AltaGas Income Trust
TSX : ALA.UN

AltaGas Income Trust

February 26, 2009 08:00 ET

AltaGas Reports Record Earnings in 2008

CALGARY, ALBERTA--(Marketwire - Feb. 26, 2009) - AltaGas Income Trust (AltaGas or the Trust) (TSX:ALA.UN) today announced 2008 net income of $163.6 million ($2.38 per unit - basic) compared to $108.8 million ($1.90 per unit - basic) in 2007.

Net income for the three months ended December 31, 2008 was $39.6 million ($0.55 per unit - basic), compared to $31.8 million ($0.55 per unit - basic) for the same period of 2007.

"Our strong fourth quarter results reflect our solid business, financial strength and commitment to disciplined risk management," said David Cornhill, Chairman and CEO of the Trust. "In 2008, we significantly advanced our growth strategy through the acquisition and integration of Taylor and the further expansion of our portfolio of renewable energy projects. We will continue to build on these achievements and seek further opportunities to grow our business and create long-term value for our investors."

"We have dramatically improved our ability to navigate through these tough economic times and to react to future opportunities by issuing $100 million of equity and terming out $250 million of debt that was to come due later this year," added Mr. Cornhill. "The strength of our asset mix, imminent completion of several major projects, and new growth opportunities positions AltaGas well for strong results in 2009. We are also well positioned for 2010 as our new projects coming on line in 2009 will contribute a full year's earnings in 2010."

AltaGas declared a distribution of $0.18 per trust unit and exchangeable unit payable on April 15, 2009 to unitholders of record on March 25, 2009. The Trust declared total cash distributions of $0.54 per unit in fourth quarter 2008.

The majority of AltaGas' revenues are underpinned by contractual arrangements that provide stable and predictable cash flow. Sixty percent of 2009 volumes exposed to fractionation (frac) spreads have been hedged at more than $27/Bbl. As of year-end, AltaGas has hedged approximately two-thirds of its base-load Sundance power generation for 2009 at prices similar to the 2008 average hedge price. Management expects strong spot power prices in Alberta to continue through 2009, largely as a result of power reserve margins, which are expected to remain around 10 percent. In addition, the Trust continues to optimize current operations and develop new assets. The volume additions and efficiency enhancements at the Harmattan Complex, as well as the Bear Mountain Wind Park, the expansion of the Pouce Coupe facility and Sarnia gas storage project, will contribute to earnings and cash flow in 2009.

FINANCIAL HIGHLIGHTS(1):

- Earnings before interest, taxes, depreciation and amortization (EBITDA) were $70.9 million ($0.99 per unit) in the fourth quarter compared to $40.3 million ($0.70 per unit) in the same quarter in 2007. EBITDA for full year 2008 was $256.4 million ($3.73 per unit), compared to $173.7 million ($3.03 per unit) in 2007.

- Funds from operations were $53.8 million ($0.75 per unit) for fourth quarter 2008, compared to $37.8 million ($0.65 per unit) for the same period in 2007. Funds from operations for the year were $217.1 million ($3.16 per unit), up from $162.9 million ($2.84 per unit) in 2007.

- Total debt on December 31, 2008 was $582.0 million, compared to $220.7 million at December 31, 2007. The Trust's debt-to-total capitalization ratio as at December 31, 2008 was 37.8 percent versus 27.4 percent at the end of 2007.

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

Net income in 2008 increased over 2007 as a result of the increased energy infrastructure assets from the Taylor acquisition and higher power prices. Net income was negatively impacted by turnarounds at four extraction facilities in 2008, which resulted in lower earnings of approximately $8.0 million. Interest costs were higher compared to 2007 due to the increased debt as a result of the Taylor acquisition. Excluding the $11.8 million reduction in future tax liability and $5.6 million after-tax gain on risk management contracts, net income was $146.2 million ($2.13 per unit - basic). Excluding the SIFT tax of $5.4 million and $6.1 million non-cash tax benefit due to the reduced federal tax rates recorded in 2007, net income for 2007 was $108.1 million ($1.88 per unit - basic). On a comparable basis, net income increased 33 percent year over year.

Net income in fourth quarter 2008 increased over the same period last year as a result of the increased energy infrastructure assets from the Taylor acquisition and strong results from the power business from higher power prices. Excluding the after-tax gain of $6.1 million related to risk management contracts, net income for fourth quarter was $33.5 million ($0.47 per unit - basic). Excluding a $6.1 million non-cash tax recovery due to reduced federal tax rates enacted in the fourth quarter 2007, net income for fourth quarter 2007 was $25.7 million ($0.53 per unit - basic). On a comparable basis, net income increased 30 percent in fourth quarter 2008 versus the same quarter in 2007.

SUBSEQUENT TO THE FOURTH QUARTER:

- On January 7, 2009, AltaGas acquired a wind development project for approximately $2 million. The development assets are located near Medicine Hat, Alberta and are expected to provide AltaGas with the potential to develop approximately 100 MW of wind power generation.

- On January 15, AltaGas invested $10 million to acquire a five percent equity position in Magma Energy Corp.,a private company focused on the exploration, development and operation of geothermal energy projects. AltaGas also received the right to acquire a direct interest in certain future geothermal projects developed or acquired by the company. Magma Energy Corp. currently owns and operates an 8 MW geothermal energy plant in Nevada as well as a portfolio of geothermal exploration and development projects in the western United States, Argentina, Chile, Nicaragua and Peru.

- AltaGas successfully completed an equity offering of 6,100,000 Trust units at a price of $16.50 per Trust unit, representing gross proceeds of approximately $100 million. The proceeds from this issue were used to repay indebtedness.

- AltaGas secured commitments for a new $250 million credit facility with a syndicate of banks. The credit facility will be used to retire an existing $250 million credit facility that would have matured in September 2009. Closing of the new credit facility is expected during the first week of March 2009. The facility has an 18-month term expiring in August, 2010.

AltaGas will hold a conference call today at 9 a.m. MT (11 a.m. ET) to discuss the fourth quarter and full year 2008 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 416-406-6419 or call toll-free at 1 888 575 8232. No pass code is required. Please note that the conference call will also be webcast. To listen, please connect here: http://events.onlinebroadcasting.com/altagas/022609/index.php.

Shortly after the conclusion of the call, a replay will be available by dialling 416-695 5800 or 1 800 408 3053. The passcode is 3282474. The replay expires at midnight (ET) on March 5, 2009. The webcast will be archived for one year.

Management's Discussion and Analysis

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 3, 2009, 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 in respect of the Trust's overall capital outlook as it relates to the various projects under development by the Trust under the heading "Consolidated Outlook". In addition, such forward-looking statements are set forth under the headings "Gas Business Outlook", "Power Business Outlook" and "Capital Projects".

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 particular segment's actual results, performance or achievements to vary from those described in this MD&A, including without limitation those listed above and 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 MD&A as intended, planned, anticipated, believed, sought, proposed, estimated or expected, and such forward-looking statements included in this MD&A 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 MD&A are expressly qualified as cautionary statements.

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 audited financial statements, Annual Information Form, Information Circular, Business Acquisition Report 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 Years Ended
December 31 December 31
($ millions) 2008 2007 2008 2007
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Revenue 424.6 336.5 1,816.8 1,428.4
Unrealized gains (losses) on risk
management 9.6 (0.5) 11.0 1.1
Net revenue(1) 125.8 76.4 476.5 324.0
EBITDA(1) 70.9 40.3 256.4 173.7
EBITDA before unrealized gains on
risk management(1) 61.3 40.8 245.4 172.6
Operating income(1) 54.1 28.9 189.4 126.6
Operating income before unrealized
gains on risk management(1) 44.5 29.4 178.4 125.5
Net income 39.6 31.8 163.6 108.8
Net income before tax-adjusted
unrealized gains on risk
management(1) 33.5 32.5 158.0 109.3
Net income before tax(1) 46.0 26.0 162.0 114.7
Total assets 2,163.6 1,172.7 2,163.6 1,172.7
Total long-term liabilities 857.5 313.5 857.5 313.5
Net additions to capital assets 47.5 29.8 808.0 21.8
Distributions declared(2) 38.7 30.5 147.1 118.6
Cash flows
Cash from operations 37.7 59.8 205.4 183.3
Funds from operations(1) 53.8 37.8 217.1 162.9
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Three Months Ended Years Ended
December 31 December 31
($ per unit) 2008 2007 2008 2007
----------------------------------------------------------------------------
EBITDA(1) 0.99 0.70 3.73 3.03
EBITDA before unrealized gains on
risk management(1) 0.86 0.70 3.57 3.01
Net income - basic 0.55 0.55 2.38 1.90
Net income - diluted 0.55 0.55 2.36 1.89
Net income before tax-adjusted
unrealized gains on risk
management(1) 0.47 0.56 2.30 1.90
Net income before tax(1) 0.64 0.45 2.35 2.00
Distributions declared(2) 0.54 0.525 2.125 2.065
Cash flows
Cash from operations 0.53 1.03 2.98 3.19
Funds from operations(1) 0.75 0.65 3.16 2.84
Units outstanding - basic
(millions)
During the period(3) 71.6 58.0 68.8 57.4
End of period 71.9 58.1 71.9 58.1
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(1) Non-GAAP financial measure. Please see previous public disclosures.
(2) Distributions declared of $0.18 per unit per month commencing in August
2008. From August 2007 to July 2008 distributions of $0.175 per unit per
month were declared. From January 2007 to July 2007 distributions of
$0.17 per unit per month were declared.
(3) Weighted average.


CONSOLIDATED FINANCIAL REVIEW

Fourth Quarter

Financial results in fourth quarter 2008 were higher than the same quarter 2007 as net income increased by 25 percent. The gas business results represented strong operating performance from the increased asset base due to the acquisition of Taylor NGL Limited Partnership (Taylor) in January 2008. The power business also delivered strong results in the fourth quarter from higher power prices reflecting the impact of the Trust's disciplined hedging strategy, as well as higher spot power prices.

Net income for the three months ended December 31, 2008 was $39.6 million ($0.55 per unit - basic) compared to $31.8 million ($0.55 per unit - basic) for the same period in 2007. Excluding the after-tax gain of $6.1 million related to risk management contracts, net income for fourth quarter was $33.5 million ($0.47 per unit - basic). Excluding a $6.1 million non-cash tax recovery due to reduced federal tax rates enacted in fourth quarter 2007, net income for fourth quarter 2007 was $25.7 million ($0.44 per unit - basic).

In fourth quarter 2008, operating income across all segments increased 87 percent to $54.1 million from $28.9 million.

Operating income from the gas business was $25.0 million in fourth quarter 2008 compared to $16.4 million in same quarter 2007. Operating income increased primarily due to the larger energy infrastructure asset base as a result of the Taylor acquisition in January 2008, new facilities in the Field Gathering and Process (FG&P) segment and higher rates, partially offset by natural declines in certain FG&P operating areas. In the FG&P segment, planned downtime at Bantry and operational issues at Rainbow Lake resulted in $1.5 million impact on operating income.

In the power business, operating income was $32.5 million in fourth quarter 2008 compared to $20.4 million in fourth quarter 2007. Operating income increased due to higher power prices, lower PPA costs and higher contributions from gas-fired peaking plants, partially offset by higher transmission costs.

The operating loss in the corporate segment decreased primarily due to unrealized gains in the fair value of risk management contracts, partially offset by lower investment income and higher general and administrative costs due to the Taylor acquisition, overall escalating costs and higher costs to support the growth of the Trust including approximately $2.0 million in non-recurring costs.

On a consolidated basis, net revenue for fourth quarter 2008 was $125.8 million compared to $76.4 million in same quarter 2007. In the gas business, net revenue increased due to additional extraction, processing and transmission facilities and higher operating cost recoveries. These increases were partially offset by lower volume throughput in certain FG&P areas. In the power business, net revenue increased due to higher prices received on both spot sales and hedged volumes, lower PPA costs and higher contributions from gas-fired peaking plants, partially offset by higher transmission costs. In addition, an unrealized gain of $9.6 million related to the fair value of risk management contracts increased net revenue.

Operating and administrative expense for fourth quarter 2008 was $54.9 million, up from $36.2 million in same quarter in 2007. The increase was primarily a result of new and expanded facilities in the gas business and increased costs to support the growth of the Trust and overall escalating costs including approximately $2.0 million in non-recurring costs related to technology support.

Amortization expense for fourth quarter 2008 was $16.8 million compared to $11.4 million in the same quarter last year. The increase was due to the additional facilities acquired in 2008.

Interest expense for fourth quarter 2008 was $8.1 million compared to $2.9 million in same quarter 2007. The increase was due to higher average debt balances of $581.6 million in the fourth quarter of 2008 compared to $218.6 million for the same period in 2007 and higher average interest rates period-over-period. The average effective interest rate was 6.3 percent in fourth quarter 2008 compared to 5.5 percent for fourth quarter 2007 due to the Trust unwinding a bond forward hedge and recording incremental interest expense of approximately $2.0 million.

Income tax expense in fourth quarter 2008 was $6.4 million compared to income tax recovery of $5.8 million in the same period 2007. The increase was primarily due to $6.1 million related to the lower federal corporate income tax rates enacted in 2007, $3.2 million due to unrealized gains on risk management contracts, $1.5 million due to true up of tax asset balances and $1.4 million due to higher earnings.

Full Year 2008

Financial results for 2008 reflect the strong operating performance of AltaGas' energy infrastructure assets. In 2008 the Trust increased its assets by approximately $600 million as a result of the Taylor acquisition. The Trust also completed approximately $50 million of growth and enhancement initiatives in late 2008 at the Harmattan Complex. Net income increased by 50 percent year-over-year. The gas and power businesses each reported year-over-year operating income increases of 75 percent and 25 percent, respectively. The gas business reported strong results despite turnarounds at five extraction facilities in 2008, which resulted in lost revenues of $3.7 million, operating costs of $4.3 million, a major turnaround at one field processing facility which resulted in $1.0 million in lower operating income. The power business reported strong results due to higher power prices received on both spot and hedged sales as well as higher contributions from the gas-fired peaking plants. The Trust recorded higher interest costs due to the increased debt balance as a result of the Taylor acquisition and lower taxes primarily as a result of changes within the Trust's legal structure.

Net income in 2008 was $163.6 million ($2.38 per unit - basic) compared to $108.8 million ($1.90 per unit - basic) in 2007. Excluding a $11.8 million reduction in future tax liability related to changes in the Trust structure and a $5.6 million after-tax gain on risk management contracts, net income was $146.2 million ($2.13 per unit - basic). Excluding the Specified Investment Flow-Through (SIFT) tax of $5.4 million and a $6.1 million non-cash tax benefit due to the reduced federal tax rates recorded in 2007, net income in 2007 was $108.1 million ($1.88 per unit - basic).

Operating income across all segments increased by 50 percent to $189.4 million in 2008 compared to $126.6 million in 2007.

Operating income from the gas business was $103.6 million in 2008 compared to $59.3 million in 2007. In the power business, operating income was $117.9 million in 2008 compared to $94.6 million in 2007. In 2008 operating income from the gas and power businesses was 47 percent and 53 percent, respectively, of total business operating income compared to 39 percent and 61 percent, respectively, for 2007. The improved balance between the gas and power businesses reflects the impact of the Trust's strategy to have a more balanced portfolio of assets.

In the gas business, operating income increased mainly due to the larger energy infrastructure asset base as a result of the Taylor acquisition, higher rates and other revenues in FG&P and higher frac spreads, partially offset by lower throughput due to declines, planned and unplanned downtime in certain FG&P areas and lower volumes processed at the extraction plants owned prior to January 2008. The gas business reported strong results despite approximately $10.0 million impact of five extraction plant turnarounds, planned and unplanned downtime at some field processing facilities and a fire at the Harmattan Complex.

In the power business, operating income increased due to higher average power prices, higher contributions from the peaking plants, a deferral account settlement from the Alberta Electric System Operator (AESO) and a gain on the sale of one of the Trust's power development projects, partially offset by a more favourable 30-day rolling average power price (RAPP) in 2007, higher transmission costs and higher environmental compliance costs.

The operating loss in the corporate segment increased primarily due to higher costs to support the growth of the Trust, general cost escalations and lower investment income, partially offset by the unrealized gain reported on risk management contracts. In 2008 the Trust incurred approximately $2.0 million in non-recurring technology costs.

Consolidated net revenue for 2008 was $476.5 million compared to $324.0 million in 2007. In the gas business, net revenue increased due to the addition of extraction, processing and transmission facilities, higher operating cost recoveries, higher rates and other revenues in FG&P and higher frac spreads. These increases were partially offset by lower throughput in certain FG&P areas, the sale of non-core assets in mid-2007, lower fixed-price gas and transport sales and lower volumes processed at the extraction plants owned prior to January 2008. In the power business, net revenue increased due to higher average price received on the sale of power, higher contributions from the peaking plants, a deferral account settlement from the AESO and the gain on sale of a power development project, partially offset by a higher RAPP in 2007, higher transmission and environmental compliance costs.

Operating and administrative expense for 2008 was $220.1 million, compared to $150.3 million in 2007. The increase was due to costs related to new facilities, turnaround costs and higher compensation and administrative costs. Operating costs included approximately $8.0 million related to turnaround costs incurred during the year. Approximately 36 percent was recovered. Administrative costs included approximately $2.0 million in non-recurring technology costs.

Amortization expense for 2008 was $67.0 million, compared to $47.1 million in 2007. The increase was primarily due to new and expanded facilities in the gas business, partially offset by the disposition of non-core assets in second quarter of 2007.

Interest expense in 2008 was $27.4 million, compared to $11.9 million in 2007. The increase was primarily due to higher average debt balances of $581.0 million in 2008, compared to $234.9 million in 2007. The average borrowing rate for 2008 was 5.3 percent which was consistent with 2007. Included in interest expense in 2008 was approximately $2.0 million as a result of the termination of a bond forward contract.

Income tax recovery for 2008 was $1.6 million, compared to income tax expense of $5.9 million in 2007. Income tax expense was lower as a result of certain tax planning initiatives undertaken by management in 2008. The income tax expense was lower by $11.8 million as a result of applying a lower tax rate to the future income tax liability that arose from changes in the legal entity structure of the Trust. This internal reorganization had the added benefit of reducing income tax expense by $13.3 million through use of higher intercompany interest offset by income taxes of $12.0 million due to higher operating income. The lower 2008 income tax expense was partially offset by $2.3 million in current taxes from the sale of a power project, $1.7 million due to higher mark-to-market gains on risk management contracts and $1.5 million due to an adjustment for the tax asset basis of the Trust. For comparative purposes, the enactment of the Specified Investment Flow-Through (SIFT) tax during 2007 increased income tax expense by $5.3 million. Later in the same year, income tax expense was reduced by $5.4 million due to the federal income tax rate reductions.

Assuming a unit was held throughout 2008, for income tax purposes the Trust expects 87.7 percent of the total distributions declared in 2008 to be taxed as property income, 0.2 percent as dividend income and 12.1 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.

Consolidated Outlook

AltaGas is well positioned to deliver another year of strong results in 2009, despite a challenging economic environment. The majority of the Trust's earnings are underpinned by long-term, fee-for-service, cost-of-service or minimum volume commitment contracts. To the extent that the Trust is exposed to frac spreads and power prices in Alberta, the Trust has a disciplined hedging strategy which mitigates the impact of frac spread and power price volatility. The diversified suite of assets contributes to earnings stability as the impact of commodity price exposures in the gas and power businesses often offset each other. In the gas business results are expected to be flat in 2009 compared to 2008 as lower frac spreads are offset by the earnings and cash flow contribution from the 2008 and 2009 capital projects as well as fewer turnarounds and increased plant reliability. The power business results are expected to be lower based on the current forward spot price for power but partly offset by the contribution from the new peaking plants which came on line in late 2008 and the Bear Mountain Wind Park which is expected to be in service in November 2009.

The Trust is also well positioned to take advantage of growth opportunities as they arise. The $100 million equity issuance which closed on February 10, 2009 reduced the Trust's debt to total capitalization from 37.8 percent as at December 31, 2008 to 32 percent on a proforma basis. In February 2009, the Trust secured commitments for a new $250 million revolving and term credit facility to replace the Trust's $250 million credit facility that was scheduled to mature in September 2009. The new facility matures August 2010. The stronger balance sheet and increased liquidity and flexibility provide the Trust with the ability to capitalize on growth opportunities to enhance returns to unitholders at a time when other market participants may be capital constrained. AltaGas expects to term out a portion of its bank credit facilities in 2009 to further improve its financial liquidity and flexibility.

Gas Business Outlook

In 2009 the gas business is expected to deliver another year of strong results similar to 2008. Weakness in frac spreads and lower producer activity are expected to be offset by the contribution from capital expenditures at the Harmattan Complex, the Ethylene Delivery System (EDS) upgrade, the Sarnia Storage project, the expansion of the Pouce Coupe facility as well as opportunities to consolidate plants and grow volume throughput in areas that are experiencing drilling activity. In 2009 there is one planned turnaround in the FG&P segment expected to cost approximately $1 million compared to 2008 plant turnarounds in both FG&P and extraction which cost approximately $5 million. The gas business is also expected to benefit from initiatives such as the Bantry acid gas injection project and initiatives at the Harmattan Complex and Rainbow Lake facility which are expected to improve reliability and efficiency.

Power Business Outlook

In 2009 almost two-thirds of the power delivered to the Alberta Power Pool from the Sundance plant is hedged at $76 similar to hedge prices in 2008. Current lower spot prices in the mid-$70s range are expected to result in lower earnings on the unhedged volumes and management believes that the average power demand in Alberta will be relatively flat in 2009. The power business is also expected to incur higher costs as work progresses on developing its portfolio of renewable projects. The increased peaking capacity installed in late 2008 and the Bear Mountain Wind Park expected to be in service in November 2009 are expected to partially offset the lower earnings in the power business. Even with the lower spot prices, AltaGas expects the power business to have its second best year of financial performance.

GLOBAL MARKET CONDITIONS

Global financial markets have recently experienced severe turmoil; however AltaGas' financial position and ability to generate cash in the short and long terms from its operations remain strong. The Trust also has good access to capital markets. In February 2009, the Trust issued trust units for gross proceeds of approximately $100 million and secured commitments for a new $250 million revolving and term credit facility. AltaGas' access to capital markets was also demonstrated with its 2008 funding program which consisted of a trust unit issue valued at approximately $115 million in June 2008 and a $250 million credit facility in March 2008, which will be replaced with the new facility secured in February 2009. In addition, trust units issued under the Trust's Distribution Reinvestment and Optional Unit Purchase Plan (DRIP) are expected to raise approximately $35 million in 2009.

The Trust's liquidity position remains sound, underpinned by highly predictable cash flow from operations, as well as revolving bank lines of $750 million, of which $326 million was available as at December 31, 2008 and high participation in the DRIP. Subsequent to the equity issuance, the Trust has approximately $100 million in incremental available bank lines.

Management has completed analyses of recent market conditions on both defined benefit pension plans and impairment testing for goodwill and intangible assets. All analyses concluded that no material adjustment is required.

CAPITAL PROJECTS

The outlook for 2009 capital expenditures is approximately $250 million with committed spending of approximately $200 million. The total of $250 million is expected to be split approximately 28 percent to gas and 72 percent to power projects. The majority of the $200 million of committed spending is to complete the construction of the Bear Mountain Wind Park.

Capital expenditures for 2010 have not yet been finalized. The Trust is pursuing many growth opportunities, however capital commitments for 2010 are subject to the economic environment and AltaGas' ability to create long-term unitholder value. As capital projects are approved and committed, AltaGas will update the capital outlook for 2010.

Gas Projects

Harmattan Co-stream Project

The proposed Harmattan Co-stream Project is expected to bring natural gas from the NOVA Gas Transmission Limited (NGTL) system to the Harmattan Complex for processing to recover ethane, propane, butane and condensate. The NGL Extraction Inquiry hearing held by the Alberta Energy Resources Conservation Board (ERCB) concluded at the end of September 2008 and the ERCB provided its ruling in February 2009. The ERCB has stated that proposed co-streaming and side-streaming projects, such as the Harmattan Co-stream Project, will be assessed on an individual basis by the ERCB. Furthermore, the entitlement to the NGL within the common-stream natural gas transported on Alberta-regulated gas transmission pipelines will be transferred over the next three years to receipt shippers who hold receipt capacity (capacity that gives the shipper the right to place natural gas on the NGTL system), rather than the current convention that gives export delivery transporters the rights to the NGL in the common stream. This change will provide AltaGas the opportunity to negotiate competitive pricing and terms to receipt shippers such that they can access the value of their NGL through the Harmattan Complex. With the NGL Inquiry now concluded, AltaGas will resubmit the application for its Harmattan Co-stream Project in the coming months. Upon approval, construction of the project will commence, requiring approximately 14 months to complete. The project, as currently envisioned, is expected to cost in the range of $100 million to $120 million and is expected to begin contributing to operating income in late 2010.

Power Projects

Hydroelectric

AltaGas is developing a portfolio of run-of-river hydroelectric projects in British Columbia. The largest of these is the 195-MW Forrest Kerr run-of-river hydroelectric project in northwest B.C. In addition AltaGas is in the early stages of developing the McLymont Creek (66 MW) and Volcano Creek (16 MW) run-of-river projects. These three projects were submitted to BC Hydro in late 2008 as part of the Clean Power Call competition to supply electricity. Management understands that BC Hydro intends to respond to the submission to the Clean Power Call by mid-2009. Should AltaGas be successful in contracting with BC Hydro for these projects, it is expected they will be in service sometime from 2014 through 2016.

AltaGas also has under development a number of smaller run-of-river hydroelectric projects in British Columbia with a combined capacity of approximately 70 MW.

Wind

Through a series of acquisitions, AltaGas has the potential of developing approximately 1,500 MW of wind power projects in western Canada and the northern and western United States. The portfolio of wind assets includes 200 MW in mature stage development, including Bear Mountain and 1,300 MW in early-stage development. Of the 1,500 MW total potential development, 600 MW are in Canada and the remainder are in the United States.



RESULTS OF OPERATIONS BY SEGMENT

Operating Income Three Months Ended Years Ended
December 31 December 31
($ millions) 2008 2007 2008 2007
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Extraction and Transmission 22.2 11.9 83.8 39.1
Field Gathering and Processing 3.1 4.5 20.4 18.2
Energy Services (0.3) - (0.6) 2.0
Power Generation 32.5 20.4 117.9 94.6
Corporate (3.4) (7.9) (32.1) (27.3)
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54.1 28.9 189.4 126.6
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EXTRACTION AND TRANSMISSION

The Extraction and Transmission (E&T) segment consists of interests in six ethane and NGL extraction plants, five natural gas and three NGL transmission systems. As a result of the Taylor acquisition in January 2008, AltaGas added an interest in the Younger Extraction Plant in British Columbia, acquired the Harmattan Complex, the EDS and Joffre Feedstock Pipeline (JFP) in Alberta and increased its ownership in the Joffre Extraction Plant to 100 percent from 50 percent.



Financial Results Three Months Ended Years Ended
December 31 December 31
($ millions) 2008 2007 2008 2007
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Revenue 98.1 39.3 430.1 142.9
Net revenue 42.7 19.3 176.2 67.4
Operating and administrative
expense 13.7 5.5 65.1 20.3
Amortization expense 6.8 1.9 27.3 8.0
Operating income 22.2 11.9 83.8 39.1
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Operating Statistics Three Months Ended Years Ended
December 31 December 31
2008 2007 2008 2007
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Extraction inlet gas processed
(Mmcf/d)(1) 790 534 801 436
Extraction ethane volumes
(Bbls/d)(1) 23,892 14,259 24,795 13,355
Extraction NGL volumes (Bbls/d)(1) 11,534 6,921 12,242 6,752
Total extraction volumes (Bbls/d)(1) 35,426 21,180 37,037 20,107
Frac spread - realized ($/Bbl)(1)(2) 28.41 29.03 26.97 21.38
Frac spread - average spot price
($/Bbl)(1) 18.58 31.84 28.79 22.48
Transmission volumes (Mmcf/d)(1)(3) 367 403 379 407
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Average for the period.
(2) 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.
(3) Excludes natural gas liquids pipeline volumes.


Fourth Quarter

In fourth quarter 2008, the E&T segment accounted for approximately 39 percent of operating income from the operating segments compared to 32 percent in fourth quarter 2007. Operating income in fourth quarter 2008 was $22.2 million compared to $11.9 million reported for the same period in 2007. The primary contributor to the increase in operating income was the addition of new extraction and transmission facilities with the Taylor acquisition.

In fourth quarter 2008, average spot frac spreads declined to $18.58/Bbl from $36.92 in third quarter 2008. AltaGas' hedging strategy mitigated the impact of the volatility in spot frac spread and resulted in realized frac spread for fourth quarter of $28.41/Bbl. The overall impact of lower frac spread on volumes from assets owned prior to the Taylor acquisition was $1.6 million. As a result of contractual arrangements in place, AltaGas was able to shut-in production of NGL at plants where it was uneconomic to produce. Production was shut in at the JEEP facility in December and a turnaround originally scheduled for second quarter 2009 was completed in December. The cost of the turnaround was $0.7 million, approximately 70 percent of which was recovered from customers.

Average ethane and NGL volumes in the extraction business increased 67 percent in fourth quarter 2008 compared to same quarter 2007, mainly due to the addition of the Harmattan Complex, Younger Extraction Plant and the remaining 50 percent ownership in the Joffre Extraction Plant. Natural gas volumes transported in the transmission business during the fourth quarter 2008 decreased from the same quarter in 2007 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.

Net revenue in fourth quarter 2008 more than doubled to $42.7 million, up from $19.3 million in the same period in 2007. Net revenue increased by $20.5 million primarily as a result of the extraction and transmission assets acquired with Taylor.

Operating and administrative expense in fourth quarter 2008 was $13.7 million compared to $5.5 million for the same period in 2007. The increase was mainly due to the costs incurred to operate the new facilities.

Amortization expense in fourth quarter 2008 was $6.8 million compared to $1.9 million for the same period in 2007. The increase was due to additional assets from the Taylor acquisition.

Full Year 2008

Operating income in the E&T segment for 2008 was $83.8 million compared to $39.1 million in 2007. The primary contributors to the increase in operating income was the addition of new extraction and transmission facilities with the Taylor acquisition in January 2008, higher realized frac spreads and increased rates, partially offset by lower volumes processed at the extraction plants owned prior to January 2008. Plant turnarounds and a fire at the Harmattan Complex in 2008 resulted in lower operating income of approximately $8.5 million.

In 2008, average ethane and NGL volumes increased primarily as a result of the addition of the Harmattan Complex, Younger Extraction Plant and the remaining 50 percent ownership in the Joffre Extraction Plant offset by lower volumes processed at the extraction plants owned prior to January 2008. Transmission volumes decreased slightly in 2008 due to lower volumes on the Suffield system.

Net revenue in 2008 was $176.2 million, up substantially from $67.4 million in 2007. Net revenue increased by $111.5 million primarily as a result of the extraction and transmission assets acquired with Taylor, $1.5 million due to higher realized frac spreads, $0.9 million due to the Cold Lake Expansion completed in 2007 and $0.6 million due to increased transmission rates. These increases were partially offset by $2.3 million in lower volumes at the extraction plants owned prior to January 2008.

Operating and administrative expense in 2008 was $65.1 million compared to $20.3 million in 2007. The increase was mainly due to the costs incurred to operate the Taylor assets acquired in first quarter 2008. Included in operating expense is $4.1 million due to turnaround costs and $0.5 million as a result of the fire at the Harmattan Complex.

Amortization expense in 2008 was $27.3 million compared to $8.0 million in 2007. The increase was due to the Taylor acquisition in January 2008.

FIELD GATHERING AND PROCESSING

The FG&P segment includes natural gas gathering pipelines and processing facilities. In January 2008 AltaGas added three interconnected processing facilities, Retlaw, Enchant and Turin and related gathering systems (RET) with processing capacity of 150 Mmcf/d as a result of the Taylor acquisition.



Financial Results Three Months Ended Years Ended
December 31 December 31
($ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue 35.1 31.7 154.4 135.1
Net revenue 33.6 29.4 143.9 127.4
Operating and administrative expense 23.3 18.5 95.4 83.3
Amortization expense 7.2 6.4 28.1 25.9
Operating income 3.1 4.5 20.4 18.2
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Operating Statistics Three Months Ended Years Ended
December 31 December 31
2008 2007 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capacity (Mmcf/d)(1) 1,172 1,023 1,172 1,023
Throughput (gross Mmcf/d)(2) 521 511 541 527
Capacity utilization (%)(2) 44 50 46 52
Average working interest (%)(1) 92 91 92 91
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) As at the end of the reporting period.

(2) Average for the period.


Fourth Quarter

Operating income in the FG&P segment for fourth quarter 2008 was $3.1 million compared to $4.5 million for the same quarter of 2007. Operating income decreased due to lower volumes, higher expenses, the impact of cold weather and an outage of a downstream pipeline. This was partially offset by the addition of new plants and higher rates.

Processing capacity increased by 150 Mmcf/d mainly as a result of the addition of the RET facility. Utilization reported in fourth quarter 2008 was 44 percent compared to 50 percent reported in fourth quarter 2007 primarily due to lower utilization at the new plants, as well as lower throughput at some previously owned facilities.

Throughput in fourth quarter 2008 averaged 521 Mmcf/d compared to 511 Mmcf/d fourth quarter 2007. The 2 percent increase was primarily due to the addition of new plants and additional well tie-ins, partially offset by natural declines downstream outages, unusually cold weather resulting in unplanned outages and planned downtime at Bantry to complete the acid gas injection project.

Net revenue for the FG&P segment was $33.6 million in fourth quarter 2008 compared to $29.4 million for the same period in 2007. Net revenue increased due to $4.6 million from new facilities, $1.9 million due to higher operating cost recoveries and $0.3 million from rate increases and higher other facility service revenues. These increases were partially offset by $1.6 million as a result of lower volumes due to natural declines, operational downtime due to cold weather and $1.0 million in lower FSR and other revenues.

Operating and administrative expense in fourth quarter 2008 was $23.3 million compared to $18.5 million for the same quarter in 2007. The increase was due to the addition of new facilities, higher plant repairs and maintenance and administrative expenses.

Amortization expense for the FG&P segment in fourth quarter 2008 was $7.2 million compared to $6.4 million for the same period in 2007. The increase was due to additional facilities and the full quarter impact of Acme and Corbett Creek plants.

Full Year 2008

Operating income in the FG&P segment was $20.4 million in 2008 compared to $18.2 million in 2007. The increase was due to the contribution from new facilities, higher rates and other facility service revenues, partially offset by lower throughput, higher expenses and the sale of Ikhil Joint Venture.

Throughput in 2008 averaged 541 Mmcf/d compared to 527 Mmcf/d in 2007. The increase was primarily due to the acquisition of new plants and additional well tie-ins, partially offset by natural declines, lower producer activity, and scheduled and unscheduled plant outages.

Throughput volumes decreased 19 Mmcf/d in the North District due to general decline and plant turnaround at Rainbow Lake (6 Mmcf/d), lower volumes due to a fire February 13, 2008 followed by a plant shutdown until May 9 at Clear Hills (4 Mmcf/d), general declines in Cold Lake (3 Mmcf/d), and Pouce Coupe operating areas and the sale of Ikhil (1 Mmcf/d), partially offset by increased volumes at Clear Prairie (3 Mmcf/d). Throughput volumes in the South District increased due to the acquisition of RET (55 Mmcf/d), a new plant at Acme (4Mmcf/d) and higher volumes at Bonnie Glen (2 Mmcf/d). These increases were offset by combined volume declines at Bantry and Princess and some volumes being diverted due to plant shut-in on February 12, 2008 at Princess (9 Mmcf/d), volume declines and lower tie-ins at Central Border (7 Mmcf/d) and Kirkpatrick (2 Mmcf/d), volume declines at South Foothills (4 Mmcf/d) and Alder Flats (2 Mmcf/d).

Net revenue in the FG&P segment was $143.9 million in 2008 compared to $127.4 million in 2007. The increase was due to $17.6 million from new facilities, $6.8 million due to higher operating cost recoveries, $1.2 million from increased rates and higher other facility service revenues. These increases were partially offset by $6.8 million due to lower throughput resulting from volume declines, lower producer drilling activity and operational downtime, as well as $2.7 million from the sale of the Ikhil Joint Venture.

Operating and administrative expense in the FG&P segment in 2008 was $95.4 million compared to $83.3 million in 2007. The increase was mainly attributable to $9.0 million for new facilities and $4.2 million due to higher expenses primarily due to the Rainbow Lake turnaround, of which 77 percent was recovered. These increases were partially offset by $1.2 million in lower expenses from the sale of the Ikhil Joint Venture.

Amortization expense in the FG&P segment in 2008 was $28.1 million compared to $25.9 million in 2007. The increase was due to new and expanded facilities, partially offset by the sale of the Ikhil Joint Venture in 2007.

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 segment previously included a small portfolio of oil and natural gas production assets that were sold effective May 31, 2007.



Financial Results Three Months Ended Years Ended
December 31 December 31
($ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue 233.8 227.2 1,058.7 1,022.5
Net revenue 3.3 4.0 14.1 20.9
Operating and administrative expense 3.2 3.5 12.7 15.6
Amortization expense 0.4 0.6 2.0 3.3
Operating income (0.3) - (0.6) 2.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Operating Statistics Three Months Ended Years Ended
December 31 December 31
2008 2007 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Energy management service
contracts(1) 1,711 1,466 1,711 1,466
Average volumes transacted
(GJ/d)(2) 291,353 393,936 302,392 388,217
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Active energy management service contracts at the end of the reporting
period.

(2) 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

Operating loss in the Energy Services segment in fourth quarter 2008 was $0.3 million compared to a nil operating income for the same quarter in 2007. Operating income decreased as a result of $0.3 million in lower fixed-price gas and transport sales.

Net revenue in fourth quarter 2008 was $3.3 million compared to $4.0 million for the same period in 2007. Net revenue decreased as a result of $0.7 million due to lower fixed-price gas and transport sales and lower volumes.

Full Year 2008

The Energy Services segment reported an operating loss of $0.6 million in 2008 compared to operating income of $2.0 million in 2007. The decrease was due to the $1.6 million gain reported on the sale of oil and natural gas production assets in second quarter 2007, lower fixed-price gas and transport sales, declining volumes and a one-time cost for commissions paid to a trade association related to 2007. The decreases were partially offset by a one-time pricing adjustment and lower operating and administrative expenses.

Net revenue was $14.1 million in 2008 compared to $20.9 million in 2007. The decrease included $4.4 million from the sale of oil and natural gas assets in second quarter 2007 and $3.5 million due to lower fixed-price gas and transport sales and declining volumes, partially offset by a $0.8 million one-time pricing adjustment.

POWER GENERATION

The Power Generation segment comprises approximately 392 MW of total power generation capacity in Alberta through a 50 percent ownership interest in the Sundance B power purchase arrangements and a capital lease for 25 MW of gas-fired power peaking capacity. In addition, gas-fired peaking plants at Bantry and Parkland have been installed with generating capacity of 14 MW. The segment also includes a 25 percent interest in a 7-MW run-of-river hydroelectric generation facility in British Columbia acquired in January 2008 with the Taylor acquisition.



Financial Results
Three Months Ended Years Ended
December 31 December 31
($ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
Revenue 58.2 45.8 223.5 182.5
Net revenue 35.9 22.9 129.0 104.2
Operating and administrative expense 1.5 0.6 3.7 2.1
Amortization expense 1.9 1.9 7.4 7.5
Operating income 32.5 20.4 117.9 94.6
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Operating Statistics
Three Months Ended Years Ended
December 31 December 31
2008 2007 2008 2007
----------------------------------------------------------------------------
Volume of power sold (GWh) 664 673 2,623 2,661
Average price received on the sale
of power ($/MWh)(1) 87.30 68.07 84.51 68.59
Alberta Power Pool average spot
price ($/MWh)(1) 95.18 61.75 89.95 66.84
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Average for the period.


Fourth Quarter

Operating income in the Power Generation segment in fourth quarter 2008 was $32.5 million compared to $20.4 million for the same quarter in 2007. Operating income increased as a result of higher spot and hedge power prices, lower PPA costs and higher contributions from gas-fired peaking plants. These increases were partially offset by higher transmission costs.

Net revenue in fourth quarter 2008 was $35.9 million compared to $22.9 million for the same period in 2007. Net revenue increased $8.4 million due to higher spot prices, $2.5 million due to higher prices on hedged volumes, $1.6 million in lower PPA costs and $1.5 million due to higher contributions from gas-fired peaking plants. These increases were partially offset by $0.7 million due to higher transmission costs.

Operating and administrative expense was $1.5 million in fourth quarter 2008 compared to $0.6 million for the same period in 2007. The increase was primarily due to repairs on a peaking plant and administrative costs related to the development of run-of-river projects.

Amortization expense of $1.9 million in fourth quarter 2008 was consistent with the same period in 2007.

Full Year 2008

Operating income in the power business for 2008 was $117.9 million compared to $94.6 million in 2007. The increase was due to higher prices received on both spot and hedged sales, higher contributions from peaking plants, an AESO deferral account settlement, and a gain from the sale of a power project under development, partially offset by higher PPA costs, higher transmission costs and higher costs to comply with Alberta's Specified Gas Emitters Regulation (SGER).

Net revenue for 2008 was $129.0 million compared to $104.2 million in 2007. The increase included $27.1 million due to higher prices received on higher hedged volumes, $9.7 million from higher prices received on spot sales, $2.7 million in higher contributions from the gas-fired peaking plants, $1.8 million from an AESO deferral account settlement and $1.6 million from the sale of a power development project. These increases were partially offset by $8.6 million due to a favourable RAPP received in 2007 as compared to 2008, $5.3 million as a result of higher transmission costs, $3.2 million of higher costs incurred to comply with Alberta's SGER which came into effect mid-2007 and $0.9 million in other variable costs.

Operating and administrative expense of $3.7 million in 2008 was higher than the $2.1 million reported in 2007, primarily due to operating and maintenance services AltaGas began providing to the leased peaking plants in March 2007, operating and maintenance costs incurred on the Bantry and Parkland generators, which came on-line in 2008, and administrative costs related to the development of run-of-river projects.

Amortization expense of $7.4 million in 2008 was similar to 2007.

CORPORATE

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 and foreign exchange rates. Management monitors the impact of mark-to-market accounting as part of the consolidated entity as 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.



Financial Results
Three Months Ended Years Ended
December 31 December 31
($ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
Revenue 0.5 1.6 1.9 5.0
Unrealized gains on risk management 9.6 (0.5) 11.0 1.1
Net revenue 10.1 1.1 12.9 6.2
Operating and administrative expense 13.0 8.4 42.8 31.2
Amortization expense 0.5 0.6 2.2 2.3
Operating loss (3.4) (7.9) (32.1) (27.3)
Operating loss before unrealized gains
on risk management (13.0) (7.4) (43.1) (28.4)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Fourth Quarter

The operating loss for fourth quarter 2008 was $3.4 million compared to $7.9 million for the same period in 2007. The decreased loss was mainly due to unrealized gains on risk management contracts and a write-off of a development project in 2007, partially offset by lower investment income from Taylor which is now reported in the operating segments.

Net revenue was $10.1 million for the fourth quarter in 2008 compared to $1.1 million in fourth quarter 2007. Net revenue increased due to $9.6 million in higher unrealized gains on risk management contracts, partially offset by $0.7 million primarily due to lower investment income as AltaGas no longer reports investment income from Taylor in the Corporate segment.

Operating and administrative expense for fourth quarter 2008 was $13.0 million compared to $8.4 million for the same period in 2007. The increase was primarily due to higher compensation of approximately $2.5 million, professional services and rent expense. In fourth quarter 2008, the Trust reported approximately $2.0 million in non-recurring information technology costs.

Amortization expense for fourth quarter 2008 was similar to the same quarter 2007.

Full Year 2008

The operating loss for 2008 was $32.1 million compared to $27.3 million in 2007. The increased loss was due to higher operating and administrative costs and lower investment income from Taylor, partially offset by unrealized gains on risk management contracts.

Net revenue was $12.9 million for 2008 compared to $6.2 million in 2007. The increase was due to $9.9 million higher unrealized gains on risk management contracts partially offset by lower investment income of $2.6 million from Taylor and $0.6 million in lower interest income.

Operating and administrative expense was $42.8 million in 2008 compared to $31.2 million in 2007. The increase was primarily due to higher compensation costs of approximately $7.0 million, higher information technology costs of approximately $2.5 million, $2.0 million of which is non-recurring and higher rent of approximately $1.5 million.

Amortization expense for 2008 was similar to 2007.

Corporate Outlook

Excluding the impact of mark-to-market accounting, the operating loss for 2009 is expected to be similar to 2008. Operating and administrative expenses are expected to increase by approximately five percent but is expected to be offset by lower costs related to business development activities which are borne by the operating segments in 2009.

The effects of risk management contracts are based on estimates relating to commodity prices 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 2008 AltaGas acquired capital assets, long-term investments and other assets of $45.1 million compared to $32.5 million in fourth quarter 2007. The increase was mainly due to the EDS Pipeline expansion and Bear Mountain capital projects. Year-to-date December 31, 2008, AltaGas acquired capital assets, long-term investments and other assets totalling $824.8 million compared to $86.1 million in 2007 which included mainly the acquisition of Taylor, renewable power projects, the construction of Bear Mountain Wind Park and capital projects at Harmattan. During 2008, the sale of excess equipment, the power development project and the reduction of the carrying value of the Trust's investment in Taylor prior to the acquisition resulted in a reduction of net invested capital of $63.6 million.



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

Energy Power
($ millions) E&T FG&P Services Generation Corporate Total
----------------------------------------------------------------------------
Invested capital:
Capital assets 18.4 12.0 0.5 16.2 1.9 49.0
Long-term
investments and
other assets - - - (4.2) 0.3 (3.9)
----------------------------------------------------------------------------
18.4 12.0 0.5 12.0 2.2 45.1

Disposals:
Capital assets (0.1) (1.4) - - - (1.5)
----------------------------------------------------------------------------
Net invested
capital 18.3 10.6 0.5 12.0 2.2 43.6
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Net Invested Capital - Investment Type Year Ended
December 31, 2008
Energy Power
($ millions) E&T FG&P Services Generation Corporate Total
----------------------------------------------------------------------------
Invested capital:
Capital assets 610.9 63.9 0.3 141.7 6.6 823.4
Long-term
investments and
other assets - - - 0.7 0.7 1.4
----------------------------------------------------------------------------
610.9 63.9 0.3 142.4 7.3 824.8

Disposals:
Capital assets (0.1) (10.1) - (5.2) - (15.4)
Long-term
investments and
other assets - - - - (48.2) (48.2)
----------------------------------------------------------------------------
Net invested
capital 610.8 53.8 0.3 137.2 (40.9) 761.2
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Net Invested Capital - Investment Type Three Months Ended
December 31, 2007
Energy Power
($ millions) E&T FG&P Services Generation Corporate Total
----------------------------------------------------------------------------
Invested capital:
Capital assets 0.3 15.3 1.0 12.7 0.8 30.1
Long-term
investments and
other assets - - - - 2.4 2.4
----------------------------------------------------------------------------
0.3 15.3 1.0 12.7 3.2 32.5

Disposals:
Capital assets - (0.3) - - - (0.3)
----------------------------------------------------------------------------
Net invested
capital 0.3 15.0 1.0 12.7 3.2 32.2
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Net Invested Capital - Investment Type Year Ended
December 31, 2007
Energy Power
($ millions) E&T FG&P Services Generation Corporate Total
----------------------------------------------------------------------------
Invested capital:
Capital assets 5.0 29.1 9.8 22.0 2.3 68.2
Long-term
investments and
other assets - - - (0.5) 18.4 17.9
----------------------------------------------------------------------------
5.0 29.1 9.8 21.5 20.7 86.1

Disposals:
Capital assets (0.3) (15.9) (30.2) - - (46.4)
Long-term
investments and
other assets - - - - - -
----------------------------------------------------------------------------
Net invested
capital 4.7 13.2 (20.4) 21.5 20.7 39.7
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

Maintenance capital expenditures were $1.2 million in fourth quarter 2008 compared to $0.3 million in the same period in 2007 due to various maintenance programs in the FG&P segment. Growth capital of $41.5 million was incurred in fourth quarter 2008 (fourth quarter 2007 - $31.5 million) which included the construction of Bear Mountain Wind project, various extraction, transmission, and field gathering and processing projects, hydroelectric power projects under development, installation of the new power peaking equipment and the development of the Sarnia storage project. Administrative capital for the fourth quarter was $2.4 million compared to $0.7 million in the same period of 2007.

Maintenance capital expenditures were $3.7 million in 2008 compared to $5.7 million in 2007. Growth capital of $813.5 million was expended in 2008 (2007 - $56.2 million) which was largely composed of $592.0 million for the Taylor acquisition, $48.7 million for the Bear Mountain Wind Project, $53.9 million for extraction and transmission facilities, $29.6 million for field gathering and processing facilities, $80.0 million for renewable power projects, $9.0 million on the installation of the new power peaking equipment and $0.2 million for the development of the Sarnia storage. Administrative capital expenditures of $7.6 million in 2008 were significantly lower than the $24.2 million recorded in 2007. The decrease was due to $12.5 million recorded in 2007 as a result of accounting for the Trust's investment in Taylor from the equity to the cost method and reclassing the investment as available-for-sale and $9.2 million promissory note received from the sale of oil and natural gas production assets in 2007. The growth capital has been financed through increased long-term debt.



Invested Capital - Use (1) Three Months Ended
December 31, 2008
Energy Power
($ millions) E&T FG&P Services Generation Corporate Total
----------------------------------------------------------------------------
Invested capital:
Maintenance - 1.2 - - - 1.2
Growth 18.5 10.5 0.5 12.0 - 41.5
Administrative - 0.2 - - 2.2 2.4
----------------------------------------------------------------------------
Invested capital 18.5 11.9 0.5 12.0 2.2 45.1
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Certain maintenance and growth capital expenditures have been reclassed
between segments.


Invested Capital - Use Year Ended
December 31, 2008
Energy Power
($ millions) E&T FG&P Services Generation Corporate Total
----------------------------------------------------------------------------
Invested capital:
Maintenance 1.5 2.2 - - - 3.7
Growth 609.5 59.3 0.2 142.4 2.1 813.5
Administrative - 2.3 0.1 - 5.2 7.6
----------------------------------------------------------------------------
Invested capital 611.0 63.8 0.3 142.4 7.3 824.8
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Invested Capital - Use Three Months Ended
December 31, 2007
Energy Power
($ millions) E&T FG&P Services Generation Corporate Total
----------------------------------------------------------------------------
Invested capital:
Maintenance 0.3 - - - - 0.3
Growth - 14.4 1.0 12.7 3.4 31.5
Administrative - 0.9 - - (0.2) 0.7
----------------------------------------------------------------------------
Invested capital 0.3 15.3 1.0 12.7 3.2 32.5
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Invested Capital - Use Year Ended
December 31, 2007
Energy Power
($ millions) E&T FG&P Services Generation Corporate Total
----------------------------------------------------------------------------
Invested capital:
Maintenance 1.7 4.0 - - - 5.7
Growth 3.3 23.3 9.3 21.5 (1.2) 56.2
Administrative - 1.8 0.5 - 21.9 24.2
----------------------------------------------------------------------------
Invested capital 5.0 29.1 9.8 21.5 20.7 86.1
----------------------------------------------------------------------------
----------------------------------------------------------------------------


SUBSEQUENT EVENTS

Acquisition of Glenridge Wind Development Project

On January 7, 2009 AltaGas acquired the Glenridge Wind Development Project for $2.2 million. The development assets are located near Medicine Hat, Alberta and are expected to provide AltaGas with the potential to develop approximately 100 MW of wind power generation.

Financing

On January 27, 2009 AltaGas entered into an agreement with a syndicate of underwriters, co-led by TD Securities Inc. and Clarus Securities Inc. under which the underwriters have agreed to purchase from AltaGas and sell to the public 6,100,000 trust units at a purchase price of $16.50 per unit. On February 10, 2009 AltaGas announced the closing of the offering resulting in gross proceeds of approximately $100 million. The net proceeds from the offering will be used to reduce indebtedness. The offering forms part of a comprehensive debt and equity financing plan which includes the equity offering as well as a new syndicated revolving and term credit facility. The new facility replaces the Trust's $250 million, 18-month credit facility expiring in September 2009.

Investment in Magma Energy Corp.

On January 15, 2009 AltaGas invested $10 million to acquire approximately a five percent equity position in Magma Energy Corp., a private company focused on the exploration, development and operation of geothermal energy projects. AltaGas also received the right to acquire a direct interest in certain future geothermal projects developed or acquired by the company. Magma Energy Corp. currently owns and operates an 8 MW geothermal energy plant in Nevada as well as a portfolio of geothermal exploration and development projects in the western United States, Argentina, Chile, Nicaragua and Peru.



Consolidated Balance Sheets
(unaudited)

As at December 31
($ thousands) 2008 2007
----------------------------------------------------------------------------

ASSETS
Current assets
Cash and cash equivalents $ 18,304 $ 12,451
Accounts receivable 220,280 191,879
Inventory 775 130
Customer deposits 24,017 24,369
Risk management 118,166 52,308
Other current assets 7,705 9,714
----------------------------------------------------------------------------
389,247 290,851
Capital assets 1,436,686 682,322
Energy arrangements, contracts and relationships 138,913 95,716
Goodwill 143,840 18,260
Risk management 37,131 21,056
Long-term investments and other assets 17,744 64,509
----------------------------------------------------------------------------
$ 2,163,561 $ 1,172,714
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities $ 198,232 $ 177,802
Distributions payable to unitholders 12,943 10,167
Short-term debt 4,493 3,551
Current portion of long-term debt 1,363 1,234
Customer deposits 24,017 24,369
Deferred revenue 2,777 1,718
Risk management 82,832 46,345
Other current liabilities 21,927 9,321
----------------------------------------------------------------------------
348,584 274,507
Long-term debt 559,412 215,949
Asset retirement obligations 41,708 18,811
Future income taxes 211,256 58,229
Risk management 22,644 17,582
Convertible debentures 16,682 -
Other long-term liabilities 5,833 2,948
----------------------------------------------------------------------------
1,206,119 588,026
Unitholders' equity 957,442 584,688
----------------------------------------------------------------------------
$ 2,163,561 $ 1,172,714
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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) 2008 2007 2008 2007
----------------------------------------------------------------------------

REVENUE
Operating $ 414,466 $ 335,401 $1,803,928 $ 1,422,242
Unrealized gain (loss) on risk
management 9,600 (502) 10,986 1,115
Other 491 1,583 1,881 5,037
----------------------------------------------------------------------------
424,557 336,482 1,816,795 1,428,394
----------------------------------------------------------------------------

EXPENSES
Cost of sales 298,773 260,048 1,340,318 1,104,399
Operating and administrative 54,944 36,150 220,131 150,297
Amortization:
Capital assets 14,275 9,491 57,075 39,477
Energy arrangements, contracts
and relationships 2,491 1,903 9,903 7,614
----------------------------------------------------------------------------
370,483 307,592 1,627,427 1,301,787
----------------------------------------------------------------------------
Interest expense
Short-term debt 2,321 222 2,632 491
Long-term debt 5,735 2,683 24,767 11,394
----------------------------------------------------------------------------
Income before income taxes 46,018 25,985 161,969 114,722
Income tax expense (recovery)
Current income tax (65) 297 2,328 297
Future income tax 6,456 (6,115) (3,930) 5,631
----------------------------------------------------------------------------
Net income 39,627 31,803 163,571 108,794
Accumulated earnings,
beginning of period 634,356 478,609 510,412 401,618
----------------------------------------------------------------------------
Accumulated earnings, end of
period $673,983 $510,412 $ 673,983 $ 510,412
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Net income per unit
Basic $ 0.55 $ 0.55 $ 2.38 $ 1.90
Diluted $ 0.55 $ 0.55 $ 2.36 $ 1.89

Weighted average number of
units outstanding (thousands)
Basic 71,610 57,960 68,813 57,382
Diluted 72,506 57,991 69,704 57,420

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) 2008 2007 2008 2007
----------------------------------------------------------------------------

Net income $39,627 $31,803 $163,571 $108,794
Other comprehensive income
(loss), net of tax
Unrealized net gain (loss) on
available-for-sale financial
assets - 6,614 - 17,902
Unrealized net gain on
derivatives designated as cash
flow hedges 19,736 5,449 20,560 7,051
Reclassification of available-
for-sale financial asset as
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 (700) 2,381 1,686 4,850
----------------------------------------------------------------------------
19,036 14,444 4,373 29,803
----------------------------------------------------------------------------
Comprehensive income $58,663 $46,247 $167,944 $138,597
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Accumulated other comprehensive
income, beginning of period $12,506 $12,725 $ 27,169 -
Adjustment resulting from
adoption of new financial
instrument accounting standards - - - (2,634)
Other comprehensive income, net
of tax 19,036 14,444 4,373 29,803
----------------------------------------------------------------------------
Accumulated other comprehensive
income, end of period $31,542 $27,169 $ 31,542 $ 27,169
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying note to the Consolidated Financial Statements.


Consolidated Statements of Cash Flows
(unaudited)

Three months ended Year ended
December 31 December 31
($ thousands) 2008 2007 2008 2007
----------------------------------------------------------------------------
Cash from operations
Net income $ 39,627 $ 31,803 $ 163,571 $ 108,794
Items not involving cash:
Amortization 16,766 11,395 66,978 47,091
Accretion of asset retirement
obligations 509 208 2,302 1,474
Unit-based compensation 87 94 387 553
Future income tax expense
(recovery) 6,456 (6,115) (3,930) 5,631
(Gain) loss on sale of assets (320) 239 (2,045) 57
Equity income (972) (610) (1,388) (2,274)
Distributions from equity
investments 82 - 291 1,490
Unrealized gain on risk
management (9,600) 502 (10,986) (1,115)
Goodwill impairment 100 - 100 -
Other 1,107 321 1,801 1,199
Asset retirement obligations
settled (345) 206 (744) (346)
Net change in non-cash working
capital (15,766) 21,768 (10,891) 20,725
----------------------------------------------------------------------------
37,731 59,811 205,446 183,279
----------------------------------------------------------------------------
Investing activities
Increase (decrease) in
customer deposits 515 1,455 352 (8,065)
Decrease in note receivable - 2,400 6,500 5,100
Acquisition of capital assets (33,053) (27,980) (143,928) (65,065)
Disposition of capital assets 186 37 15,618 9,759
Acquisition of long-term
investments and other assets (4,577) (3,455) (311,493) (5,567)
Disposition of long-term
investments and other assets - 37 - 412
----------------------------------------------------------------------------
(36,929) (27,506) (432,951) (63,426)
----------------------------------------------------------------------------
Financing activities
Increase (decrease) in
short-term debt 4,348 (1,079) 942 3,551
Net issuance (repayment) of
revolving long-term debt 21,093 (106,127) 233,985 (146,708)
Issuance of long-term debt - 100,000 - 100,000
Repayment of long-term debt (216) (1,204) (5,792) (1,204)
Distributions to unitholders (38,616) (30,406) (144,348) (118,061)
Net proceeds from issuance of
units 9,556 6,649 144,071 41,794
Net proceeds from issuance of
warrants - - 4,500 -
----------------------------------------------------------------------------
(3,835) (32,167) 233,358 (120,628)
----------------------------------------------------------------------------
Change in cash and cash
equivalents (3,033) 138 5,853 (775)
Cash and cash equivalents,
beginning of period 21,337 12,313 12,451 13,226
----------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 18,304 $ 12,451 $ 18,304 $ 12,451
----------------------------------------------------------------------------

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 are at the exchange amount. The following describes the Trust's five reporting segments:



Extraction and Transmission (E&T) - NGL processing and extraction plants
and transmission pipelines to
transport natural gas and NGL;
Field Gathering and Processing (FG&P) - natural gas gathering lines and
processing facilities;
Energy Services - energy consulting and sale of
natural gas and electricity;
Power Generation - coal-fired and gas-fired power
output under power purchase
arrangements and other agreements,
gas-fired power plants, wind and
run-of-river power projects under
development; and
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 Energy Gas
December 31, 2008 E&T FG&P Services Subtotal
----------------------------------------------------------------------------
Revenue $ 98,101 $ 35,099 $ 233,794 $ 366,994
Unrealized gain on risk
management - - - -
Cost of sales (55,380) (1,546) (230,492) (287,418)
Operating and
administrative (13,792) (23,238) (3,205) (40,235)
Amortization (6,691) (7,134) (447) (14,272)
Interest expense - - - -
----------------------------------------------------------------------------
Income (loss) before income
taxes $ 22,238 $ 3,181 $ (350) $ 25,069
----------------------------------------------------------------------------
Net additions
(reductions) to:
Capital assets(1) $ 18,474 $ 10,522 $ 445 $ 29,441
Energy services
arrangements,
contracts and
relationships - - - -
Long-term investment and
other assets(2) - - - -
----------------------------------------------------------------------------
Goodwill $ 142,725 $ 115 - $ 142,840
Segmented assets $ 1,038,581 $ 530,855 $ 138,899 $1,708,335
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Three Months Ended Power Intersegment
December 31, 2008 Generation Corporate Elimination Total
----------------------------------------------------------------------------
Revenue $ 58,168 $ 492 $ (10,697) $ 414,957
Unrealized gain on risk
management - 9,600 - 9,600
Cost of sales (22,297) - 10,942 (298,773)
Operating and
administrative (1,479) (12,985) (245) (54,944)
Amortization (1,928) (566) - (16,766)
Interest expense - (8,056) - (8,056)
----------------------------------------------------------------------------
Income (loss) before income
taxes $ 32,464 $ (11,515) - $ 46,018
----------------------------------------------------------------------------
Net additions
(reductions) to:
Capital assets(1) $ 16,263 $ 1,821 - $ 47,525
Energy services
arrangements,
contracts and
relationship - - - $ -
Long-term investment and
other assets(2) $ (4,229) $ 329 - $ (3,900)
----------------------------------------------------------------------------
Goodwill $ - - - $ 142,840
Segmented assets $ 268,474 $ 186,752 - $2,163,561
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Includes non-cash transactions of $14,658.

(2) Includes non-cash transactions of $8,477.


Year Ended Energy Gas
December 31, 2008 E&T FG&P Services Subtotal
----------------------------------------------------------------------------
Revenue $ 430,132 $ 154,402 $ 1,058,653 $ 1,643,187
Unrealized gain on risk
management - - - -
Cost of sales (253,910) (10,558) (1,044,521) (1,308,989)
Operating and
administrative (65,164) (95,353) (12,713) (173,230)
Amortization (27,214) (28,071) (2,021) (57,306)
Interest expense - - - -
----------------------------------------------------------------------------
Income (loss) before income
taxes $ 83,844 $ 20,420 $ (602)$ 103,662
----------------------------------------------------------------------------
Net additions
(reductions) to:
Capital assets(1) $ 610,886 $ 53,695 $ 266 $ 664,847
Energy service
arrangements,
contracts and
relationships $ 53,000 - - $ 53,000
Long-term investment and
other assets(2) - - - -
----------------------------------------------------------------------------
Goodwill $ 143,725 $ 115 - $ 143,840
Segmented assets $ 1,038,581 $ 530,855 $ 138,899 $ 1,708,335
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Year Ended Power Intersegment
December 31, 2008 Generation Corporate Elimination Total
----------------------------------------------------------------------------
Revenue $ 223,510 $ 1,882 $ (62,770)$ 1,805,809
Unrealized gain on risk
management - 10,986 - 10,986
Cost of sales (94,518) - 63,189 (1,340,318)
Operating and
administrative (3,715) (42,767) (419) (220,131)
Amortization (7,436) (2,236) - (66,978)
Interest expense - (27,399) - (27,399)
----------------------------------------------------------------------------
Income (loss) before income
taxes $ 117,841 $ (59,534) - $ 161,969
----------------------------------------------------------------------------
Net additions
(reductions) to:
Capital assets(1) $ 136,523 $ 6,592 - $ 807,962
Energy service
arrangements,
contracts and
relationships - - - $ 53,000
Long-term investment and
other assets(2) $ 713 $ (47,479) - $ (46,766)
----------------------------------------------------------------------------
Goodwill $ - - - $ 143,840
Segmented assets $ 268,474 $ 186,752 - $ 2,163,561
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Includes non-cash transactions of $679,652.

(2) Includes non-cash transactions of $358,259.


Three Months Ended Energy Gas
December 31, 2007 E&T FG&P Services Subtotal
----------------------------------------------------------------------------
Revenue $ 39,294 $ 31,685 $ 227,232 $ 298,211
Unrealized loss on risk
management - - - -
Cost of sales (19,939) (2,244) (223,192) (245,375)
Operating and
administrative (5,476) (18,573) (3,439) (27,488)
Amortization (2,004) (6,359) (552) (8,915)
Interest expense - - - -
----------------------------------------------------------------------------
Income (loss) before income
taxes $ 11,875 $ 4,509 $ 49 $ 16,433
----------------------------------------------------------------------------
Net additions to:
Capital assets(1) $ 259 $ 15,053 $ 1,058 $ 16,370
Long-term investment and
other assets(2) - - - -
----------------------------------------------------------------------------
Goodwill $ 18,045 $ 215 - $ 18,260
Segmented assets $ 241,198 $ 507,876 $ 115,850 $ 864,924
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Three Months Ended Power Intersegment
December 31, 2007 Generation Corporate Elimination Total
----------------------------------------------------------------------------
Revenue $ 45,815 $ 1,583 $ (8,625) $ 336,984
Unrealized loss on risk
management - (502) - (502)
Cost of sales (22,951) - 8,278 (260,048)
Operating and
administrative (603) (8,406) 347 (36,150)
Amortization (1,894) (585) - (11,394)
Interest expense - (2,905) - (2,905)
----------------------------------------------------------------------------
Income (loss) before income
taxes $ 20,367 $ (10,815) - $ 25,985
----------------------------------------------------------------------------
Net additions to:
Capital assets(1) $ 12,704 $ 765 - $ 29,839
Long-term investment and
other assets(2) $ (1) $ 2,388 - $ 2,387
----------------------------------------------------------------------------
Goodwill - - - $ 18,260
Segmented assets $ 151,401 $ 156,389 - $1,172,714
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Includes non-cash transactions of $1,896.

(2) Includes non-cash transactions of $1,031.


Year Ended Energy Gas
December 31, 2007 E&T FG&P Services Subtotal
----------------------------------------------------------------------------
Revenue $ 142,938 $ 135,105 $1,022,506 $1,300,549
Unrealized gain on
risk management - - - -
Cost of sales (75,495) (7,655) (1,001,599) (1,084,749)
Operating and
administrative (20,300) (83,344) (15,576) (119,220)
Amortization (8,055) (25,901) (3,307) (37,263)
Interest expense - - - -
----------------------------------------------------------------------------
Income (loss) before income
taxes $ 39,088 $ 18,205 $ 2,024 $ 59,317
----------------------------------------------------------------------------
Net additions
(reductions) to:
Capital assets(1) $ 4,672 $ 13,213 $ (20,457) $ (2,572)
Long-term investment and
other assets(2) - - - -
----------------------------------------------------------------------------
Goodwill $ 18,045 $ 215 - $ 18,260
Segmented assets $ 241,198 $ 507,876 $ 115,850 $ 864,924
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Year Ended Power Intersegment
December 31, 2007 Generation Corporate Elimination Total
----------------------------------------------------------------------------
Revenue $ 182,535 $ 5,037 $ (60,842) $1,427,279
Unrealized gain on
risk management - 1,115 - 1,115
Cost of sales (78,373) - 58,723 (1,104,399)
Operating and
administrative (2,035) (31,161) 2,119 (150,297)
Amortization (7,488) (2,340) - (47,091)
Interest expense - (11,885) - (11,885)
----------------------------------------------------------------------------
Income (loss) before income
taxes $ 94,639 $ (39,234) - $ 114,722
----------------------------------------------------------------------------
Net additions
(reductions) to:
Capital assets(1) $ 22,013 $ 2,349 - $ 21,790
Long-term investment and
other assets(2) $ (530) $ 18,396 - $ 17,866
----------------------------------------------------------------------------
Goodwill - - - $ 18,260
Segmented assets $ 151,401 $ 156,389 - $1,172,714
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Includes non-cash transactions of $33,516.
(2) Includes non-cash transactions of $12,711.


Supplementary Quarterly Financial and Operating Information

($ millions unless
otherwise indicated) 2008 Q4-08 Q3-08 Q2-08 Q1-08
----------------------------------------------------------------------------
FINANCIAL HIGHLIGHTS(1)
Net Revenue(2)
Extraction and
Transmission 176.2 42.7 43.8 44.1 45.6
Field Gathering and
Processing 143.9 33.6 38.1 40.6 31.6
Energy Services 14.1 3.3 4.4 3.0 3.4
Power Generation 129.0 35.9 32.8 31.9 28.4
Corporate 12.9 10.1 3.6 (2.8) 2.0
Intersegment Elimination 0.4 0.2 - 0.5 (0.3)
----------------------------------------------------------------------------
476.5 125.8 122.7 117.3 110.7
----------------------------------------------------------------------------

EBITDA(2)
Extraction and
Transmission 111.1 29.0 25.4 25.7 31.0
Field Gathering and
Processing 48.5 10.3 14.2 12.8 11.2
Energy Services 1.4 0.1 1.4 (0.4) 0.3
Power Generation 125.3 34.4 31.8 31.4 27.7
Corporate (29.9) (2.9) (4.7) (15.7) (6.6)
----------------------------------------------------------------------------
256.4 70.9 68.1 53.8 63.6
----------------------------------------------------------------------------

Operating Income
(Loss)(2)
Extraction and
Transmission 83.8 22.2 18.0 18.8 24.8
Field Gathering and
Processing 20.4 3.1 7.2 5.8 4.3
Energy Services (0.6) (0.3) 0.8 (0.9) (0.2)
Power Generation 117.9 32.5 30.1 29.4 25.9
Corporate (32.1) (3.4) (5.4) (16.1) (7.2)
----------------------------------------------------------------------------
189.4 54.1 50.7 37.0 47.6
----------------------------------------------------------------------------
OPERATING HIGHLIGHTS
Extraction and
Transmission
Extraction inlet gas
processed (Mmcf/d)(4) 801 790 781 759 872
Extraction volumes
(Bbls/d)(4) 37,037 35,426 35,591 35,335 41,799
Transmission volumes
(Mmcf/d)(4)(5) 379 367 381 390 379
Frac spread - realized
($/Bbl)(4)(6) 26.97 28.41 26.02 27.61 27.02
Frac spread - average
spot price ($/Bbl)(4)(6) 28.79 18.58 36.92 30.32 28.92
Field Gathering and
Processing
Capacity (gross
Mmcf/d)(3) 1,172 1,172 1,178 1,178 1,178
Throughput (gross
Mmcf/d)(4) 541 521 545 554 542
Capacity utilization
(%)(4) 46 44 46 47 46
Energy Services
Energy management
service contracts(3) 1,711 1,711 1,572 1,514 1,499
Average volumes
transacted (GJ/d)(4) 302,392 291,353 298,608 303,212 324,758
Power Generation
Volume of power sold
(GWh)(4) 2,623 664 651 648 660
Average price received
on sale of power
($/MWh)(4) 84.51 87.30 83.10 89.46 78.24
Alberta Power Pool
average spot price
($/MWh)(4) 89.94 95.18 80.36 107.56 76.69
----------------------------------------------------------------------------

(1) Columns may not add due to rounding.
(2) Non-GAAP financial measure.
(3) As at period end.
(4) Average for the period.
(5) Excludes natural gas liquids pipeline volumes.
(6) 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.

----------------------------------------------------------------------------


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


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