Assets

The Power Segment comprises 392 MW of total power generation capacity in Alberta through a 50 percent ownership interest in the Sundance B PPAs and a total natural gas-fired power peaking capacity of 39 MW. The segment also includes a 25 percent interest in a 7-MW run-of-river hydroelectric generation facility in British Columbia, a 102-MW wind park in B.C. that commenced commercial operations on October 24, 2009.

Fourth Quarter

Operating income in the Power Segment in fourth quarter 2009 was $22.9 million compared to $32.5 million for the same period in 2008. In the fourth quarter, the Power Segment was focused on the completion and integration of Bear Mountain Wind Park which reached commercial operation ahead of time and on budget. Operating performance at the wind park during the quarter met management's expectations. Contributions from Bear Mountain and a strong hedging program however were more then offset by lower spot power prices in Alberta.

Net revenue in fourth quarter was $26.5 million compared to $35.9 million for the same period in 2008. Net revenue decreased as a result of lower realized power prices in Alberta which averaged $67.54/MWh compared to the fourth quarter 2008 average of $87.30/MWh. The lower realized power prices resulted in $9.9 million lower revenue. Net revenue was also lower due to higher PPA costs of $1.6 million and lower contribution from gas-fired peaking plants of $1.7 million. These decreases were partially offset by $3.0 million due to the commencement of commercial operations at Bear Mountain.

Operating and administrative expense was $1.6 million in fourth quarter 2009 compared to $1.5 million for the same period in 2008. The increase was due to administrative costs related to the development of renewable energy projects and the commencement of commercial operations at Bear Mountain Wind Park, partially offset by lower costs at peaking plants.

Amortization expense was $2.0 million in fourth quarter 2009 and largely unchanged from $1.9 million for the same period in 2008. The increase was due to the gas-fired peaking plants which went into commercial use in late 2008.

Full Year 2009

Operating income in the Power Segment in 2009 was $88.0 million compared to $117.9 million in 2008. During 2009, the Power Segment was focused on the completion of Bear Mountain Wind Park, which reached commercial operation ahead of schedule and on budget. Contributions from Bear Mountain and a strong hedging program were more than offset by lower spot power prices.

Net revenue for 2009 was $102.2 million compared to $129.0 million for 2008. Net revenue decreased $26.8 million due to lower spot prices in Alberta which averaged $47.84/MWh in 2009 compared to an average of $89.95/MWh in 2008. Net revenue was also lower due to a $1.6 million gain on the sale of a power project under development reported in 2008. The peaking plants reported $2.4 million lower net revenue due primarily to lower power prices in Alberta and $1.2 million higher PPA costs. These decreases were partially offset by lower transmission costs of $7.0 million, $3.0 million due to the commencement of commercial operations at Bear Mountain and $2.3 million of lower environmental costs.

Operating and administrative expense was $6.1 million for 2009 compared to $3.7 million for 2008. The increase was due to costs related to the development of renewable energy projects and increased costs related to the gas-fired peaking plants commissioned in late 2008 and the commencement of commercial operations at Bear Mountain.

Amortization expense was $8.2 million in 2009 compared to $7.4 million in 2008. The increase was due to the gas-fired peaking plants commissioned in late 2008.



Three Months Ended Year Ended
Power Operating Statistics December 31 December 31
2009 2008 2009 2008
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Volume of power sold (GWh)(1) 707 664 2,726 2,623
Average price realized on the sale
of power ($/MWh)(1) 67.54 87.30 68.97 84.51
Alberta Power Pool average spot
price ($/MWh)(2) 46.32 95.18 47.84 89.95
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----------------------------------------------------------------------------
(1) Average for the period.
(2) Includes only Alberta volumes and prices realized on the sale of power.



Power Outlook

In 2010 almost two-thirds of the power delivered to the Alberta Power Pool from the Sundance Plant is hedged at a price of $72, slightly lower than the average hedge price in 2009. Current forward prices, as published in daily broker reports, are in the high $40's/MWh for the balance of 2010. This reflects a temporary over-supply situation in the Alberta Power market that management does not believe is sustainable over the long term. According to the Alberta Electric System Operator (AESO), if the demand for power and the rate of growth in Alberta continues as forecast, the addition of up to 3,800 megawatts of new generation may be required by 2016. A large coal unit in Alberta is expected to be retired during 2010 resulting in a reduction of supply that will not be fully replaced in the near term, and improved economic conditions are expected to bring increased power demand to the province. Offsetting weakness in the spot market will be the impact of a full year contribution from the Bear Mountain Wind Park, as well as the anticipated addition of the Harmattan Cogeneration facility, currently expected to be on-line in the fourth quarter of 2010.

AltaGas is constructing a 13-MW gas-fired co-generation facility at its Harmattan Complex which is expected to cost approximately $22 million. The co-generation facility will deliver power to the Alberta electrical grid and use steam to provide process heat to the Harmattan Complex. This is a highly efficient process of generating power and will reduce greenhouse gas emissions. It also adds further diversity to AltaGas' portfolio of generation assets and will provide another source of capacity to backstop the Sundance B PPAs. The facility is expected to be commissioned in fourth quarter 2010.

CORPORATE

Description of Corporate Assets

The Corporate segment includes the cost of providing corporate services and general corporate overhead, investments in public and private entities and the effects of changes in the value of risk management assets and liabilities. Management makes operating decisions and assesses performance of its operating segments based on realized results and key financial metrics such as return on equity and return on capital without the impact of the volatility in commodity prices, interest rates and foreign exchange rates. Management monitors the impact of mark-to-market accounting as part of the consolidated entity since risk is managed on a portfolio basis. Consequently, the impact of mark-to-market accounting on net income is reported and monitored in the Corporate segment.

Corporate Variance Analysis

Fourth Quarter

The operating loss for fourth quarter 2009 was $16.1 million compared to $4.5 million for the same period in 2008. The increased loss was due to unrealized losses on risk management contracts compared to unrealized gains in 2008, partially offset by investment income and decreased administrative expenses due to cost control measures.

Net revenue was negative $3.5 million for the fourth quarter in 2009 compared to $10.1 million in fourth quarter 2008. Net revenue decreased due to unrealized losses on risk management contracts of $7.2 million compared to a gain of $9.6 million for the same period in 2008. This decrease was partially offset by $3.3 million increase in investment income.

Operating and administrative expense for fourth quarter 2009 was $12.0 million compared to $14.1 million for the same period in 2008. The decrease was due to lower computer costs of $2.0 million and reduced other administrative costs due to cost control measures.

Amortization expense was $0.6 million for fourth quarter 2009 similar to $0.5 million for the same period in 2008.

Full Year 2009

The operating loss for 2009 was $24.1 million compared to $33.5 million for 2008. The decreased loss was mainly due to realized and unrealized gains from investments, higher investment income and last year's charge for project development costs. These decreases were partially offset by lower unrealized gains on risk management contracts.

Net revenue was $18.6 million in 2009 compared to $12.9 million in 2008. Net revenue increased $13.4 million due to increased investment income, partially offset by $7.7 million in lower unrealized gains on risk management contracts.

Operating and administrative expense was $40.1 million in 2009 compared to $44.1 million in 2008. Increased expenses were incurred to support regulatory requirements and growth of the Trust but were more then offset as a result of several initiatives to reduce general and administrative expenses. The overall decrease was primarily due to these cost controlling efforts.

Amortization expense was $2.5 million in 2009 compared to $2.2 million in 2008.

Corporate Outlook

Excluding the impact of mark-to-market accounting, the operating loss for 2010 is expected to be higher than the loss reported in 2009. Operating and administrative expenses are expected to be higher than 2009 as a result of the growth of the Trust as well as the cost of converting to a corporation and meeting new financial reporting requirements. The Corporate segment is also expected to report lower earnings from equity investments since Utility Group is no longer reported as an equity investment.

The effects of risk management contracts are based on estimates relating to commodity prices, interest rates and foreign exchange rates over time. The actual amounts will vary based on these drivers and management is therefore unable to predict the impact of financial instruments. However, the impact of the accounting standards is expected to be relatively low as the Trust uses financial instruments to manage exposure to commodity price fluctuations and to buy and sell gas and power with locked-in margins. The Trust does not execute financial instruments for speculative purposes.

INVESTED CAPITAL

During fourth quarter 2009, AltaGas acquired capital assets, long-term investments and other assets of $310.8 million compared to $45.1 million in same quarter 2008. For the full year, AltaGas acquired capital assets, long-term investments and other assets for $497.5 million compared to $824.8 million in 2008.



Net Invested Capital - Investment Type(1) Three Months Ended
December 31, 2009

($ millions) Gas Power Corporate Total
----------------------------------------------------------------------------
Invested capital:
Capital assets 285.3 37.6 0.4 323.3
Long-term investments and other
assets (12.3) (0.3) 1.2 (11.4)
----------------------------------------------------------------------------
Net invested capital 273.0 37.3 1.6 311.9
Disposals:
Capital assets (0.3) (0.7) (0.1) (1.1)
----------------------------------------------------------------------------
Net invested capital 272.7 36.6 1.5 310.8
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----------------------------------------------------------------------------
(1) Certain capital expenditures have been reclassed between segments.


Net Invested Capital - Investment Type Three Months Ended
December 31, 2008

($ millions) Gas Power Corporate Total
----------------------------------------------------------------------------
Invested capital:
Capital assets 30.9 16.2 1.9 49.0
Long-term investments and other
assets - (4.2) 0.3 (3.9)
----------------------------------------------------------------------------
30.9 12.0 2.2 45.1
Disposals:
Capital assets (1.5) - - (1.5)
----------------------------------------------------------------------------
Net invested capital 29.4 12.0 2.2 43.6
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----------------------------------------------------------------------------


Net Invested Capital - Investment Type Year Ended
December 31, 2009

($ millions) Gas Power Corporate Total
----------------------------------------------------------------------------
Invested capital:
Capital assets 324.0 160.3 3.2 487.5
Long-term investments and other
assets (12.3) (0.4) 24.4 11.7
----------------------------------------------------------------------------
311.7 159.9 27.6 499.2
Disposals:
Capital assets (0.2) (0.7) (0.1) (1.0)
----------------------------------------------------------------------------
Net invested capital 311.5 159.2 27.5 498.2
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----------------------------------------------------------------------------


Net Invested Capital - Investment Type Year Ended
December 31, 2008

($ millions) Gas Power Corporate Total
----------------------------------------------------------------------------
Invested capital:
Capital assets 675.1 141.7 6.6 823.4
Long-term investments and other
assets - 0.7 0.7 1.4
----------------------------------------------------------------------------
675.1 142.4 7.3 824.8
Disposals:
Capital assets (10.2) (5.2) - (15.4)
Long-term investments and other
assets - - (48.2) (48.2)
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Net invested capital 664.9 137.2 (40.9) 761.2
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----------------------------------------------------------------------------


The Trust categorizes its invested capital into maintenance, growth and administration.

Growth capital of $307.2 million was incurred in fourth quarter 2009 (fourth quarter 2008 - $41.5 million). In the Gas Segment, growth capital spend in fourth quarter consisted of $259.1 million for the acquisition of NGD assets through the acquisition of Utility Group and Heritage Gas, $1.9 million for various E&T projects, $7.3 million for Harmattan fractionation project, $0.9 million for gas storage projects and $2.2 million for FG&P projects. In the Power Segment, growth capital spent included $28.7 million to complete the Bear Mountain Wind Park, $6.4 million for Harmattan Cogeneration project and $2.2 million to advance renewable energy projects. Included in growth capital under the Corporate Segment is a mark-to-market adjustment of $(1.5) million to fair value the Trust's Magma Energy Corp. (Magma) investment. The growth capital has been financed through increased long-term debt and equity. Administrative and maintenance capital expenditures in fourth quarter 2009 were $3.3 million and $1.4 million, respectively (fourth quarter 2008 - $2.4 million and $1.2 million, respectively).

Growth capital of $490.1 million was expended in 2009 (2008 - $813.5 million). In the Gas Segment, growth capital was comprised of $259.1 million for the acquisition of NGD assets, $17.6 million for the Harmattan fractionation project, $14.2 million for the completion of Sarnia Storage, $8.9 million for various E&T projects and $8.4 million for FG&P projects. Within the Power Segment, growth capital projects included $145.6 million for the completion of Bear Mountain Wind Park, $7.9 million for renewable power development projects and $6.4 million related to the Harmattan Cogeneration project. The Corporate Segment growth capital of $22.0 million was related to the acquisition of shares in Magma Energy Corporation. Administrative and maintenance capital expenditures in 2009 were $5.8 million and $3.3 million, respectively (2008 - $7.6 million and $3.7 million, respectively).



Invested Capital - Use (1) Three Months Ended
December 31, 2009

($ millions) Gas Power Corporate Total
----------------------------------------------------------------------------
Invested capital:
Maintenance 1.4 - - 1.4
Growth 271.4 37.3 (1.5) 307.2
Administrative 0.2 - 3.1 3.3
----------------------------------------------------------------------------
Invested capital 273.0 37.3 1.6 311.9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Certain capital expenditures have been reclassed between segments.


Invested Capital - Use Three Months Ended
December 31, 2008

($ millions) Gas Power Corporate Total
----------------------------------------------------------------------------
Invested capital:
Maintenance 1.2 - - 1.2
Growth 29.5 12.0 - 41.5
Administrative 0.2 - 2.2 2.4
----------------------------------------------------------------------------
Invested capital 30.9 12.0 2.2 45.1
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Invested Capital - Use Year Ended
December 31, 2009

($ millions) Gas Power Corporate Total
----------------------------------------------------------------------------
Invested capital:
Maintenance 3.3 - - 3.3
Growth 308.2 159.9 22.0 490.1
Administrative 0.3 - 5.5 5.8
----------------------------------------------------------------------------
Invested capital 311.8 159.9 27.5 499.2
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Invested Capital - Use Year Ended
December 31, 2008

($ millions) Gas Power Corporate Total
----------------------------------------------------------------------------
Invested capital:
Maintenance 3.7 - - 3.7
Growth 669.0 142.4 2.1 813.5
Administrative 2.4 - 5.2 7.6
----------------------------------------------------------------------------
Invested capital 675.1 142.4 7.3 824.8
----------------------------------------------------------------------------
----------------------------------------------------------------------------


SUBSEQUENT EVENTS

Warrants

On January 1, 2010 AltaGas issued 180,433 units on exercise of special warrants that were originally issued in February 2008 on a one-for-one basis at $24.94 per special warrant.

Landis Energy Corporation

On February 2, 2010 AltaGas offered to acquire all the outstanding common shares of Landis Energy Corporation (Landis) in exchange for cash of $0.80 per common share. The acquisition is valued at approximately $22 million and, if successful, will be funded through AltaGas' existing credit facilities. The offer is subject to certain conditions, including its acceptance by the holders of at least two-thirds of the outstanding common shares of Landis and regulatory approval. The offer is currently due to expire on March 10, 2010.



Consolidated Balance Sheets

(unaudited)

December 31 December 31
($ thousands) 2009 2008
----------------------------------------------------------------------------

ASSETS
Current assets
Cash and cash equivalents $ 3,739 $ 18,304
Short-term investment 19,436 -
Accounts receivable 203,673 220,280
Inventory 1,401 775
Restricted cash holdings from customers 27,228 24,017
Regulatory assets 2,567 -
Risk management 66,271 92,842
Prepaid expenses and other current assets 7,505 7,705
----------------------------------------------------------------------------
331,820 363,923
Capital assets 1,857,095 1,436,686
Energy arrangements, contracts and relationships 128,949 138,913
Goodwill 201,728 143,840
Regulatory assets 60,885 -
Risk management 18,132 31,147
Long-term investments and other assets 30,487 17,744
----------------------------------------------------------------------------
$ 2,629,096 $ 2,132,253
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities $ 158,319 $ 198,232
Distributions payable to unitholders 15,109 12,943
Short-term debt 14,626 4,493
Current portion of long-term debt 591,944 1,363
Customer deposits 30,678 24,017
Deferred revenue - 2,777
Regulatory liabilities 1,403 -
Risk management 34,200 57,423
Other current liabilities 14,831 21,927
----------------------------------------------------------------------------
861,110 323,175
Long-term debt 408,170 559,412
Asset retirement obligations 41,771 41,708
Future income taxes 228,596 211,256
Regulatory liabilities 16,610 -
Risk management 14,491 16,745
Convertible debentures - 16,682
Future employee obligations 9,491 5,833
----------------------------------------------------------------------------
1,580,239 1,174,811
Unitholders' equity 1,048,857 957,442
----------------------------------------------------------------------------
$ 2,629,096 $ 2,132,253
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying note to the Consolidated Financial Statements.


Consolidated Statements of Income
and Accumulated Earnings
(unaudited)


Three Months Ended Year Ended
($ thousands except per unit December 31 December 31
amounts) 2009 2008 2009 2008
----------------------------------------------------------------------------
REVENUE
Operating $ 339,884 $ 414,466 $1,249,649 $1,803,928
Unrealized gain on risk
management (7,206) 9,600 3,697 10,986
Other 3,756 491 14,919 1,881
----------------------------------------------------------------------------
336,434 424,557 1,268,265 1,816,795
----------------------------------------------------------------------------

EXPENSES
Cost of sales 220,993 298,773 811,688 1,340,318
Operating and administrative 56,355 56,064 208,219 221,500
Amortization:
Capital assets 17,818 14,275 64,157 57,075
Energy arrangements,
contracts and relationships 2,491 2,491 9,964 9,903
----------------------------------------------------------------------------
297,657 371,603 1,094,028 1,628,796
----------------------------------------------------------------------------

Foreign exchange gain (loss) (260) 1,120 (1) 1,369
Interest expense
Short-term debt 245 2,321 1,283 2,632
Long-term debt 9,035 5,735 30,476 24,767
----------------------------------------------------------------------------
Income before income taxes 29,237 46,018 142,477 161,969
Income tax expense (recovery)
Current income tax 814 (65) 981 2,328
Future income tax (3,723) 6,456 187 (3,930)
----------------------------------------------------------------------------
Net income 32,146 39,627 141,309 163,571
Accumulated earnings,
beginning of period 782,899 634,356 673,736 510,165
----------------------------------------------------------------------------
Accumulated earnings, end of
period $ 815,045 $ 673,983 $ 815,045 $ 673,736
----------------------------------------------------------------------------
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Net income per unit
Basic $ 0.40 $ 0.55 $ 1.80 $ 2.38
Diluted $ 0.40 $ 0.55 $ 1.79 $ 2.36

Weighted average number of
units outstanding (thousands)
Basic 80,042 71,610 78,540 68,813
Diluted 80,536 72,506 79,371 69,704

See accompanying note to the Consolidated Financial Statements.


Consolidated Statements of Comprehensive Income
and Accumulated Other Comprehensive Income
(unaudited)

Three Months Ended Year Ended
December 31 December 31
($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------

Net income $ 32,146 $ 39,627 $141,309 $163,571

Other comprehensive income (loss),
net of tax
Unrealized net gain on
available-for-sale financial
assets (701) - 3,877 -
Unrealized net gain on derivatives
designated as cash flow hedges 3,027 19,736 15,088 20,560
Reclassification of
available-for-sale financial assets
as a result of business acquisition - - - (17,873)
Reclassification to net income of
net gain (loss) on derivatives
designated as cash flow hedges
pertaining to prior periods (8,622) (700) (29,309) 1,686
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(6,296) 19,036 (10,344) 4,373
----------------------------------------------------------------------------
Comprehensive income $ 25,850 $ 58,663 $130,965 $167,944
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Accumulated other comprehensive
income (loss), beginning of period $ 27,521 $ 12,506 $ 31,569 $ 27,169
Other comprehensive income (loss),
net of tax (6,296) 19,036 (10,344) 4,373
----------------------------------------------------------------------------
Accumulated other comprehensive
income, end of period $ 21,225 $ 31,542 $ 21,225 $ 31,542
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying note to the Consolidated Financial Statements.


Consolidated Statements of Cash Flows
(unaudited)

Three Months Ended Year Ended
December 31 December 31
($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------

Cash from operations
Net income $ 32,146 $ 39,627 $ 141,309 $ 163,571
Items not involving cash:
Amortization 20,309 16,766 74,121 66,978
Accretion of asset retirement
obligations 807 509 3,138 2,302
Unit-based compensation (1,679) 87 (195) 387
Future income tax expense
(recovery) (3,813) 6,456 187 (3,930)
Gain on sale of assets - (320) (28) (2,045)
Equity income 741 (972) (158) (1,388)
Unrealized gain 9,464 (9,600) (9,468) (10,986)
Goodwill impairment 150 100 150 100
Other 111 1,107 2,788 1,801
Non-operating investment income (7,224) - (9,585) -
Asset retirement obligations
settled (239) (345) (384) (744)
Net change in non-cash working
capital (5,341) (15,766) (17,729) (10,891)
----------------------------------------------------------------------------
45,432 37,649 184,146 205,155
----------------------------------------------------------------------------

Investing activities
Increase (decrease) in customer
deposits 1,096 515 (3,211) 352
Decrease in note receivable - - - 6,500
Capital expenditures (84,678) (33,053) (242,970) (143,928)
Disposition of capital assets - 186 - 15,618
Investment in regulatory assets (6,014) - (6,014) -
Distributions from equity
investments 1,080 82 3,236 291
Disposition (acquisition) of
short-term investment 30,540 - (8,198) -
Business acquisition (191,277) (4,577) (191,277) (311,493)
Disposition (acquisition) of
long-term investments
and other assets 565 - (15,658) -
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(248,688) (36,847) (464,092) (432,660)
----------------------------------------------------------------------------

Financing activities
Repayment of short-term debt 14,022 4,348 10,133 942
Net issuance (repayment) of
revolving long-term debt 207,523 21,093 16,132 233,985
Issuance of long-term debt (66) - 295,080 -
Repayment of long-term debt (365) (216) (18,017) (5,792)
Distributions to unitholders (43,173) (38,616) (168,666) (144,348)
Net proceeds from issuance of
units 10,594 9,556 130,719 144,071
Net proceeds from issuance of
warrants - - - 4,500
----------------------------------------------------------------------------
188,535 (3,835) 265,381 233,358
----------------------------------------------------------------------------
Change in cash and cash
equivalents (14,721) (3,033) (14,565) 5,853
Cash and cash equivalents,
beginning of period 18,460 21,337 18,304 12,451
----------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 3,739 $ 18,304 $ 3,739 $ 18,304
----------------------------------------------------------------------------

See accompanying note to the Consolidated Financial Statements.


1. SEGMENTED INFORMATION

AltaGas is an integrated energy trust with a portfolio of assets and services used to move energy from the source to the end-user. The majority of the transactions among the reporting segments are recorded at the market price of the commodities and the remainder is at the exchange amount. In accordance with CICA Handbook Section 1700, for the year ended December 31, 2009, AltaGas has changed the composition of its reportable segments as a result of modifications and growth of the enterprise. Comparative periods have been restated based on the current reportable segments. The following describes the Trust's three reporting segments:



Gas - NGL processing and extraction plants
- transmission pipelines to transport natural gas and NGLs
- natural gas gathering lines and processing facilities
- energy consulting and sale of natural gas and electricity
- natural gas storage facilities
- regulated natural gas distribution assets
----------------------------------------------------------------------------
Power - coal-fired and gas-fired power output under power
purchase arrangements and other agreements
- gas-fired power plants
- wind and run-of-river power plants
----------------------------------------------------------------------------
Corporate - the costs of providing corporate services and general
corporate overhead, investments in public and private
entities, corporate assets and the effects of changes in
the fair value of risk management contracts.

The following tables show the composition by segment:


Three Months Ended Intersegment
December 31, 2009 Gas Power Corporate Elimination Total
----------------------------------------------------------------------------
Revenue $ 332,373 $ (48,330) $ 3,756 $ (40,819) $ 343,640
Unrealized gain
on risk
management - - (7,206) - (7,206)
Cost of sales (238,816) (21,819) - 39,642 (220,993)
Operating and
administrative (43,925) (1,647) (11,960) 1,177 (56,355)
Amortization (17,721) (1,952) (636) - (20,309)
Foreign exchange
loss - - (260) - (260)
Interest expense - - (9,280) - (9,280)
----------------------------------------------------------------------------
Income before
income taxes $ 31,911 $ 22,912 $ (25,586) - $ 29,237
Net additions to:
Capital
assets(1) $ 284,978 $ 36,882 $ 358 - $ 322,218
Long-term
investment and
other assets(2) (12,300) $ (348) $ 1,168 - $ (11,480)
----------------------------------------------------------------------------
Goodwill $ 201,728 - - - $ 201,728
Segmented assets $2,053,177 $ 425,899 $ 150,020 - $2,629,096
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Difference in timing of cash flows, non-cash transactions and assets
acquired in business acquisitions, recorded as acquisition of long-term
investment on statement of cash flow of $237,540.
(2) Difference in timing of cash flows, non-cash transactions and assets
acquired in business acquisitions, recorded as acquisition of long-term
investment on statement of cash flow of $202,192.


Year Ended Intersegment
December 31, 2009 Gas Power Corporate Elimination Total
----------------------------------------------------------------------------
Revenue $1,142,411 $ 188,508 $ 14,919 $ (81,270) $1,264,568
Unrealized gain
on risk
management - - 3,697 - 3,697
Cost of sales (802,262) (86,280) - 76,854 (811,688)
Operating and
administrative (166,433) (6,069) (40,133) 4,416 (208,219)
Amortization (63,427) (8,167) (2,527) - (74,121)
Foreign exchange
gain - - (1) - (1)
Interest expense - - (31,759) - (31,759)
----------------------------------------------------------------------------
Income (loss)
before income
taxes $ 110,289 $ 87,992 $ (55,804) - $ 142,477
----------------------------------------------------------------------------
Net additions to:
Capital
assets(1) $ 323,779 $ 159,544 $ 3,073 - $ 486,396
Long-term
investment and
other assets(2) (12,300) $ (367) $ 24,410 - $ 11,743
----------------------------------------------------------------------------
Goodwill $ 201,728 - - - $ 201,728
Segmented assets $2,053,177 $ 425,899 $ 150,020 - $2,629,096
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Difference in timing of cash flows, non-cash transactions and assets
acquired in business acquisitions, recorded as acquisition of long-term
investment on statement of cash flow of $243,426.
(2) Difference in timing of cash flows, non-cash transactions and assets
acquired in business acquisitions, recorded as acquisition of long-term
investment on statement of cash flow of $195,192.


Three Months Ended Intersegment
December 31, 2008 Gas Power Corporate Elimination Total
----------------------------------------------------------------------------
Revenue $ 366,994 $ 58,168 $ 492 $ (10,697) $ 414,957
Unrealized
gains on risk
management - - 9,600 - 9,600
Cost of sales (287,418) (22,297) - 10,942 (298,773)
Operating and
administrative (40,235) (1,479) (14,105) (245) (56,064)
Amortization (14,272) (1,928) (566) - (16,766)
Foreign
exchange gain - - 1,120 - 1,120
Interest
expense - - (8,056) - (8,056)
----------------------------------------------------------------------------
Income (loss)
before income
taxes $ 25,069 $ 32,464 $(11,515) - $ 46,018
----------------------------------------------------------------------------
Net additions
(reductions) to:
Capital
assets(1) $ 29,441 $ 16,263 $ 1,821 - $ 47,525
Long-term
investment and
other assets(2) - $ (4,229) $ 329 - $ (3,900)
----------------------------------------------------------------------------
Goodwill $ 142,840 - - - $ 142,840
Segmented
assets $1,708,335 $268,474 $155,444 - $ 2,132,253
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Difference in timing of cash flows, non-cash transactions and assets
acquired in business acquisitions, recorded as acquisition of long-term
investment on statement of cash flow of $14,658.
(2) Difference in timing of cash flows, non-cash transactions and assets
acquired in business acquisitions, recorded as acquisition of long-term
investment on statement of cash flow of $8,477.


Year Ended Intersegment
December 31, 2008 Gas Power Corporate Elimination Total
----------------------------------------------------------------------------
Revenue $1,643,187 $223,510 $ 1,882 $ (62,770) $ 1,805,809
Unrealized gain
on risk
management - - 10,986 - 10,986
Cost of sales (1,308,989) (94,518) - 63,189 (1,340,318)
Operating and
administrative (173,230) (3,715) (44,136) (419) (221,500)
Amortization (57,306) (7,436) (2,236) - (66,978)
Foreign
exchange gain - - 1,369 - 1,369
Interest
expense - - (27,399) - (27,399)
----------------------------------------------------------------------------
Income (loss)
before income
taxes $ 103,662 $117,841 $ (59,534) - $ 161,969
----------------------------------------------------------------------------
Net additions to:
Capital
assets(1) $ 664,847 $136,523 $ 6,592 - $ 807,962
Energy
services
arrangements,
contracts and
relationships $ 53,000 - - - $ 53,000
Long-term
investment and
other assets(2) - $ 713 $ (47,479) - $ (46,766)
----------------------------------------------------------------------------
Goodwill $ 143,840 - - - $ 143,840
Segmented
assets $1,708,335 $268,474 $ 155,444 - $ 2,132,253
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Difference in timing of cash flows, non-cash transactions and assets
acquired in business acquisitions, recorded as acquisition of long-term
investment on statement of cash flow of $679,652.
(2) Difference in timing of cash flows, non-cash transactions and assets
acquired in business acquisitions, recorded as acquisition of long-term
investment on statement of cash flow of $358,259.


Supplementary Quarterly Financial Information
(unaudited)

($ millions unless otherwise indicated) 2009 Q4-09 Q3-09 Q2-09 Q1-09
----------------------------------------------------------------------------
FINANCIAL HIGHLIGHTS(1)
Net Revenue(2)
----------------------------------------------------------------------------
Gas 340.1 93.6 81.4 81.1 84.1
Power 102.3 26.5 24.8 23.4 27.5
Corporate 18.6 (3.5) 9.5 11.3 1.2
Intersegment Elimination (4.4) (1.2) (1.0) (1.5) (0.7)
----------------------------------------------------------------------------
456.6 115.4 114.7 114.3 112.1
----------------------------------------------------------------------------

EBITDA(2)
----------------------------------------------------------------------------
Gas 173.7 49.6 40.8 39.9 43.4
Power 96.2 24.9 23.4 21.9 26.0
Corporate (21.5) (15.7) (0.6) 1.8 (7.1)
----------------------------------------------------------------------------
248.4 58.8 63.6 63.6 62.3
----------------------------------------------------------------------------

Operating Income (Loss)(2)
----------------------------------------------------------------------------
Gas 110.3 32.0 25.3 24.6 28.4
Power 88.0 22.9 21.4 19.6 24.1
Corporate (24.0) (16.1) (1.3) 1.3 (7.8)
----------------------------------------------------------------------------
174.3 38.8 45.4 45.5 44.7
----------------------------------------------------------------------------
(1) Columns may not add due to rounding.
(2) Non-GAAP financial measure.


Supplementary Quarterly Operating Information

(unaudited)

2009 Q4-09 Q3-09 Q2-09 Q1-09
----------------------------------------------------------------------------
OPERATING HIGHLIGHTS
Gas
Extraction inlet gas processed
(Mmcf/d)(1) 841 844 839 798 882
Extraction volumes (Bbls/d)(1) 40,053 39,812 38,222 39,334 42,898
Transmission volumes
(Mmcf/d)(1)(3) 324 320 332 345 348
Frac spread - realized
($/Bbl)(1)(4) 23.46 25.96 20.55 22.05 25.29
Frac spread - average spot
price ($/Bbl)(1)(4) 19.51 26.87 19.74 16.34 15.20
Processing Capacity (gross
Mmcf/d)(2) 1,172 1,172 1,172 1,172 1,172
Processing Throughput (gross
Mmcf/d)(1) 453 423 433 475 480
Processing Capacity
utilization (%)(1) 39 39 37 41 41
Deliveries- end-use (PJ)(5)(6) 6.62 6.62 - - -
Deliveries - transportation
(PJ) (5) (6) 0.55 0.55 - - -
Service sites at year-end (7) 72,717 72,717 - - -
Degree day variance (%)(8) 9.9 9.9 - - -
Energy management service
contracts(2) 1,748 1,748 1,727 1,727 1,707
Average volumes transacted
(GJ/d)(1) 354,513 377,580 329,192 287,315 374,113
Power
Volume of power sold (GWh)(1) 2,726 707 683 672 664
Average price realized on sale
of power ($/MWh)(1) 68.34 67.54 70.22 63.84 74.33
Alberta Power Pool average
spot price ($/MWh)(1) 47.84 46.32 49.75 32.31 63.01
----------------------------------------------------------------------------
(1) Average for the period.
(2) As at period end.
(3) Excludes natural gas liquids pipeline volumes.
(4) AltaGas reports an indicative frac spread or NGL margin, expressed in
dollars per barrel of NGL, which is derived from Edmonton postings for
propane, butane and condensate and the daily AECO natural gas price.
(5) Petajoule (PJ) is one million gigajoules (GJ)
(6) Deliveries reflect AltaGas' 100 percent share in AUGI and Heritage Gas
as at October 8 and November 18, 2009 respectively.
(7) Service sites reflect all the service sites of AUI, Heritage Gas and
Inuvik Gas.
(8) Degree days relate to AUI's service area. A degree day is the
cumulative extent to which the daily mean temperature falls below 15
degrees Celsius. Normal degree days are based on a 20-year rolling
average. Positive variances from normal lead to increased delivery
volumes from normal expectations.


Other Information

DEFINITIONS

Bbls/d barrels per day
Bcf billion cubic feet
GJ gigajoule
GWh gigawatt-hour
Mcf thousand cubic feet
Mmcf/d million cubic feet per day
MW megawatt
MWh megawatt hour
PJ one million gigajoules (GJ)


ABOUT ALTAGAS

AltaGas Income Trust is one of Canada's largest and fastest growing integrated energy infrastructure organizations. The Trust creates value by growing and optimizing gas and power infrastructure, including a focus on renewable energy sources.

AltaGas Income Trust's units are listed on the Toronto Stock Exchange under the symbol ALA.UN. The Trust is included in the S&P/TSX Composite Index, the S&P/TSX Income Trust Index and the S&P/TSX Capped Energy Trust Index.

Contact Information