News

AltaGas Announces Strong Third Quarter Results

November 07, 2007





CALGARY, ALBERTA--(Marketwire - Nov. 7, 2007) - AltaGas Income Trust (AltaGas or the Trust) (TSX:ALA.UN) today reported a 9 percent increase in net income of $31.4 million ($0.54 per unit) for the three months ended September 30, 2007 compared to $28.8 million ($0.52 per unit) for the same quarter in 2006.

Net income for the nine months ended September 30, 2007 was $77.0 million ($1.35 per unit) compared to $87.2 million ($1.58 per unit) for the same period in 2006. Excluding non-cash charges related to the tax on income trusts of $6.0 million and the non-cash tax benefit of $6.6 million recorded in second quarter 2006, net income for the nine months ended September 30, 2007 was $83.0 million ($1.45 per unit) compared to $80.6 million ($1.46 per unit) in the same period in 2006.

AltaGas Income Trust also declared a distribution of $0.175 per trust unit and exchangeable unit payable on December 17, 2007 to holders of record on November 26, 2007. AltaGas declared total cash distributions of $0.52 per unit in third quarter 2007. During the quarter AltaGas also declared a special distribution of one AltaGas Utility Group Inc. share for every 100 trust units and exchangeable units of AltaGas.

David Cornhill, Chairman, President and CEO of the Trust, remarked, "This quarter marked another record for AltaGas, as quarterly net income exceeded $30 million for the first time. Our performance reflected the benefit of being diversified along the energy value chain. Our hedging strategy resulted in strong power prices and cash flow in a quarter when spot prices were lower than the same quarter last year. Our Extraction and Transmission segment also reported strong earnings even though we had lower volumes, since frac spreads remained strong and we benefited from the growth in the underlying extraction and transmission assets. In the Field Gathering and Processing segment we continue to see lower volumes processed and higher operating costs but our contracting strategy, redeployable equipment and ability to increase processing capacity in areas where there is strong producer activity have mitigated the impact of lower throughput. Overall we are on track for another successful year."

Net income in third quarter 2007 was higher than in the same quarter last year. Net income increased primarily due to higher hedge prices and lower costs in the Power Generation segment, higher rates and one new facility in the Field Gathering and Processing (FG&P) segment. These increases were partially offset by higher operating and administrative costs, lower throughput in FG&P, higher income tax expense, a one-time write-off of costs related to the deferral of the Noel project, lower Alberta spot power prices and lower contributions from the Energy Services segment.

Excluding the Specified Investment Flow-Through (SIFT) tax reported in 2007 and the non-cash tax benefit recorded in 2006, net income for the nine months ended September 30, 2007 was higher than in the same period last year. Net income increased mainly as a result of higher power prices and lower costs in the Power Generation segment, new facilities, higher rates and product revenues in the FG&P segment, a one-time gain from the sale of oil and gas production assets and lower interest expense. These increases were partially offset by higher operating and administrative costs, lower throughput in the FG&P segment, the expiration of the Genesee power contract, decreased earnings in the Energy Services segment, higher amortization expense, lower one-time take-or-pay contractual provisions in FG&P and a one-time write-off of costs related to the deferred Noel project.

FINANCIAL HIGHLIGHTS(1)

- Earnings before interest, taxes, depreciation and amortization (EBITDA) were $49.1 million ($0.85 per unit) this quarter compared to $45.1 million ($0.81 per unit) in the same quarter in 2006. EBITDA for the first nine months of 2007 was $133.4 million ($2.33 per unit), up from $128.6 million ($2.33 per unit) for the same period last year.

- Cash from operations was $30.8 million ($0.53 per unit) for third quarter 2007 compared to $40.8 million ($0.73 per unit) for the same period in 2006. Cash from operations for the first nine months of 2007 was $123.5 million ($2.16 per unit), up from $110.3 million ($2.00 per unit) for the same period last year.

- Funds from operations were $47.6 million ($0.83 per unit) for third quarter 2007, compared to $43.2 million ($0.78 per unit) for the same period in 2006. Funds from operations for the first nine months of 2007 were $125.1 million ($2.19 per unit), up from $119.9 million ($2.17 per unit) for the same period last year.

- Total debt was $229.1 million, compared to $265.5 million at December 31, 2006. The Trust's debt-to-total capitalization ratio was 29.0 percent, versus 33.4 percent at the end of 2006.

(1) Includes Non-GAAP financial measures. Please see discussion in the Non-GAAP Financial Measures section of the Trust's third quarter Management's Discussion and Analysis.

IN THE THIRD QUARTER:

- AltaGas, through its partnership in GreenWing Energy Development Limited Partnership, submitted three non-binding project bids into the Manitoba Hydro 300 MW Wind Request for Proposal. Responses to the bids are expected in November 2007.

- AltaGas signed an agreement to sell its one-third interest in the Ikhil Joint Venture to AltaGas Utility Group Inc. for $9.0 million effective July 31, 2007. The gain on sale was negligible.

- Bear Mountain Wind Limited Partnership (BMWLP), a partnership in which AltaGas owned 50 percent, signed agreements with AltaGas, Aeolis Wind Power Corporation (Aeolis) and Peace Energy A Renewable Energy Cooperative (Peace) to exchange their equity interests in BMWLP for a royalty agreement pursuant to which Aeolis and Peace will receive royalty payments. AltaGas contributed an additional $1.0 million to BMWLP for the purpose of repaying loans owing to Aeolis. This contribution, along with similar amounts loaned by AltaGas, now form additional investments by AltaGas in BMWLP. As a result, AltaGas now owns 100 percent of BMWLP.

- AltaGas purchased a 50 percent interest in the Sarnia Airport Pool Storage Project. Once developed, the storage project is expected to have 5.3 Bcf of working capacity and deliverability of approximately 52 Mmcf/d. The project is in the early development stage and is subject to various regulatory and environmental approvals. The project is targeted to be in full operation by mid-2009.

- AltaGas filed a final short-form base shelf prospectus to facilitate the issuance of trust units or unsecured debt securities. This shelf has a 25-month life and permits the Trust to issue up to an aggregate of $500 million of securities.

- AltaGas announced the deferral of the Noel natural gas pipeline construction and sour gas facility expansion project. The project, announced on April 10, 2007, was subject to certain economic conditions precedent and has been deferred due to uncertainty around installation costs and low gas prices. In the third quarter AltaGas reported a charge of $1.5 million of costs specific to the project. AltaGas continues to pursue the expansion of the Pouce Coupe facility in order to meet producer requirements in the area.

- AltaGas extended its syndicated revolving-term credit facility and amended the agreement to add a $75 million accordion feature to the facility. The facility expires September 30, 2010.

- The Trust suspended the Premium component of the Distribution Reinvestment Plan (DRIP) effective with the August 15, 2007 distribution payment. The regular component of the DRIP remains in effect and continues to support AltaGas' financing strategy. In the future, as conditions warrant, the Trust may consider reinstating the Premium DRIP (PDRIP) component based on AltaGas' capital requirements and desire to maintain an efficient capital structure. While the PDRIP component of the plan is suspended, PDRIP participants will continue to receive regular cash distributions. For further information on the DRIP please visit AltaGas' website at www.altagas.ca.

- AltaGas announced a significant multi-year financial commitment valued at more than $500,000 to support Cross Country Canada. This commitment is the largest philanthropic contribution ever for the Trust and will support the nation's high-performance cross-country skiers and fuel their drive to the podium.

AltaGas will hold a teleconference today at 2:00 p.m. MST (4:00 p.m. EST) to discuss the third quarter 2007 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) 641-6131 or call toll free at 1-866-226-1792. No passcode is required. Please note that the conference call will also be webcast. To listen, please connect here: http://events.onlinebroadcasting.com/altagas/110707/index.php.

Shortly after the conclusion of the call, a replay will be available by dialing (416) 695-5800 or 1-800-408-3053. The passcode for this replay is 3239032. The replay will expire at midnight (EST) on November 14, 2007. The webcast will be archived for one year.

Management's Discussion and Analysis

The Management's Discussion and Analysis (MD&A) of operations and unaudited interim Consolidated Financial Statements presented herein reports on a continuity of interests accounting basis which recognizes AltaGas Income Trust (AltaGas or the Trust) as the successor to AltaGas Services Inc. (ASI). This MD&A dated November 7, 2007 is a review of the results of operations and the liquidity and capital resources of the Trust for the three and nine months ended September 30, 2007 compared to the three and nine months ended September 30, 2006. It should be read in conjunction with the accompanying unaudited Consolidated Financial Statements and notes thereto of the Trust as at and for the three and nine months ended September 30, 2007 and with the audited Consolidated Financial Statements and MD&A contained in the Trust's annual report for the year ended December 31, 2006.

This MD&A contains forward looking statements. When used in this MD&A 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 MD&A 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. 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 actual results, performance or achievements to vary from those described in this MD&A, including without limitation those listed above. 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 MD&A. 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, filed as AltaGas Services Inc. prior to May 1, 2004, including its annual MD&A and audited financial statements, Annual Information Form, Information Circular and Proxy Statement, material change reports and press releases issued by the Trust, are also available through the Trust's website or directly through the SEDAR system at www.sedar.com.

ALTAGAS INCOME TRUST

The material businesses of the Trust are operated by AltaGas Ltd., AltaGas Operating Partnership, AltaGas Limited Partnership and AltaGas Pipeline Partnership, as well as PremStar Energy Canada Limited Partnership (PremStar) and ECNG Energy L.P. (collectively the operating subsidiaries). The cash flow of the Trust is solely dependent on the results of the operating subsidiaries and is derived from operating income earned from partnership interests held by AltaGas Holding Limited Partnership No. 1 (AltaGas LP #1), from interest earned on loans to the operating subsidiaries and from dividends or returns of capital from equity interests held within the Trust structure.

AltaGas General Partner Inc., through its Board of Directors, the members of which are elected by the Trust at the direction of the holders of the units, has been delegated by the trustee of the Trust to manage or supervise the business and affairs of the Trust. AltaGas Ltd. provides all management, administrative and operating services to the Trust and its subsidiaries.



Consolidated Financial Results Three Months Ended Nine Months Ended
September 30 September 30
($ millions) 2007 2006 2007 2006
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Revenue 322.1 317.9 1,091.9 995.2
Unrealized gains (losses) on risk
management 1.1 - 1.6 -
Net revenue(1) 88.2 82.5 247.6 234.3
EBITDA(1) 49.1 45.1 133.4 128.6
EBITDA before unrealized gains (losses)
on risk management(1) 48.0 45.1 131.8 128.6
Operating income(1) 37.5 33.7 97.7 94.6
Operating income before unrealized gains
(losses) on risk management(1) 36.4 33.7 96.1 94.6
Net income 31.4 28.8 77.0 87.2
Net income before tax-adjusted unrealized
gains (losses) on risk management(1) 30.7 28.8 76.8 87.2
Net income before SIFT tax(1) 30.9 28.8 83.0 87.2
Total assets 1,162.5 1,030.6 1,162.5 1,030.6
Total long-term liabilities 354.2 343.9 354.2 343.9
Net additions (reductions) to
capital assets 5.9 23.5 (8.0) 54.0
Distributions declared(2) 30.0 28.1 88.2 82.1
Cash flows
Cash from operations 30.8 40.8 123.5 110.3
Funds from operations(1) 47.6 43.2 125.1 119.9
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Three Months Ended Nine Months Ended
September 30 September 30
($ per unit) 2007 2006 2007 2006
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EBITDA(1) 0.85 0.81 2.33 2.33
EBITDA before unrealized gains (losses)
on risk management(1) 0.83 0.81 2.30 2.33
Net income 0.54 0.52 1.35 1.58
Net income before tax-adjusted unrealized
gains (losses) on risk management(1) 0.53 0.52 1.34 1.58
Net income before SIFT tax(1) 0.54 0.52 1.45 1.58
Distributions declared(2) 0.52 0.505 1.54 1.485
Cash flows
Cash from operations 0.53 0.73 2.16 2.00
Funds from operations(1) 0.83 0.78 2.19 2.17
Units outstanding - basic (millions)
During the period(3) 57.7 55.7 57.2 55.2
End of period 57.8 55.9 57.8 55.9
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(1) Non-GAAP financial measure. See discussion in Non-GAAP Financial
Measures section of this MD&A.
(2) Distributions declared of $0.175 per unit per month commencing in August
2007. From August 2006 to July 2007 distributions of $0.17 per unit per
month were declared. From March 2006 to July 2006 distributions of
$0.165 per unit per month were declared. In January 2006 distributions
of $0.16 per unit per month were declared.
(3) Weighted average.

 


CONSOLIDATED FINANCIAL REVIEW

Three Months Ended September 30

Net income for the three months ended September 30, 2007 was $31.4 million ($0.54 per unit) compared to $28.8 million ($0.52 per unit) for the same period in 2006. Net income was higher this quarter than the same quarter last year as a result of higher hedge prices and lower costs in the Power Generation segment, higher rates and a new facility in the Field Gathering and Processing (FG&P) segment and unrealized gains as a result of changes in the fair value of risk management contracts. These increases were partially offset by higher operating and administrative costs, lower throughput in the FG&P segment, higher income tax expense, a one-time write-off of costs related to the deferred Noel project, lower Alberta spot power prices and lower contributions from the Energy Services segment.

On a consolidated basis, net revenue for third quarter 2007 was $88.2 million compared to $82.5 million in the same quarter last year. Net revenue increased for third quarter 2007 due to higher hedge prices and lower costs in the Power Generation segment, increased rates, routine equalization adjustments and a new facility in FG&P, and the unrealized gain in the fair value of risk management contracts. The increases were partially offset by lower throughput in FG&P, lower revenues as a result of the sale of oil and gas assets in May 2007 and lower Alberta spot power prices.

In the Extraction and Transmission, Power Generation and Energy Services segments, net revenue which is defined in the Non-GAAP Financial Measures section of this MD&A, better reflects performance than does revenue as changes in the market price of natural gas and power affect both revenue and cost of goods sold.

Operating and administrative expense for third quarter 2007 was $39.1 million compared to $37.2 million in the same quarter last year. The increase was primarily due to a one-time $1.5 million charge related to costs specific to the deferred Noel project. The total cost of the Noel project incurred to date was $3.4 million of which $1.6 million is expected to be recovered.

Amortization expense for third quarter 2007 was $11.7 million compared to $11.4 million in the same quarter last year. The increase was a result of new and expanded FG&P facilities and increased ownership at one of the Empress extraction facilities, partially offset by the disposition of oil and natural gas production assets.

Interest expense for the third quarter 2007 was $2.9 million compared to $3.2 million in the same quarter last year. The decrease was due to lower average debt balances of $225.2 million compared to $271.1 million for the same period in 2006 as a result of repaying long-term debt with excess cash generated from operations. The average borrowing rate in third quarter 2007 was 5.3 percent compared to 4.8 percent in third quarter 2006.

Income tax expense for third quarter 2007 was $3.2 million compared to $1.7 million in the same quarter last year. The increase was due to higher taxable income and a tax impact on unrealized gains related to risk management assets and liabilities, partially offset by an adjustment of $0.5 million to future income tax liabilities as a result of the Specified Investment Flow-Through (SIFT) tax.

Nine Months Ended September 30

Net income for the nine months ended September 30, 2007 was $77.0 million ($1.35 per unit) compared to $87.2 million ($1.58 per unit) for the same period last year. Excluding the non-cash SIFT tax of $6.0 million recorded in the nine months ended September 30, 2007 and the non-cash tax benefit of $6.6 million recorded in second quarter 2006, net income was $83.0 million ($1.45 per unit) compared to $80.6 million ($1.46 per unit). Net income increased as a result of higher prices and lower costs in the Power Generation segment, new facilities, higher rates and product revenues in the FG&P segment, unrealized gain on risk management contracts, a one-time gain from the sale of oil and natural gas production assets and lower interest expense. The increases in net income were partially offset by higher operating and administrative expenses, continued lower throughput in the FG&P segment, the expiration of the Genesee power contract on March 31, 2006 which contributed $4.1 million to income in first quarter 2006, decreased earnings in the Energy Services segment, higher amortization expense, lower one-time take-or-pay contractual provisions in the FG&P segment and a one-time write-off of costs related to the deferred Noel project.

On a consolidated basis, net revenue in the first nine months of 2007 was $247.6 million compared to $234.3 million for the same period in 2006. The increase was due to higher power prices and lower costs in the Power Generation segment, new facilities, higher rates and product revenues in the FG&P segment and a one-time gain on the sale of oil and natural gas production assets. The increases were partially offset by the expiration of the Genesee power contract, lower throughput and lower one-time take-or-pay contractual provisions in the FG&P segment, a lower contribution from the oil and gas assets sold in May 2007 and decreased earnings in the Energy Services segment.

Operating and administrative expense for the nine months ended September 30, 2007 was $114.1 million compared to $105.7 million for the same period in 2006. The increase was due to additional costs related to new facilities, increased ownership at one of the extraction facilities, higher compensation costs and a one-time $1.5 million write-off of costs specific to the deferred Noel project.

Amortization expense for the first nine months of 2007 was $35.7 million compared to $34.0 million for the same period in 2006. The increase was primarily due to new and expanded facilities in the FG&P segment, partially offset by the sale of oil and natural gas production assets.

Interest expense for the nine months ended September 30, 2007 was $9.0 million compared to $9.9 million for the same period last year. The decrease was primarily due to a lower average debt balance of $240.4 million compared to $273.5 million for the same period in 2006 as a result of repaying long-term debt with excess cash generated from operations. The average borrowing rate in the first nine months of 2007 was 5.2 percent compared to 4.9 percent in the same period in 2006.

During third quarter 2007 AltaGas recalculated the estimate for the SIFT tax reported in second quarter. The recalculation resulted in a decrease in SIFT tax from $14.5 million to $6.5 million. The change resulted in an increase in net income for second quarter 2007 to $21.1 million ($0.37 per unit) from $13.1 million ($0.23 per unit) previously reported. Net income for the six months ended June 30, 2007 increased to $45.6 million ($0.80 per unit) from $37.6 million ($0.66 per unit) previously reported. The results reported for the nine months ended September 30, 2007 reflect the adjustment made to second quarter 2007 results.

Income tax expense for the nine months ended September 30, 2007 was $11.7 million compared to an income tax recovery of $2.5 million in the same period in 2006. The increase was due to the non-cash charge of $6.0 million to record future income tax liabilities for differences between the accounting and tax basis of AltaGas' assets and liabilities as a result of the SIFT tax, a $6.6 million non-cash tax benefit recorded in 2006 due to Alberta and federal income tax rate reductions, $1.4 million tax impact on unrealized gains related to risk management assets and liabilities and $0.8 million from higher taxable income. These increases were partially offset by a future income tax recovery of $0.6 million from the sale of oil and natural gas production assets.

Specified Investment Flow-Through Tax

On June 12, 2007 the SIFT tax included in Bill C-52 received Third Reading and on June 22, 2007 it received Royal Assent, creating a new 31.5 percent tax to be applied to distributions from certain income trusts and partnerships, including AltaGas, effective January 1, 2011. Prior to this legislation, AltaGas' future income tax liability reflected only those temporary differences in the Trust's subsidiaries that were subject to tax. While net income in the nine months ended September 30, 2007 was significantly reduced by this future income tax adjustment, the non-cash future income tax expense has no impact on current cash flows.

Management will continue to review and consider alternatives for the most efficient organizational structure for AltaGas subject to the passage of the legislation and the provision of further guidance by the federal government. AltaGas' decision will be the one that best protects its unitholders.

NON-GAAP FINANCIAL MEASURES

This MD&A contains references to certain financial measures that do not have a standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP) and may not be comparable to similar measures presented by other entities. The non-GAAP measures and their reconciliation to GAAP financial measures are shown below. All of the measures have been calculated consistent with previous disclosures.



Net Revenue Three Months Ended Nine Months Ended
September 30 September 30
($ millions) 2007 2006 2007 2006
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Net revenue 88.2 82.5 247.6 234.3
Add: Cost of sales 233.9 235.4 844.3 760.9
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Revenue (GAAP financial measure) 322.1 317.9 1,091.9 995.2
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Net revenue, which is revenue less the cost of commodities purchased for sale and shrinkage, is a better reflection of performance than revenue, as changes in the market price of natural gas and power affect both revenue and cost of sales.



Operating Income Three Months Ended Nine Months Ended
September 30 September 30
($ millions) 2007 2006 2007 2006
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Operating income 37.5 33.7 97.7 94.6
Add (deduct): Interest expense (2.9) (3.2) (9.0) (9.9)
Income tax expense (3.2) (1.7) (11.7) 2.5
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Net income (GAAP financial measure) 31.4 28.8 77.0 87.2
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Operating income is a measure of the Trust's profitability from its principal business activities prior to how these activities are financed or how the results are taxed. Operating income is calculated from the Consolidated Statements of Income and Accumulated Earnings and is defined as net revenue less operating and administrative expenses and amortization.



Operating Income Before Unrealized Three Months Ended Nine Months Ended
Gains (Losses) on Risk Management September 30 September 30
($ millions) 2007 2006 2007 2006
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Operating income before unrealized
gains (losses) on risk management 36.4 33.7 96.1 94.6
Add (deduct): Unrealized gains (losses)
on risk management 1.1 - 1.6 -
Interest expense (2.9) (3.2) (9.0) (9.9)
Income tax expense (3.2) (1.7) (11.7) 2.5
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Net income (GAAP financial measure) 31.4 28.8 77.0 87.2
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Operating income before unrealized gains (losses) on risk management is a measure of the Trust's profitability from its principal business activities prior to accounting for how these activities are financed, how the results are taxed, and how the impact of gains (losses) from risk management activities affected operations. Operating income before unrealized gains (losses) on risk management is calculated from the Consolidated Statements of Income and Accumulated Earnings and is defined as net revenue adjusted for unrealized gains (losses) on risk management less operating and administrative expenses and amortization.



EBITDA Three Months Ended Nine Months Ended
September 30 September 30
($ millions) 2007 2006 2007 2006
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EBITDA 49.1 45.1 133.4 128.6
Add (deduct): Amortization (11.6) (11.4) (35.7) (34.0)
Interest expense (2.9) (3.2) (9.0) (9.9)
Income tax expense (3.2) (1.7) (11.7) 2.5
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Net income (GAAP financial measure) 31.4 28.8 77.0 87.2
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EBITDA is a measure of the Trust's operating profitability. EBITDA provides an indication of the results generated by the Trust's principal business activities prior to accounting for how these activities are financed, assets are amortized or how the results are taxed. EBITDA is calculated from the Consolidated Statements of Income and Accumulated Earnings and is defined as net revenue less operating and administrative expenses.



EBITDA Before Unrealized Gains Three Months Ended Nine Months Ended
(Losses) on Risk Management September 30 September 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
EBITDA before unrealized gains
(losses) on risk management 48.0 45.1 131.8 128.6
Add (deduct): Unrealized gains (losses)
on risk management 1.1 - 1.6 -
Amortization (11.6) (11.4) (35.7) (34.0)
Interest expense (2.9) (3.2) (9.0) (9.9)
Income tax expense (3.2) (1.7) (11.7) 2.5
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Net income (GAAP financial measure) 31.4 28.8 77.0 87.2
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EBITDA before unrealized gains (losses) on risk management is a measure of the Trust's operating profitability. EBITDA before unrealized gains (losses) on risk management provides an indication of the results generated by the Trust's principal business activities prior to accounting for the impact of unrealized gains (losses) from risk management activities and how business activities are financed, assets are amortized or how the results are taxed. EBITDA before gains (losses) on risk management is calculated from the Consolidated Statements of Income and Accumulated Earnings and is defined as net revenue adjusted for unrealized gains (losses) on risk management less operating and administrative expenses.



Net Income Before Tax-Adjusted
Unrealized Gains (Losses) on Three Months Ended Nine Months Ended
Risk Management September 30 September 30
($ millions) 2007 2006 2007 2006
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Net income before tax-adjusted
unrealized gains (losses) on
risk management 30.7 28.8 76.8 87.2
Add (deduct): Unrealized gains (losses)
on risk management 1.1 - 1.6 -
Income tax expense on
risk management (0.4) - (1.4) -
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Net income (GAAP financial measure) 31.4 28.8 77.0 87.2
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Net income before tax-adjusted unrealized gains (losses) on risk management is a better reflection of performance than net income, as changes related to risk management are based on estimates relating to commodity prices and foreign exchange rates over time.



Funds from Operations Three Months Ended Nine Months Ended
September 30 September 30
($ millions) 2007 2006 2007 2006
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Funds from operations 47.6 43.2 125.1 119.9
Add (deduct): Net change in non-cash
working capital (16.4) (2.4) (1.0) (9.6)
Asset retirement
obligations settled (0.4) - (0.6) -
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Cash from operations
(GAAP financial measure) 30.8 40.8 123.5 110.3
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Funds from operations is used to assist management and investors in analyzing operating performance without regard to changes in the Trust's non-cash working capital in the period. Funds from operations as presented should not be viewed as an alternative to cash from operations, or other cash flow measures calculated in accordance with GAAP. Funds from operations is calculated from the Consolidated Statements of Cash Flows and is defined as cash provided by operating activities before changes in non-cash working capital and expenditures incurred to settle asset retirement obligations.



RESULTS OF OPERATIONS BY SEGMENT

Operating Income Three Months Ended Nine Months Ended
September 30 September 30
($ millions) 2007 2006 2007 2006
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Field Gathering and Processing 3.1 7.4 13.7 18.4
Extraction and Transmission 9.9 10.4 27.2 28.1
Power Generation 31.5 24.1 74.3 65.4
Energy Services (0.2) 1.6 2.0 2.5
Corporate (6.8) (9.8) (19.5) (19.8)
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37.5 33.7 97.7 94.6
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Operating income before unrealized
gains (losses) on risk management 36.4 33.7 96.1 94.6
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FIELD GATHERING AND PROCESSING

The Field Gathering and Processing segment includes natural gas gathering pipelines and processing facilities, as well as AltaGas' investments in businesses ancillary to the field gathering and processing business.



Financial Results Three Months Ended Nine Months Ended
September 30 September 30
($ millions) 2007 2006 2007 2006
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Revenue 33.4 34.7 103.4 102.7
Net revenue 31.5 32.3 98.0 95.2
Operating and administrative 21.9 19.0 64.8 59.5
Amortization 6.5 5.8 19.5 17.4
Operating income 3.1 7.4 13.7 18.4
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Operating Statistics Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
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Capacity (Mmcf/d)(1) 1,008 1,021 1,008 1,021
Throughput (gross Mmcf/d)(2) 510 537 532 557
Capacity utilization (%)(2) 51 53 53 55
Average working interest (%)(1) 92 92 92 92
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(1) As at September 30.
(2) Average for the period.

 


Three Months Ended September 30

Operating income in the FG&P segment in third quarter 2007 was $3.1 million compared to $7.4 million for the same quarter last year. Excluding the impact of the $1.9 million reversal recorded in second quarter 2006 for corporate costs previously charged to the segment, operating income decreased $2.4 million. $1.9 million of the decrease was due to lower throughput resulting mainly from natural declines and lower producer activity, as well as $0.5 million in one-time take-or-pay contractual provisions in the third quarter of 2006, $0.4 million of higher non-flowthrough operating and compensation costs and $0.5 million of higher amortization resulting from the expansion of existing facilities. These decreases were partially offset by $0.9 million as a result of recontracting at higher rates, routine equalization adjustments and the new Clear Hills facility.

Throughput in third quarter 2007 averaged 510 Mmcf/d compared to 537 Mmcf/d in third quarter 2006. The 5 percent decrease in throughput was primarily due to natural declines, lower producer activity and scheduled downtime. The impact of the scheduled downtime was approximately 1 percent or 5 Mmcf/d of total gross throughput, and had a negligible impact on operating income. In the North district, throughput decreased by 18 Mmcf/d due to natural declines, lower producer activity and scheduled downtime, partially offset by 8 Mmcf/d contributed by the new Clear Hills facility. The decline of 17 Mmcf/d in the South district was due to natural declines, lower producer activity and scheduled downtime. During the quarter, AltaGas' one-third interest in the Ikhil Joint Venture was sold as part of its divestiture plan for non-core production assets. The Ikhil Joint Venture delivered an average of approximately 1.5 Mmcf/d of sweet dry gas into an 8 Mmcf/d field processing facility. During the quarter, the 5 Mmcf/d Del Bonita facility was removed from service due to lack of success by area producers in finding significant reserves. The facility has been dismantled and the equipment has been redeployed.

Utilization reported in third quarter 2007 was 51 percent compared to 53 percent reported in the same quarter last year due to lower throughput as a result of natural declines and the slowdown in producer drilling.

Net revenue for the FG&P segment in third quarter 2007 was $31.5 million compared to $32.3 million for the same period in 2006. The decrease was due to lower throughput as a result of natural declines and lower producer activity, as well as lower operating cost flowthrough revenue. The decrease was partially offset by $1.9 million from increased rates, routine equalization adjustments and revenue from the new Clear Hills facility. The prior year's net revenue included $0.5 million of one-time take-or-pay contractual provisions.

Operating and administrative expense for third quarter 2007 was $21.9 million compared to $19.0 million for the same period in 2006. Results for third quarter 2006 included a one-time reversal of $1.9 million of corporate costs which were previously charged to the operating segment. The $1.0 million increase was primarily due to additional operating costs at the new Clear Hills facility and higher compensation costs.

Amortization expense for the FG&P segment in third quarter 2007 was $6.5 million compared to $5.8 million for the same period last year due to new and expanded facilities.

Operating income as a percentage of net revenue in third quarter 2007 was 10 percent compared to 23 percent in the same quarter in 2006. The decrease in the third quarter was primarily due to lower throughput, a one-time reversal of corporate costs in 2006, higher amortization and higher operating expenses. (See Non-GAAP Financial Measures section of this MD&A for description of operating income and net revenue.)

Nine Months Ended September 30

Operating income in the FG&P segment in the nine months ended September 30, 2007 was $13.7 million compared to $18.4 million for the same period last year. The decrease included $5.4 million due to lower throughput which was partially offset by $4.2 million of operating income from new facilities, increased rates and product revenues. Operating income also decreased as a result of $1.1 million in higher compensation costs, $1.0 million of amortization from maintenance capital and expanded facilities, and $1.5 million in lower one-time take-or-pay contractual provisions.

Throughput in the nine months ended September 30, 2007 averaged 532 Mmcf/d compared to 557 Mmcf/d for the same period in 2006. The 4 percent decrease was primarily due to natural declines and lower producer activity. The impact of these factors would have been more significant were it not for the throughput additions of 13 Mmcf/d contributed by AltaGas' new Clear Prairie, Clear Hills and Princess facilities. Of the 25 Mmcf/d throughput decrease, 14 Mmcf/d was attributable to the North district and the balance to the South district. In the North district, the Wabasca area experienced throughput declines of 10 Mmcf/d as a result of a less successful drilling program than the previous year. The decline in the South district was due to natural declines, partially offset by higher throughput from new wells at South Foothills.

Utilization for the nine months ended September 30 was 53 percent and 55 percent for 2007 and 2006 respectively. The decrease was due to lower throughput as a result of natural declines and the slowdown in producer drilling activity.

Net revenue for the nine months ended September 30, 2007 was $98.0 million compared to $95.2 million for the same period last year. The increase was due to $6.7 million of revenue generated from new facilities and $2.9 million from higher rates, and product revenues, partially offset by $5.4 million due to lower well tie-ins and natural declines. One-time take-or-pay contractual provisions of $1.5 million recorded in 2006 also contributed to the decrease in net revenue.

Operating and administrative expense for the nine months ended September 30, 2007 was $64.8 million compared to $59.5 million for the same period in 2006. The increase was mainly attributable to new facilities and $1.1 million of higher compensation costs.

Amortization expense for the FG&P segment for the nine months ended September 30, 2007 was $19.5 million compared to $17.4 million for the same period in 2006 due to new and expanded facilities.

Operating income as a percentage of net revenue in the nine months ended September 30, 2007 was 14 percent, compared to 19 percent in the same period in 2006. The decrease was due to lower throughput, lower take-or-pay adjustments and additional compensation costs. (See Non-GAAP Financial Measures section of this MD&A for description of operating income and net revenue.)

FG&P Outlook

Operating income in the FG&P segment in 2007 is expected to be lower than 2006 due to continued lower throughput. However, the commissioning of the Acme facility in the fourth quarter is expected to partially offset the impact of lower throughput for the remainder of 2007. While results in the FG&P segment are expected to be lower this year compared to last, AltaGas is continuing to execute its strategy of converting contracts to flowthrough operating costs, raising processing fees and managing operating costs while continuing to provide high-quality service. In third quarter 2007 three of four major contracts at one of the larger facilities were amended to operating cost flowthrough for the majority of volumes. This amendment is expected to substantially increase the operating income at this facility. This ongoing strategy should continue to improve returns on invested capital in low throughput times while positioning AltaGas to capture upside when gas production activity increases. The majority of AltaGas facilities are also moveable, providing the opportunity to redeploy equipment to areas that are more active and productive.

In 2007 AltaGas expects to spend approximately $37 million of capital in addition to the Acme coal bed methane processing facility and associated gathering and sales lines.

AltaGas' previously announced Noel natural gas pipeline and Pouce Coupe processing facility expansion project was deferred due to uncertainty around installation costs and low gas prices. AltaGas continues to pursue the expansion of the Pouce Coupe facility to provide gas processing infrastructure in the area.

The new 10 Mmcf/d new gas processing facility and associated gathering and sales lines near Acme, Alberta will process coal bed methane and is expected to cost $13 million. The facility is expected to be in service in November 2007.

AltaGas sold its one-third interest in the Ikhil Joint Venture effective July 31, 2007. There was a negligible gain recorded on the sale. For the period October to December 2006, these assets contributed approximately $0.4 million to the operating income of the FG&P segment.

EXTRACTION AND TRANSMISSION

The Extraction and Transmission (E&T) segment consists of interests in four ethane and NGL extraction plants, one fractionation facility, five natural gas transmission systems and one condensate pipeline.



Financial Results Three Months Ended Nine Months Ended
September 30 September 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue 32.7 41.1 103.6 114.6
Net revenue 17.0 17.9 48.1 47.7
Operating and administrative 5.0 5.6 14.8 13.8
Amortization 2.1 1.9 6.1 5.8
Operating income 9.9 10.4 27.2 28.1
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Operating Statistics Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Extraction inlet capacity (Mmcf/d)(1) 554 539 554 539
Extraction volumes (Bbls/d)(2) 16,859 19,880 19,747 19,421
Transmission volumes (Mmcf/d)(2)(3) 407 388 407 396
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) As at September 30.
(2) Average for the period.
(3) Excludes condensate pipeline volumes.

 


Three Months Ended September 30

Operating income in the E&T segment in third quarter 2007 was $9.9 million compared to $10.4 million for the same period in 2006. The decrease was primarily due to lower extraction volumes produced, as well as higher revenue deferral in the transmission business resulting from actual volumes transported being lower than contracted volumes on the Suffield transmission system. The average frac spread was $25.00/Bbl for the third quarter of 2007 and 2006. Partially offsetting the decrease in operating income in the segment were higher frac spread-exposed NGL volumes in the extraction business as a result of the increased ownership at one of the Empress facilities and the expansion of the Cold Lake transmission system.

Average ethane and NGL volumes in the extraction business were lower in third quarter 2007 compared to the same quarter last year mainly due to lower downstream natural gas demand and a scheduled 10-day turnaround at the Edmonton extraction plant, partially offset by increased volumes at the Empress facilities. Transmission volumes were up mainly due to higher volumes moved on the Suffield system.

Net revenue in third quarter 2007 was $17.0 million compared to $17.9 million in the same period in 2006. Net revenue in the quarter was down due to lower ethane volumes produced in the extraction business and higher revenue deferral in the transmission business. The decrease was partially offset by higher volumes exposed to frac spread, the increased ownership at one of the Empress facilities and the expansion of the Cold Lake transmission system.

Operating and administrative expense in third quarter 2007 was $5.0 million compared to $5.6 million for the same period in 2006. The decrease was mainly due to lower volumes processed through the Edmonton extraction plant, partially offset by increased costs at one of the Empress facilities due to the increased ownership.

Amortization expense in third quarter 2007 was $2.1 million compared to $1.9 million for the same period in 2006. The slight increase was due to the increased ownership at one of the Empress facilities and the enhanced ethane recovery project.

Operating income as a percentage of net revenue in third quarter 2007 and 2006 was 58 percent. (See Non-GAAP Financial Measures section of this MD&A for description of operating income and net revenue.)

Nine Months Ended September 30

Operating income in the E&T segment for the nine months ended September 30, 2007 was $27.2 million compared to $28.1 million for the same period in 2006. Operating income decreased $0.8 million as a result of lower frac spreads and $0.7 million as a result of revenue deferral resulting from lower than contracted volumes transported on the Suffield transmission system. The decreases were partially offset by higher frac spread-exposed NGL volumes in the extraction business and the expansion of the Cold Lake transmission system, which began contributing to income in May 2007. Although frac spreads remained strong at $18.00/Bbl for the nine months ended September 30, 2007, they were lower than the historic high of $20.50/Bbl for the same period in 2006.

Average ethane and NGL volumes increased as a result of higher volumes processed through the Empress facilities. Transmission volumes were up mainly due to higher volumes transported on the Suffield system.

Net revenue in the nine months ended September 30, 2007 was $48.1 million, compared to $47.7 million for the same period in 2006. The increase was due to higher ethane and NGL volumes from additional gas supply arrangements, increased ownership at one of the Empress facilities, the expansion of the Cold Lake transmission system and higher operating cost recovery. These increases were partially offset by lower frac spreads and deferred revenue due to lower than contracted volumes on the Suffield system.

Operating and administrative expense for the nine months ended September 30, 2007 was $14.8 million compared to $13.8 million for the same period last year. The increase was due to the increased ownership at one of the Empress facilities and higher variable costs associated with increased utilization at the extraction facilities.

Amortization expense in the nine months ended September 30, 2007 was $6.1 million compared to $5.8 million for the same period in 2006. The increase was due to the increased ownership at one of the Empress facilities and the enhanced ethane recovery project.

Operating income as a percentage of net revenue in the nine months ended September 30, 2007 was 57 percent compared to 59 percent in the same period last year. The decrease was primarily due to lower frac spreads in the extraction business and higher operating cost recoveries, partially offset by higher extraction volumes. (See Non-GAAP Financial Measures section of this MD&A for description of operating income and net revenue.)

E&T Outlook

AltaGas expects results in the E&T segment in 2007 to be higher than 2006. Results for the remainder of 2007 are expected to be stronger than fourth quarter 2006 due to higher frac spreads, higher volumes exposed to frac spreads and lower revenue deferral in the transmission business. The enhanced ethane recovery project at the Edmonton extraction facility, completed in January 2007, increased ethane production capability by 800 Bbls/d. The full-year production impact of the enhanced ethane recovery project and increased ownership of one of the Empress facilities are both expected to contribute to increased earnings in 2007. The expansion of the Cold Lake transmission system is also expected to contribute to increased earnings in 2007. Based on projected volumes on the Suffield system, AltaGas expects to record revenue deferrals in 2007 similar to those recorded in 2006.

POWER GENERATION

The Power Generation segment comprises 378 MW of total power generation capacity in Alberta through a 50 percent ownership interest in the Sundance B power purchase arrangements (PPA) and a capital lease for 25 MW of gas-fired power peaking capacity.



Financial Results Three Months Ended Nine Months Ended
September 30 September 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue 51.7 48.7 136.7 140.0
Net revenue 33.9 26.1 81.3 71.8
Operating and administrative 0.5 0.2 1.4 0.9
Amortization 1.9 1.8 5.6 5.5
Operating income 31.5 24.1 74.3 65.4
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Operating Statistics Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Volume of power sold (GWh) 673 669 1,988 2,167
Average price received on the sale
of power ($/MWh)(1) 76.92 72.88 68.77 64.60
Alberta Power Pool average spot
price ($/MWh)(1) 92.00 94.87 68.53 68.36
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Average for the period.

 


Three Months Ended September 30

Operating income for the Power Generation segment in third quarter 2007 was $31.5 million compared to $24.1 million for the same quarter in 2006. Operating income increased by $7.4 million due to higher hedge prices, lower PPA costs mainly as a result of a favourable 30-day rolling average power price received during the Sundance scheduled outage and lower transmission costs. These increases were partially offset by lower average spot power prices and costs incurred to comply with Alberta's Specified Gas Emitters Regulation (SGER).

Net revenue in third quarter 2007 was $33.9 million compared to $26.1 million for the same period in 2006 due to $4.5 million from higher hedge prices, $4.3 million from lower PPA costs mainly as a result of a favourable 30-day rolling average power price received during the Sundance scheduled outage and $1.0 million from lower transmission costs. These increases were partially offset by lower revenue from unhedged sales of $1.3 million and costs incurred to comply with Alberta's SGER of $0.7 million.

Operating and administrative expense was $0.5 million in third quarter 2007 compared to $0.2 million for the same period in 2006. In March 2007 AltaGas began providing operating and maintenance services to the leased peaking plants. While this has not materially impacted operating income, it has resulted in slightly lower cost of sales offset by higher operating expenses.

Amortization expense of $1.9 million in third quarter 2007 was similar to $1.8 million in the same period in 2006.

Operating income as a percentage of net revenue in third quarter 2007 was 93 percent compared to 92 percent in the same period in 2006. (See Non-GAAP Financial Measures section of this MD&A for description of operating income and net revenue.)

Nine Months Ended September 30

Operating income for the nine months ended September 30, 2007 was $74.3 million compared to $65.4 million for the same period in 2006. The increase was due to higher power prices received on both hedged and unhedged sales, as well as lower PPA costs mainly as a result of a favourable 30-day rolling average power price received during the Sundance scheduled outage, and lower transmission costs. These increases were partially offset by the expiration of the Genesee contract in March 2006 and costs incurred to comply with Alberta's SGER.

The volume of power sold in the nine months ended September 30, 2007 was lower than the same period of 2006 primarily as a result of the Genesee contract expiration on March 31, 2006.

Net revenue for the nine months ended September 30, 2007 was $81.3 million compared to $71.8 million for the same period in 2006. The increase included $8.1 million due to higher power prices, $5.0 million due to lower PPA costs, mainly as a result of a favourable 30-day rolling average power price received during the Sundance scheduled outage, and lower transmission costs of $1.1 million. These increases were partially offset by the expiration of the Genesee contract which contributed $4.1 million and $0.7 million of costs incurred to comply with Alberta's SGER.

Operating and administrative expense of $1.4 million in the nine months ended September 30, 2007 was higher than the $0.9 million reported in the nine months ended September 30, 2006, primarily due to the operating and maintenance services AltaGas began providing to the leased peaking plants in March 2007.

Amortization expense of $5.6 million in the nine months ended September 30, 2007 was similar to $5.5 million in the same period in 2006.

Operating income as a percentage of net revenue was 91 percent in the nine months ended September 30, 2007 and 2006. (See Non-GAAP Financial Measures section of this MD&A for description of operating income and net revenue.)

Power Generation Outlook

Operating income in the Power Generation segment is expected to be higher in 2007 than in 2006. The contribution from hedged power volumes is expected to be higher than in 2006 as a result of higher average hedge prices of approximately $66/MWh compared to $60/MWh. Consistent with AltaGas' hedge program, approximately two-thirds of the power available from the Sundance B PPAs has been hedged and the remaining one-third of power volumes is exposed to the spot price in Alberta. Current forward prices for the remainder of 2007 are slightly higher than what was realized in the nine months ended September 30, 2007 but below what was realized in the fourth quarter of 2006. As a result AltaGas expects spot prices for 2007 as a whole to average lower than in 2006. Operating income for the year is expected to be higher due to higher average hedge prices and lower costs. For 2008, AltaGas has hedged at prices that are significantly higher than 2007's $66/MWh.

On June 27, 2007 the Alberta government passed the Specified Gas Emitters Regulation which requires large final emitters to reduce greenhouse gas emissions by 12 percent beginning July 1, 2007. The regulation is expected to increase 2007 operating expenses by approximately $2.1 million (approximately $5.0 million annualized based on normal generation at Sundance). To the extent these costs can be recovered through higher power pool prices or by the reduction of emissions or by creating or acquiring offsets, the impact of the increased costs would be mitigated.

In first quarter 2007 AltaGas announced the acquisition of 14.4 MW of power generation capacity, increasing its gas-fired generation under operation by more than 55 percent to 39.4 MW. The new peaking generation will be installed at the Bantry and Parkland FG&P locations with access to natural gas supply and the electrical grid. The facilities are expected to be integrated into ongoing operations, with the Bantry location to be in service by the end of 2007 and the Parkland location to be in service by the end of first quarter 2008. Installation of the generating capacity is estimated to cost approximately $10 million upon completion and is expected to be accretive to net income and cash flow once operational.

AltaGas currently owns 100 percent interest in the Bear Mountain Wind Limited Partnership (BMWLP) and the Bear Mountain wind park. AltaGas intends to finance the project, currently estimated at approximately $200 million, through its credit facilities and intends to include one or more third-party investors in the project, which will reduce ownership in the wind park to approximately 45 percent. The Bear Mountain wind park was recently optimized from 120 MW to approximately 100 MW and is underpinned by a 25-year electricity purchase agreement with BC Hydro. BMWLP continues to make progress toward finalizing its wind turbine purchase and service agreements with Enercon GmbH, a leading German manufacturer of gearless turbines. Construction is scheduled to begin in November 2007, with a planned in service date of late 2009. In late August the project obtained its Environmental Certificate from the BC Government, however the project continues to be subject to various approvals, which are anticipated to be received by late fall 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 included a small portfolio of oil and natural gas production assets which was sold effective May 31, 2007.



Financial Results Three Months Ended Nine Months Ended
September 30 September 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue 211.1 211.2 795.3 694.0
Net revenue 3.9 6.1 16.9 18.6
Operating and administrative 3.5 3.3 12.1 12.5
Amortization 0.6 1.2 2.8 3.6
Operating income (loss) (0.2) 1.6 2.0 2.5
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Operating Statistics Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Energy management service contracts(1) 1,451 1,342 1,451 1,342
Average volumes transacted (GJ/d)(2) 342,143 325,419 372,931 319,589
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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.

 


Three Months Ended September 30

The operating loss in the Energy Services segment in third quarter 2007 was $0.2 million compared to operating income of $1.6 million for the same quarter in 2006. Operating income decreased as a result of a one-time reversal of $0.9 million of corporate costs in third quarter 2006 which were previously charged to the operating segment, lower contributions from the energy management business due to non-recurring earnings of $0.7 million and higher gas costs of $0.6 million to meet a natural gas supply contract. These reductions were partially offset by $0.3 million due to higher fixed-price commodity gas volumes and increased transportation revenue.

Net revenue in third quarter 2007 was $3.9 million compared to $6.1 million for the same period in 2006. Net revenue decreased as a result of lower operating revenue of $1.5 million from the oil and gas production assets which were sold in May 2007, $0.7 million of non-recurring earnings reported in third quarter 2006, and $0.6 million of higher gas costs to meet a natural gas supply contract. These reductions were partially offset by $0.5 million due to higher fixed-price commodity gas volumes and increased transportation revenues.

Operating and administrative expense in third quarter 2007 was $3.5 million compared to $3.3 million for the same quarter in 2006. The increase in third quarter 2007 was due to a one-time reversal of corporate costs of $0.9 million in third quarter 2006. This increase was partially offset by lower costs as a result of the sale of oil and natural gas production assets in May 2007.

Amortization expense in third quarter 2007 was $0.6 million compared to $1.2 million in the same quarter in 2006, primarily due to the sale of oil and natural gas production assets in May 2007.

Operating loss was $0.2 million in third quarter 2007 as compared to an operating income of $1.6 million, or 26 percent of net revenue, for the same period in 2006. The decrease was a result of lower contributions from the energy management business due to non-recurring earnings reported in 2006 and higher gas costs to meet a natural gas supply contract. (See Non-GAAP Financial Measures section of this MD&A for description of operating income and net revenue.)

Nine Months Ended September 30

Operating income in the Energy Services segment in the nine months ended September 30, 2007 was $2.0 million compared to $2.5 million for the same period in 2006. The decrease was due to $2.2 million of non-recurring earnings reported in 2006 in the energy management business, higher gas costs of $1.1 million, and lower contributions of $0.6 million from the operations of the oil and natural gas production assets which were sold effective May 31, 2007. These decreases were partially offset by $1.9 million due to growth in electricity and gas services business and the one-time pre-tax gain of $1.5 million from the sale of oil and natural gas production assets.

Net revenue in the nine months ended September 30, 2007 was $16.9 million compared to $18.6 million in the same period in 2006. The decrease included a $2.6 million lower contribution due to lower volumes and prices related to the operation of the oil and gas production assets, $2.2 million related to non-recurring earnings in the energy management business, and $1.1 million due to higher gas costs to supply a natural gas contract. These decreases were partially offset by $1.9 million from higher fixed-price commodity gas sales volumes, the one-time pre-tax gain from the sale of oil and natural gas production assets of $1.5 million, and $0.8 million from higher transportation revenues and the expansion into the Ontario electricity market and growth in targeted sectors.

Operating and administrative expense the nine months ended September 30, 2007 was $12.1 million compared to $12.5 million for the same period in 2006. The decrease was primarily due to lower costs related to the operation of the oil and natural gas production assets ($1.1 million), partially offset by $0.8 million in higher administrative expenses to generate growth in gas sales volumes, transportation revenues and expansion into the electricity market.

Amortization expense in the nine months ended September 30, 2007 was $2.8 million compared to $3.6 million in the same period in 2006. The decrease was primarily due to the sale of the oil and natural gas production assets. Amortization expense related to oil and natural gas production assets was $1.2 million in the nine months ended September 30, 2007 compared to $2.2 million in the same period in 2006.

Operating income as a percentage of net revenue decreased to 12 percent in the nine months ended September 30, 2007 from 13 percent in the same period in 2006. Excluding the one-time gain, operating income as a percentage of net revenue was 3 percent in the nine months ended September 30, 2007. The decrease was the result of non-recurring earnings reported in 2006 in the energy management business, higher gas costs to meet a natural gas supply contract and lower contributions from the operation of the oil and natural gas production assets, partially offset by the one-time pre-tax gain of $1.5 million from the sale of oil and natural gas production assets, increased margins in the gas services business, and expansion into the electricity market. (See Non-GAAP Financial Measures section of this MD&A for description of operating income and net revenue.)

Energy Services Outlook

AltaGas expects results in the Energy Services segment in 2007 to be lower than 2006 results. Non-recurring earnings realized in 2006 will continue to affect the energy management business through the balance of 2007, offsetting expected continued growth in the energy management business. This growth will be based on continued expansion into natural gas and electricity supply management and a focused national account strategy in specific targeted sectors.

Lower revenues resulting from higher gas costs related to a natural gas supply contract are expected to offset growth in the gas services business in 2007. The business is expected to grow as a result of locking in back-to-back buy and sell gas contracts which is expected to produce fixed margins for terms of up to five years. In addition, the gas services business is expected to have continued growth in its transportation business.

The Energy Services segment is an important element in increasing the value of assets in AltaGas' other segments. Energy Services works with the other segments to optimize AltaGas' assets and in this capacity is expected to contribute to earnings growth across AltaGas.

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, return on capital and operating income as a percentage of net revenue 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 Nine Months Ended
September 30 September 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue(1) 0.8 0.5 3.5 2.8
Net revenue 2.0 0.5 5.1 2.8
Operating and administrative 8.2 9.7 22.8 20.8
Amortization 0.6 0.6 1.8 1.8
Operating loss (6.8) (9.8) (19.5) (19.8)
Operating loss before unrealized gains
(losses) on risk management (7.9) (9.8) (21.1) (19.8)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Excludes unrealized gains (losses) on risk management.

 


Three Months Ended September 30

The operating loss before unrealized gains on risk management for third quarter 2007 was $7.9 million compared to $9.8 million for the same period in 2006. The decrease was due to lower operating and administrative costs due to an adjustment of $3.0 million in third quarter 2006 related to corporate costs previously charged to the operating segments in first half 2006 and an increase of $0.3 million in interest and equity income. These decreases were partially offset by a one-time $1.5 million write-off of costs related to the deferred Noel project.

Revenue in third quarter 2007 was $0.8 million compared to $0.5 million for the same period in 2006 due to higher interest and equity income.

Effective January 1, 2007 AltaGas adopted accounting standards that require the fair value of all financial instruments to be reflected on the financial statements. On adoption, January 1, 2007, AltaGas recorded financial instrument related assets and liabilities of $107.8 million and $110.6 million respectively. The net impact to accumulated earnings and to other comprehensive income on January 1, 2007 was $0.2 million and $2.6 million respectively. In third quarter 2007, AltaGas recorded a $1.1 million unrealized gain related to risk management contracts and back-to-back commodity purchases and sales.

Operating and administrative expense for third quarter 2007 was $8.2 million compared to $9.7 million for the same period last year. The decrease was attributable to lower administrative costs due to a $3.0 million adjustment in third quarter 2006 related to corporate costs previously charged to the operating segments in first half 2006, partially offset by a one-time $1.5 million write-off of costs related to the deferred Noel project. Total costs of the Noel project were $3.4 million, of which $1.6 million are recoverable.

Amortization expense for third quarter 2007 was consistent with the same period last year.

Nine Months Ended September 30

The operating loss before unrealized gains on risk management for the nine months ended September 30, 2007 was $21.1 million compared to $19.8 million for the same period in 2006. The increased loss was primarily due to $1.5 million in higher compensation costs and a one-time write-off of $1.5 million in costs related to the Noel project deferral. These increases were partially offset by $1.5 million in lower general corporate overhead and a one-time gain of $0.4 million on the unwinding of interest rate swaps as a result of the issuance of $100 million of medium-term notes (MTNs) in January 2007. Effective second quarter 2007 AltaGas reduced its influence over Taylor NGL Limited Partnership (Taylor) and commenced accounting for its interest in Taylor using the cost method. The effect of the change in the accounting method on the operating loss in the nine months ended September 30, 2007 was negligible.

Revenue in the nine months ended September 30, 2007 was $3.5 million compared to $2.8 million for the same period in 2006 primarily due to the gain recorded as a result of unwinding interest rate swaps in first quarter 2007 of $0.4 million and to $0.3 million from higher interest revenue.

Effective January 1, 2007 AltaGas adopted accounting standards that require the fair value of all financial instruments to be reflected on the financial statements. For the nine months ended September 30, 2007, AltaGas recorded a $1.6 million unrealized gain related to risk management contracts and back-to-back commodity purchases and sales.

Operating and administrative expense for the nine months ended September 30, 2007 was $22.8 million compared to $20.8 million for the same period last year. The increase was primarily related to $2.0 million in higher compensation costs and a write-off of costs related to the Noel project of $1.5 million, partially offset by lower general corporate overhead.

Amortization expense for the nine months ended September 30, 2007 was consistent with the same period last year.

Corporate Outlook

The operating loss in the Corporate segment is expected to be slightly higher than in 2006. Revenues from the investments in Taylor and AltaGas Utility Group Inc. (Utility Group) are expected to stay relatively flat and AltaGas expects lower operating and administrative expense due to lower ongoing costs to meet certification requirements mandated by the Canadian Securities Administrators. The lower costs of meeting certification requirements are expected to be more than offset by higher compensation costs.

The effects of financial instruments are based on estimates relating to commodity prices and foreign exchange rates over time. The actual amounts will vary based on these factors. Consequently, management is 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 third quarter 2007 AltaGas increased its capital assets, long-term investments and other assets by $12.3 million compared to $25.1 million in third quarter 2006. The increase was due to acquiring an additional $20.3 million in capital assets and $1.1 million increase in the fair value of assets available for sale, partially offset by the special distribution of AltaGas Utility Group Inc. common shares valued at $4.2 million, $2.7 million collected on a note receivable and the elimination of $2.3 million in loans advanced to the Bear Mountain Wind Limited Partnership (BMWLP) as a result of AltaGas acquiring all the outstanding partnership units in BMWLP. During third quarter 2007 AltaGas disposed of $14.4 million in original cost of assets due mainly to the sale of its interest in the Ikhil Joint Venture. The gain on sale was negligible.

During the nine months ended September 30, 2007 AltaGas increased its capital assets by $53.7 million compared to $58.8 million in the same period in 2006. The increase was mainly due to the acquisition of capital assets of $38.2 million, a $12.7 million increase as a result of the increase in the fair value of assets available for sale and a promissory note of $9.2 million recorded in long-term investments. These increases were partially offset by the special distribution of Utility Group common shares valued at $4.2 million and the elimination of $2.3 million in loans advanced to BMWLP. The $46.2 million of disposals included the $30.2 million disposition of the original cost of the oil and natural gas production assets in Energy Services and the original cost of the $14.4 million interest in the Ikhil Joint Venture.



Net Invested Capital - Investment Type Three Months Ended
September 30, 2007
Field
Gathering Extraction
and and Power Energy
($ millions) Processing Transmission Generation Services Corporate Total
----------------------------------------------------------------------------
Invested
capital:
Capital assets 5.6 0.8 5.4 8.0 0.5 20.3
Long-term
investments
and other
assets - - (1.0) - (7.0) (8.0)
----------------------------------------------------------------------------
5.6 0.8 4.4 8.0 (6.5) 12.3
Disposals:
Capital assets (14.3) (0.1) - - - (14.4)
----------------------------------------------------------------------------
Net invested
capital (8.7) 0.7 4.4 8.0 (6.5) (2.1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Net Invested Capital - Investment Type Nine Months Ended
September 30, 2007
Field
Gathering Extraction
and and Power Energy
($ millions) Processing Transmission Generation Services Corporate Total
----------------------------------------------------------------------------
Invested
capital:
Capital assets 13.8 4.8 9.3 8.7 1.6 38.2
Long-term
investments
and other
assets - - (0.5) - 16.0 15.5
----------------------------------------------------------------------------
13.8 4.8 8.8 8.7 17.6 53.7
Disposals:
Capital assets (15.6) (0.4) - (30.2) - (46.2)
----------------------------------------------------------------------------
Net invested
capital (1.8) 4.4 8.8 (21.5) 17.6 7.5
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Net Invested Capital - Investment Type Three Months Ended
September 30, 2006
Field
Gathering Extraction
and and Power Energy
($ millions) Processing Transmission Generation Services Corporate Total
----------------------------------------------------------------------------
Invested
capital:
Capital assets 23.3 0.6 (1.3) - 0.9 23.5
Long-term
investments
and other
assets - - 2.1 - (0.5) 1.6
----------------------------------------------------------------------------
23.3 0.6 0.8 - 0.4 25.1
Disposals:
Capital assets - - - - - -
----------------------------------------------------------------------------
Net invested
capital 23.3 0.6 0.8 - 0.4 25.1
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Net Invested Capital - Investment Type Nine Months Ended
September 30, 2006
Field
Gathering Extraction
and and Power Energy
($ millions) Processing Transmission Generation Services Corporate Total
----------------------------------------------------------------------------
Invested
capital:
Capital assets 51.4 1.4 - 0.4 1.3 54.5
Long-term
investments
and other
assets - - 4.2 - 0.1 4.3
----------------------------------------------------------------------------
51.4 1.4 4.2 0.4 1.4 58.8
Disposals:
Capital assets (0.5) - - - - (0.5)
----------------------------------------------------------------------------
Net invested
capital 50.9 1.4 4.2 0.4 1.4 58.3
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


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

Maintenance capital projects totaling $2.1 million in third quarter 2007 (third quarter 2006 - $0.8 million) were undertaken in the FG&P and E&T segments. Of the $11.8 million in growth capital spent in third quarter 2007 (third quarter 2006 - $23.2 million), $7.8 million was due to the Sarnia Airport Pool Storage project in the Energy Services segment, $2.7 million was due to the purchase of Bear Mountain Wind Limited Partnership assets in the Power Generation segment, and $3.7 million was due to growth in the FG&P segment, mainly for the new Acme coal bed methane processing facility. This growth was partially offset by the $4.2 million special distribution of Utility Group shares to AltaGas unitholders. AltaGas now holds 19.6 percent of the common shares of AltaGas Utility Group Inc. Administrative invested capital increased by $1.1 million as a result of the increase in the fair value of assets available for sale and $1.0 million due to expenditures for computer hardware and software. These increases were more than offset by a $2.7 million payment on a promissory note, resulting in administrative capital of negative $1.6 million in the quarter, compared to $1.1 million of administrative capital spent in third quarter 2006.

Maintenance capital projects totaling $5.4 million in the nine months ended September 30, 2007 ($4.0 million in the same period 2006) were undertaken primarily in the FG&P segment. Of the $24.6 million spent on growth capital in the first nine months of 2007, $7.8 million was due to the Sarnia Airport Pool Storage project in the Energy Services segment, $4.0 million was due to new peaking generation equipment in the Power Generation segment, $3.6 million was due to the new Acme CBM processing facility, $3.6 million was due to the purchase of BMWLP assets and $3.1 million was for the expansion of existing facilities in the FG&P segment. These increases in growth capital were partially offset by a $4.2 million special distribution of Utility Group shares to Trust unitholders. Administrative capital increased by $23.7 million due to a $12.5 million increase in the fair value of assets available for sale, $9.2 million due to a promissory note received from the sale of oil and natural gas production assets and an additional $2.1 million due to expenditures on computer hardware and software.



Invested Capital - Use Three Months Ended
September 30, 2007
Field
Gathering Extraction
and and Power Energy
($ millions) Processing Transmission Generation Services Corporate Total
----------------------------------------------------------------------------
Invested
capital:
Maintenance 1.4 0.7 - - - 2.1
Growth 3.7 (0.1) 4.4 8.0 (4.2) 11.8
Administrative 0.5 - - - (2.1) (1.6)
----------------------------------------------------------------------------
Invested
capital 5.6 0.6 4.4 8.0 (6.3) 12.3
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Invested Capital - Use Nine Months Ended
September 30, 2007
Field
Gathering Extraction
and and Power Energy
($ millions) Processing Transmission Generation Services Corporate Total
----------------------------------------------------------------------------
Invested
capital:
Maintenance 4.0 1.4 - - - 5.4
Growth 8.9 3.4 8.8 8.1 (4.6) 24.6
Administrative 0.9 - - 0.6 22.2 23.7
----------------------------------------------------------------------------
Invested
capital 13.8 4.8 8.8 8.7 17.6 53.7
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Invested Capital - Use Three Months Ended
September 30, 2006
Field
Gathering Extraction
and and Power Energy
($ millions) Processing Transmission Generation Services Corporate Total
----------------------------------------------------------------------------
Invested
capital:
Maintenance 0.7 0.1 - - - 0.8
Growth 22.5 0.4 0.8 - (0.5) 23.2
Administrative 0.1 0.1 - - 0.9 1.1
----------------------------------------------------------------------------
Invested
capital 23.3 0.6 0.8 - 0.4 25.1
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Invested Capital - Use Nine Months Ended
September 30, 2006
Field
Gathering Extraction
and and Power Energy
($ millions) Processing Transmission Generation Services Corporate Total
----------------------------------------------------------------------------
Invested
capital:
Maintenance 3.3 0.6 - 0.1 - 4.0
Growth 48.0 0.6 4.2 0.2 (0.6) 52.4
Administrative 0.1 0.1 - 0.2 2.0 2.4
----------------------------------------------------------------------------
Invested
capital 51.4 1.3 4.2 0.5 1.4 58.8
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


FINANCIAL INSTRUMENTS

The Trust is exposed to market risk and potential loss from changes in the value of financial instruments. AltaGas enters into financial derivative contracts to manage exposure to fluctuations in commodity prices, interest rates and foreign exchange rates, particularly in the Power Generation segment and with respect to interest rates on debt. During the three-month period ended September 30, 2007 the Trust had positions in the following types of derivatives:

Commodity forward contracts: The Trust executes gas, power, and other commodity forward contracts to manage its asset portfolio and lock in margin from back-to-back purchase and sale agreements. In a forward contract, one party agrees to deliver a specified amount of an underlying asset to the other party at a future date at a specified price. The Energy Services segment transacts primarily on this basis.

Commodity swap contracts: The Trust executes fixed for floating power price swaps to manage its power asset portfolio and NGL frac spreads. A fixed for floating price swap is an agreement between two counterparties to exchange a fixed price for a floating price. The Power Generation segment's results are significantly affected by the price of electricity in Alberta. AltaGas employs derivative commodity instruments for the purpose of managing the Trust's exposure to power price volatility. Alberta Power Pool settles power prices on an hourly basis and whereas prices ranged from $6.95/MWh to $999.99/MWh in third quarter 2007, the average spot price for the quarter was $92.00/MWh. AltaGas moderated the impact of this volatility on its business through the use of financial hedges on a portion of its power portfolio that management deemed optimal. The average price received for power by the Trust in third quarter 2007 was $76.92/MWh.

Interest rate forward contracts: The Trust enters into interest rate swaps under which cash flows of a fixed rate are exchanged for those of a floating rate. At September 30, 2007 the Trust had interest rates fixed through swap transactions with varying terms to maturity on drawn bank debt of $15.0 million. Including AltaGas' MTNs and capital leases, the rate has been fixed on almost 100 percent of AltaGas' debt.

Foreign exchange forward contracts: Foreign exchange exposure created by transacting commercial arrangements in foreign currency is managed through the use of foreign exchange forward contracts where a fixed rate is locked in against a floating rate. The Trust's foreign exchange risk was not material at September 30, 2007.

LIQUIDITY AND CAPITAL RESOURCES

The Trust historically has used debt and equity financing to the extent that funds from operations and proceeds from the Distribution Reinvestment Plan (DRIP) were insufficient to fund distributions, capital expenditures, acquisitions and working capital changes from financing and investing activities. Should larger acquisitions require financing beyond existing sources, management is confident that equity and debt capital markets could be accessed to provide additional financing.

At this time AltaGas does not reasonably expect any currently known trend or uncertainty to affect the Trust's ability to access its historical sources of cash, except that cash from operations may be impacted by the proposed tax on the taxable component of the Trust's distribution effective in the 2011 taxation year.



Cash Flows Three Months Ended Nine Months Ended
September 30 September 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Cash from operations 30.8 40.8 123.5 110.3
Investing activities (8.9) (24.6) (35.9) (70.6)
Financing activities (21.8) (15.0) (88.5) (39.3)
----------------------------------------------------------------------------
Change in cash 0.1 1.2 (0.9) 0.4
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Cash from Operations

Cash from operations reported on the Consolidated Statements of Cash Flows decreased by 25 percent to $30.8 million in third quarter 2007 from $40.8 million in the same period 2006. Although funds from operations increased in third quarter 2007 ($47.6 million) compared to the same period in 2006 ($43.2 million), the increase was more than offset by a lower change in non-cash working capital resulting from the timing of cash flow and commodity pricing. Cash from operations increased by 12 percent to $123.5 million in the nine months ended September 30, 2007 from $110.3 million in the same period last year. (See Non-GAAP Financial Measures section of this MD&A for description of funds from operations.)

Working capital was $29.3 million at the end of third quarter 2007 compared to $23.7 million at December 31, 2006. The working capital ratio remained the same at 1.1 for the end of third quarter 2007 and at December 31, 2006.



Working Capital September 30 December 31
($ millions) 2007 2006
----------------------------------------------------------------------------
Current assets 275.4 263.4
Current liabilities 246.1 239.7
----------------------------------------------------------------------------
Working capital 29.3 23.7
Current ratio 1.1 1.1
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Investing Activities

Cash used for investing activities in third quarter 2007 was $8.9 million compared to $24.6 million in the same period in 2006. The decrease in cash used for investing activities was due to lower acquisitions of capital assets as well as higher proceeds on disposition of assets in third quarter 2007 compared to the same period last year. Cash used in investing activities for the nine months ended September 30, 2007 was $35.9 million compared to $70.6 million in the same period of 2006. The decrease was due to a lower amount of cash used to acquire capital assets, as well as higher proceeds on disposition of non-core assets. A description of the acquisitions and investments comprising these amounts is in the Invested Capital section of this MD&A.

Financing Activities

Cash used for financing activities in third quarter 2007 was $21.8 million compared to $15.0 million in the same period in 2006. The increase was due to higher distributions paid to unitholders, a reduction to long-term debt and lower equity issuances, partially offset by an increase in short-term debt. For the nine months ended September 30, 2007 cash used for financing activities was $88.5 million compared to $39.3 million in the same period in 2006. The increase was primarily due to a reduction of long-term debt and an increase in distributions. The reduction in long-term debt in 2007 was primarily a result of higher cash from operations and lower cash used in investing activities.

Capital Resources

The use of debt or equity funding is based on AltaGas' capital structure determined by considering the norms and risks associated with each of its business segments. At September 30, 2007 AltaGas had total debt outstanding of $229.1 million, down from $265.5 million as at December 31, 2006. At September 30, 2007 the Trust had $200.0 million in MTNs outstanding and had access to prime loans, bankers' acceptances and letters of credit through bank lines totaling $425.0 million. At September 30, 2007 the Trust had drawn bank debt of $17.9 million and letters of credit outstanding of $71.0 million.

In third quarter 2007 AltaGas renewed its credit facility, added an accordion feature of $75.0 million and extended the maturity date to September 30, 2010.

All of the borrowing facilities have financial tests and other covenants customary for these types of facilities, which must be met at each quarter end. AltaGas has been in compliance with these covenants each quarter since the establishment of the facilities.

AltaGas' target debt-to-total capitalization ratio is 40 to 45 percent. The Trust's debt-to-total capitalization ratio at September 30, 2007 was 29.0 percent, down from 33.4 percent at December 31, 2006. The Trust's earnings interest coverage for the rolling 12 months ended September 30, 2007 was 10.52 times.

The Dominion Bond Rating Service (DBRS) rates AltaGas Income Trust and the MTNs issued by AltaGas Income Trust at BBB (low) with a positive trend. Standards & Poor's (S&P) rates the Trust's long-term corporate credit at BBB- with a stable outlook, and the senior unsecured debt at BBB-. The Trust has a stability rating of SR-3 from S&P and STA-3 (middle) from DBRS.

Credit ratings are intended to provide investors with an independent measure of credit quality of an issue of securities and are indicators of the likelihood of payments and of the capacity and willingness of an entity to meet its financial commitment on an obligation in accordance with the terms of an obligation. Stability ratings are intended to convey the opinion of a rating agency in respect of the relative stability and sustainability of the Trust's distribution stream when compared to other rated Canadian income trusts.

CONTRACTUAL OBLIGATIONS

There have been no material changes to AltaGas' contractual obligations from those included in the MD&A included in the Trust's 2006 Annual Report, except for the issue of $100 million senior unsecured MTNs on January 19, 2007. The notes carry a coupon rate of 5.07 percent and mature on January 19, 2012. The proceeds from the MTN issue were used to pay down bank indebtedness and for general corporate purposes.

RELATED PARTIES

In third quarter 2007 the Trust sold $5.3 million of natural gas and provided $0.2 million of operating services to Utility Group and paid management fees of $0.1 million and transportation costs of $0.1 million to Utility Group. The Trust also received management fees of $7,500 from Utility Group for administrative services. In addition, the Trust sold its one-third interest in the Ikhil Joint Venture to Utility Group for $9.0 million. The gain on the sale was negligible.

The Trust pays rent under a lease for office space and equipment to 2013761 Ontario Inc., which is owned by an employee. Payments of $21,171 were made in third quarter 2007 (third quarter 2006 - $20,773). The five-year lease expires at the end of 2007 and has been renewed by AltaGas for an additional year. (See note 13 of the interim Consolidated Financial Statements.)



SUMMARY OF CONSOLIDATED RESULTS FOR THE EIGHT MOST RECENT QUARTERS

($ millions) Q3-07 Q2-07 Q1-07 Q4-06 Q3-06 Q2-06 Q1-06 Q4-05
----------------------------------------------------------------------------
Net revenue(1) 88.2 80.1 79.3 84.6 82.5 72.8 79.1 78.7
Operating income(1) 37.5 31.2 29.0 32.0 33.7 26.0 35.0 29.0
Net income 31.4 21.1 24.6 27.3 28.8 29.9 28.6 26.4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ per unit) Q3-07 Q2-07 Q1-07 Q4-06 Q3-06 Q2-06 Q1-06 Q4-05
----------------------------------------------------------------------------
Net income
Basic 0.54 0.37 0.43 0.49 0.52 0.54 0.52 0.48
Diluted 0.54 0.37 0.43 0.49 0.52 0.54 0.52 0.48
Distributions
declared(2)(3) 0.52 0.51 0.51 0.51 0.505 0.495 0.485 0.48
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Non-GAAP financial measure. See Non-GAAP Financial Measures in this
MD&A.
(2) Excludes share distribution as a result of the spin-out of the NGD
segment. The Trust issued one common share of Utility Group (valued at
$7.50 per share) for every 13.9592 trust units held on November 14,
2005, providing additional value of $0.54 per unit.
(3) Excludes the special distribution issuance of one common share of
Utility Group for every 100 trust units held on August 27, 2007,
valued at $0.07 per unit.

 


Identifiable trends in AltaGas' business in the past eight quarters reflect: the organization's internal growth, acquisitions, a favourable business environment including generally increasing power prices in Alberta, seasonality in the natural gas distribution (NGD) business up to the time of its spin-out in November 2005, and asset dispositions.

Significant items that impacted individual quarterly earnings were as follows:


Results in fourth quarter 2005 were impacted by the spin-out of the NGD segment, the net after-tax impact of which was $0.1 million. In addition, operating income was approximately $2.0 million lower due to owning 100 percent of the NGD segment for only six weeks in the quarter and a $1.6 million tax recovery due to an adjustment to future tax balances. Results were also impacted by higher prices received for power sold and lower interest expense;


Results in the FG&P segment are typically lower in the first quarter compared to the fourth quarter;


In second quarter 2006 a $6.6 million non-cash future income tax benefit was recorded as a result of a reduction in the federal and Alberta corporate income tax rates;


In fourth quarter 2006 the Trust reported a $0.6 million goodwill impairment and deferred $0.8 million in revenue in the transmission business; and


In second quarter 2007 the Trust recorded a $6.5 million future tax expense as a result of new tax legislation included in Bill C-52 which was substantially enacted by the Government of Canada. This non-cash charge to earnings relates to the temporary differences between the accounting and tax basis of AltaGas' assets and liabilities.

TRUST UNIT INFORMATION

Under the terms of the restructuring of AltaGas into an income trust effective May 1, 2004, ASI security holders exchanged their shares in ASI for Trust units and eligible security holders also received exchangeable units that are exchangeable into Trust units on a one-for-one basis. The exchangeable units are not listed for trading on an exchange.

Units Outstanding

At September 30, 2007 the Trust had 55,786,541 trust units and 2,040,856 exchangeable units outstanding and a market capitalization of $1.5 billion based on a closing trading price on September 28, 2007 of $26.62 per trust unit. At September 30, 2007 there were 1,032,275 options outstanding and 289,300 options exercisable under the terms of the unit option plan.

DISTRIBUTIONS

AltaGas distributions are determined giving consideration to the ongoing sustainable cash flow as impacted by the consolidated net income, maintenance and growth capital and debt repayment requirements of the Trust. AltaGas has been able to sustain its distributions through cash from operations. In the nine months ended September 30, 2007 the Trust distributed cash of $87.7 million and had cash from operations of $123.5 million (same period 2006 - $81.4 million and $110.3 million respectively). In third quarter 2007 the Trust declared distributions of $30.0 million compared to $28.1 million in third quarter 2006.

The Trust suspended the Premium portion of the DRIP effective with the August 2007 distribution. The regular component of the DRIP will remain in effect and will continue to support AltaGas' financing strategy. In the future, as conditions warrant, the Trust may consider reinstating the PDRIP based on AltaGas' capital requirements and desire to maintain an efficient capital structure. While the PDRIP component of the Plan is suspended, PDRIP participants will continue to receive regular cash distributions. For further information on the DRIP please visit AltaGas' website at www.altagas.ca.

AltaGas announced that the Board of Directors of AltaGas General Partner Inc., delegate of the Trustee, increased its monthly cash distribution to $0.175 per unit ($2.10 per unit annualized) from $0.17 per unit ($2.04 per unit annualized) payable on September 17, 2007 to unitholders of record on August 27, 2007. This was AltaGas' fourth distribution increase since converting to a trust in May 2004. AltaGas' total distributions declared in third quarter 2007 were $0.52 per unit.

In addition, a special distribution of one Utility Group common share for every 100 trust units and exchangeable units of AltaGas held on August 27, 2007 was made on September 17, 2007. The Trust distributed 577,416 shares valued at $4.2 million.



The following table summarizes AltaGas' distribution declaration history
since 2005:

Distributions

($ per unit) 2007 2006 2005
----------------------------------------------------------------------------
First quarter 0.51 0.485 0.45
Second quarter 0.51 0.495 0.45
Third quarter 0.52 0.505 0.47
Fourth quarter - 0.510 0.48
Distribution of shares(1) 0.07 - 0.54
----------------------------------------------------------------------------
1.61 1.995 2.39
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) On September 17, 2007, one share of Utility Group was issued for every
100 trust units and exchangeable units held on August 27, 2007. On
November 17, 2005, one share of Utility Group was issued for every
13.9592 Trust units held on November 14, 2005.

 


CHANGES IN ACCOUNTING POLICIES

2007 Changes

Effective January 1, 2007 AltaGas adopted the revised Canadian Institute of Chartered Accountants (CICA) Handbook Section 1506. This section prescribes the criteria for changing accounting policies, together with the accounting treatment and disclosure of changes in accounting policies, changes in accounting estimates and corrections of errors. The adoption of this standard did not have a material impact on the consolidated financial statements.

Financial Instruments

Effective January 1, 2007 the Trust prospectively adopted the CICA Handbook Section 3855, Financial Instruments - Recognition and Measurement; Section 3865, Hedges; Section 1530, Comprehensive Income and Section 3861, Financial Instruments - Disclosure and Presentation. The impacts of adopting the new standards are reflected in the Trust's current quarter results, and prior year comparative financial statements have not been restated. While the new rules resulted in changes to how the Trust accounts for its financial instruments, there were no material impacts on the Trust's current quarter financial results. For a description of the new accounting rules and the impact on the Trust's financial statements of adopting such rules, see note 2 to the interim Consolidated Financial Statements for the three and nine months ended September 30, 2007.

Future Accounting Changes

Section 1535 Capital Disclosures

Effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2007, the new CICA Handbook Section 1535 Capital Disclosures requires the disclosure of qualitative and quantitative information about the Trust's objectives, policies and processes for managing capital. This new section is effective for the Trust beginning January 1, 2008.

Section 3862 Financial Instruments - Disclosures and Section 3863 - Financial Instruments - Presentation

Effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2007, the new CICA Handbook Sections 3862 and 3863 will replace Section 3861 to prescribe the requirements for presentation and disclosure of financial instruments. The objective of Section 3862 is to provide users with information to evaluate the significance of the financial instruments on the entity's financial position and performance, the nature and extent of risks arising from financial instruments, and how the entity manages those risks. The provisions of Section 3863 deal with the classification of financial instruments, related interest, dividends, losses and gains, and the circumstances in which financial assets and financial liabilities are offset. These new sections are effective for the Trust beginning January 1, 2008.

International Financial Reporting Standards (IFRS)

In 2006 the Accounting Standards Board (AcSB) published a new strategic plan that will significantly affect financial reporting requirements in Canada. The AcSB strategic plan outlines the convergence of Canadian GAAP with IFRS over an expected five-year transition period. While AltaGas has begun assessing the adoption of IFRS for 2011, the financial impact of the transition to IFRS cannot be reasonably estimated at this time.

SIGNIFICANT ACCOUNTING POLICIES

AltaGas' significant accounting policies remain unchanged from December 31, 2006 except as disclosed in the notes to the interim Consolidated Financial Statements for the three and nine months ended September 30, 2007. For further information regarding these policies refer to the notes to the audited Consolidated Financial Statements in AltaGas' 2006 Annual Report.

CRITICAL ACCOUNTING ESTIMATES

Since a determination of the value of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of the Trust's interim Consolidated Financial Statements requires the use of estimates and assumptions which have been made using careful judgment. AltaGas' significant accounting policies are described in the notes to the interim Consolidated Financial Statements for the three and nine months ended September 30, 2007 and in the notes to the 2006 audited Consolidated Financial Statements included in the Trust's 2006 Annual Report. Certain of these policies involve critical accounting estimates as a result of the requirement to make particularly subjective or complex judgments about matters that are inherently uncertain and because of the likelihood that materially different amounts could be reported under different conditions or using different assumptions.

AltaGas' critical accounting estimates are risk management assets and liabilities, amortization expense, asset retirement obligations, asset impairment assessment and future tax liability. For a full discussion of these accounting estimates, refer to the MD&A in AltaGas' 2006 Annual Report and the notes to the interim Consolidated Financial Statements for the three and nine months ended September 30, 2007.

OFF-BALANCE-SHEET ARRANGEMENTS

The Trust is not party to any contractual arrangement under which an unconsolidated entity may have any obligation under certain guarantee contracts, a retained or contingent interest in assets transferred to an unconsolidated entity or similar arrangement that serves as credit, liquidity or market risk support to that entity for such assets. The Trust has no obligation under derivative instruments, or a material variable interest in an unconsolidated entity that provides financing, liquidity, market risk or credit risk support or engages in leasing, hedging or research and development services with the Trust.

DISCLOSURE CONTROLS AND PROCEDURES

The Trust maintains disclosure controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under applicable securities legislation is accumulated and communicated to management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

INTERNAL CONTROLS OVER FINANCIAL REPORTING

Management of the Trust is responsible for establishing and maintaining internal controls over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be designed effectively can provide only reasonable assurance with respect to financial statement preparation and presentation. During third quarter 2007 there were no material changes to the Trust's internal controls over financial reporting.



Consolidated Balance Sheets
(unaudited)

September 30 December 31
($ thousands) 2007 2006
----------------------------------------------------------------------------

ASSETS
Current assets
Cash and cash equivalents $ 12,313 $ 13,226
Accounts receivable 162,561 224,533
Inventory 111 61
Customer deposits 25,824 16,304
Risk management (note 5) 69,848 -
Other 4,723 9,277
----------------------------------------------------------------------------
275,380 263,401
Capital assets 661,789 677,941
Energy service arrangements, contracts and
relationships 97,619 103,330
Goodwill 18,260 18,260
Risk management (note 5) 47,306 -
Long-term investments and other assets 62,122 46,643
----------------------------------------------------------------------------
$ 1,162,476 $ 1,109,575
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities $ 124,513 $ 200,882
Distributions payable to unitholders 10,120 9,588
Short-term debt 2,865 -
Current portion of long-term debt 1,213 1,147
Customer deposits 25,824 16,304
Deferred revenue 1,483 788
Risk management (note 5) 72,461 -
Other 7,659 10,982
----------------------------------------------------------------------------
246,138 239,691
Long-term debt 225,000 264,340
Asset retirement obligations 20,322 23,350
Future income taxes (notes 4 and 6) 60,332 51,252
Risk management (note 5) 45,841 -
Other long-term liabilities 2,692 1,526
----------------------------------------------------------------------------
600,325 580,159
Unitholders' equity (notes 7 and 8) 562,151 529,416
----------------------------------------------------------------------------
$ 1,162,476 $ 1,109,575
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the Consolidated Financial Statements.


Consolidated Statements of Income and Accumulated Earnings
(unaudited)

($ thousands except per Three months ended Nine months ended
unit amounts and September 30 September 30
number of units) 2007 2006 2007 2006
----------------------------------------------------------------------------
REVENUE
Operating $ 320,165 $ 317,313 $ 1,086,841 $ 992,451
Unrealized gains on risk
management 1,142 - 1,617 -
Other 762 545 3,454 2,767
----------------------------------------------------------------------------
322,069 317,858 1,091,912 995,218
----------------------------------------------------------------------------

EXPENSES
Cost of sales 233,896 235,414 844,351 760,855
Operating and
administrative 39,073 37,237 114,148 105,723
Amortization 11,650 11,439 35,696 33,978
----------------------------------------------------------------------------
284,619 284,090 994,195 900,556
----------------------------------------------------------------------------
Operating income 37,450 33,768 97,717 94,662
Interest expense
Short-term debt 121 62 269 292
Long-term debt 2,734 3,207 8,710 9,643
----------------------------------------------------------------------------
Income before income taxes 34,595 30,499 88,738 84,727
Income tax expense
(recovery) (note 4) 3,237 1,728 11,747 (2,508)
----------------------------------------------------------------------------
Net income 31,358 28,771 76,991 87,235
Accumulated earnings,
beginning of period 447,251 345,571 401,618 287,107
----------------------------------------------------------------------------
Accumulated earnings, end
of period $ 478,609 $ 374,342 $ 478,609 $ 374,342
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net income per unit (notes
4 and 8)
Basic $ 0.54 $ 0.52 $ 1.35 $ 1.58
Diluted $ 0.54 $ 0.52 $ 1.35 $ 1.58

Weighted average number of
units outstanding
(thousands) (note 8)
Basic 57,692 55,661 57,188 55,229
Diluted 57,744 55,775 57,227 55,329


See accompanying notes to the Consolidated Financial Statements.


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

Three Nine
months ended months ended
September 30 September 30
($ thousands) 2007 2007
----------------------------------------------------------------------------

Net income (note 4) $ 31,358 $ 76,991

Other comprehensive income, net of tax
(note 5)
Unrealized net gains on available for
sale financial assets 889 11,288
Unrealized net gains on derivative
designated as cash flow hedges 5,688 1,602
Reclassification to net income of net
loss on derivatives designated as cash
flow hedges pertaining to prior periods 5,858 2,469
----------------------------------------------------------------------------
12,435 15,359
----------------------------------------------------------------------------
Comprehensive income $ 43,793 $ 92,350
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Accumulated other comprehensive income,
beginning of period $ 290 -
Adjustment resulting from adoption of new
financial instrument accounting standards
(note 2) - (2,634)
Other comprehensive income, net of tax 12,435 15,359
----------------------------------------------------------------------------
Accumulated other comprehensive income,
end of period $ 12,725 $ 12,725
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the Consolidated Financial Statements.


Consolidated Statements of Cash Flows
(unaudited)
Three months ended Nine months ended
September 30 September 30
($ thousands ) 2007 2006 2007 2006
----------------------------------------------------------------------------
Cash from operations
Net income $ 31,358 $ 28,771 $ 76,991 $ 87,235
Items not involving cash:
Amortization 11,650 11,439 35,696 33,978
Accretion of asset
retirement obligations 416 376 1,266 1,063
Unit-based compensation 128 162 459 196
Future income tax expense
(recovery) 3,236 1,734 11,746 (2,517)
Loss (gain) on sale of
assets (note 9) 1,381 - (182) -
Equity income (loss) 29 (316) (1,664) (2,361)
Distribution from equity
investments 232 745 1,490 2,195
Unrealized gains on risk
management (1,142) - (1,617) -
Other 331 271 878 109
----------------------------------------------------------------------------
Funds from operations 47,619 43,182 125,063 119,898
Asset retirement
obligations settled (412) (17) (552) (59)
Net change in non-cash
working capital (note 11) (16,439) (2,409) (1,043) (9,584)
----------------------------------------------------------------------------
30,768 40,756 123,468 110,255
----------------------------------------------------------------------------
Investing activities
Increase in customer
deposits (3,337) (857) (9,520) (3,844)
Acquisition of capital
assets (16,197) (21,673) (37,085) (62,673)
Disposition of capital
assets 9,215 (7) 9,722 321
Disposition of energy
services arrangements,
contracts and
relationships - 420 - 36
Acquisition of long-term
investments and other
assets (1,313) (2,523) (2,112) (4,399)
Disposition of long-term
investments and other
assets 2,700 - 3,075 -
----------------------------------------------------------------------------
(8,932) (24,640) (35,920) (70,559)
----------------------------------------------------------------------------
Financing activities
Increase (decrease) in
short-term debt 1,020 - 2,865 (2,710)
Increase (decrease) in
long-term debt (1,703) (40) (38,816) 10,828
Distributions to
unitholders (29,845) (27,790) (87,655) (81,361)
Net proceeds from issuance
of units (note 8) 8,696 12,837 35,145 33,927
----------------------------------------------------------------------------
(21,832) (14,993) (88,461) (39,316)
----------------------------------------------------------------------------
Change in cash and cash
equivalents 4 1,123 (913) 380
Cash and cash equivalents,
beginning of period 12,309 10,942 13,226 11,685
----------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 12,313 $ 12,065 $ 12,313 $ 12,065
----------------------------------------------------------------------------

See accompanying notes to the Consolidated Financial Statements.

 


Selected Notes to the Consolidated Financial Statements

(unaudited)

(Tabular amounts in thousands of Canadian dollars unless otherwise indicated.)

1. BASIS OF PRESENTATION

The interim Consolidated Financial Statements of AltaGas Income Trust (AltaGas or the Trust) include the accounts of the Trust and all of its wholly owned subsidiaries, and its proportionate interests in various partnerships and joint ventures.

Until second quarter 2007 AltaGas accounted for its investment in Taylor NGL Limited Partnership (Taylor) using the equity method. Effective second quarter 2007 AltaGas ceased to exercise significant influence over Taylor and began accounting for its investment in Taylor using the cost method. As a result, the investment in Taylor is designated as available for sale and is measured at fair value with the changes in fair value recorded in Other Comprehensive Income (OCI).

The interim Consolidated Financial Statements have been prepared by management in accordance with Canadian generally accepted accounting principles (GAAP). The accounting policies applied are consistent with those outlined in the Trust's annual Consolidated Financial Statements for the year ended December 31, 2006, except as described below in notes 2 and 3. These interim Consolidated Financial Statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2006 audited Consolidated Financial Statements included in the Trust's Annual Report.

2. CHANGES IN ACCOUNTING POLICIES

Changes for 2007

Effective January 1, 2007 the Trust adopted the new CICA Handbook accounting requirements for Section 3855 "Financial Instruments - Recognition and Measurement", Section 3865 "Hedges", Section 3861 "Financial Instruments - Disclosure and Presentation", Section 1530 "Comprehensive Income", Section 3251 "Equity" and Section 1506 "Accounting Changes". In accordance with the transitional provisions for these new standards, these policies were adopted prospectively without restatement of prior periods.

Accounting Changes

This section prescribes the criteria for changing accounting policies, together with the accounting treatment and disclosure of changes in accounting policies, changes in accounting estimates and corrections of errors. The adoption of this standard did not have a material impact on the interim Consolidated Financial Statements of the Trust.

Financial Instruments

All financial instruments, including derivatives, are included on the balance sheet initially at fair value. The financial assets are classified as held for trading, held to maturity, loans and receivables, or available for sale. Financial liabilities are classified as held for trading or other financial liabilities. Subsequent measurement is determined by classification.

Held for trading financial assets and liabilities are entered into with the intention of generating a profit and consist of swaps, options and forwards. These financial instruments are initially accounted for at their fair value and changes to fair value are recorded in income. Held to maturity financial assets are accounted for at their amortized cost using the effective interest method. The Trust did not have any held to maturity financial instruments at September 30, 2007. Loans and receivables are accounted for at their amortized cost using the effective interest method. The available for sale classification includes non-derivative financial assets that are designated as available for sale or are not included in the other three classifications. Available for sale instruments are initially accounted for at their fair value and changes to fair value are recorded through OCI. Income earned from these investments is included in Revenue.

Other financial liabilities not classified as held for trading are accounted for at their amortized cost, using the effective interest method.

Derivatives embedded in other financial instruments or contracts (the host instrument) are recorded as separate derivatives and are measured at fair value if the economic characteristics of the embedded derivative are not closely related to the host instrument, the terms of the embedded derivative are the same as those of a stand alone derivative and the total contract is not held for trading or accounted for at fair value. Changes in fair value are included in income. All derivatives, other than those that meet the expected purchase, sale or usage requirements exception, are carried on the balance sheet at fair value. The Trust used January 1, 2003 as the transition date for identifying embedded derivatives. The Trust did not identify any embedded derivatives requiring bifurcation.

Transaction costs are incremental costs that are directly attributable to the acquisition, issue or disposal of a financial instrument. Effective January 1, 2007 the Trust reclassified $1.1 million of unamortized deferred financing costs from Other current assets and Long-term investments and other assets to Long-term debt as a result of adopting the new standards. The reclassification of transaction costs has no impact on earnings. Effective January 1, 2007 the Trust began amortizing these costs using the effective interest rate method. Previously, these costs were amortized on a straight-line basis over the life of the debt.

Hedges

The new standard specifies the circumstances under which hedge accounting is permissible, how hedge accounting may be performed and where the impacts should be recorded. The standard introduces three specific types of hedging relationships: fair value hedges, cash flow hedges and hedges of a net investment in self-sustaining foreign operations.

As part of its asset and liability management, the Trust uses derivatives for hedging positions to reduce its exposure to commodity price and interest rate risk. The Trust designates certain derivatives as hedges and prepares documentation at the inception of the hedging contract. The Trust performs an assessment at inception and during the term of the contract to determine if the derivative used as a hedge is effective in offsetting the risks in the values or cash flows of the hedged financial instrument. All derivatives are initially recorded at fair value and adjusted to fair value at each reporting date.

The Trust uses cash flow hedges to reduce its exposure to fluctuations in interest rates and changes in commodity prices. The effective portion of changes in the value of cash flow hedges is recognized in Other comprehensive income. Ineffective portions and amounts excluded from effectiveness testing of hedges are included in income in the same financial category as the underlying transaction. Gains or losses from cash flow hedges that have been included in accumulated other comprehensive income are included in net income when the underlying transaction has occurred or becomes probable of not occurring. The maximum length of time the Trust is hedging its exposure to variability in future cash flows is 10.25 years.

Comprehensive Income and Equity

The Trust's financial statements include a Consolidated Statement of Comprehensive Income and Accumulated Other Comprehensive Income which consists of earnings and the effective portion of changes in unrealized gains and losses related to available for sale assets and cash flow hedges. In addition, as required by Section 3251, the Trust now presents separately in its Unitholders' equity note the changes for each of its components of Unitholders' equity. A new component, Accumulated other comprehensive income, and a one-time transition adjustment have been added to the Trust's Unitholders' equity as a result of the implementation of this new standard. (See note 5.)

Net Effect of Accounting Policy Changes

The net effect to the Trust's financial statements at January 1, 2007 resulting from the above mentioned changes in accounting policies is as follows:



Balance Sheet Account Affected Increase
(Decrease)
----------------------------------------------------------------------------
Current assets - risk management $ 59,866
Other current assets (451)
Non-current assets 47,942
Long-term investments and other assets (793)
Current liabilities - risk management 69,618
Long-term debt (1,082)
Long-term liabilities - risk management 48,359
Future income tax liability (7,450)
Unitholders' equity - Transition amount on adoption of new
accounting standards, net of tax (247)
Unitholders' equity - Accumulated other comprehensive income,
net of tax (2,634)
----------------------------------------------------------------------------

 


The unrealized gains and losses included in the Transition amount and in Accumulated other comprehensive income were recorded net of income tax recoveries of $4.6 million and $2.9 million, respectively.

Future Accounting Changes

Section 1535 Capital Disclosures

Effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2007, the new CICA Handbook Section 1535 "Capital Disclosures" requires the disclosure of qualitative and quantitative information about the Trust's objectives, policies and processes for managing capital. This new section is effective for the Trust beginning January 1, 2008.

Section 3862 Financial Instruments - Disclosures and Section 3863 - Financial Instruments - Presentation

Effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2007, the new CICA Handbook Sections 3862 and 3863 will replace Section 3861 to prescribe the requirements for presentation and disclosure of financial instruments. The objective of Section 3862 is to provide users with information to evaluate the significance of the financial instruments on the entity's financial position and performance, the nature and extent of risks arising from financial instruments, and how the entity manages those risks. The provisions of Section 3863 deal with the classification of financial instruments, related interest, dividends, losses and gains, and the circumstances in which financial assets and financial liabilities are offset. These new sections are effective for the Trust beginning January 1, 2008.

International Financial Reporting Standards (IFRS)

In 2006 the Accounting Standards Board (AcSB) published a new strategic plan that will significantly affect financial reporting requirements in Canada. The AcSB strategic plan outlines the convergence of Canadian GAAP with IFRS over an expected five-year transitional period. While AltaGas has begun assessing the adoption of IFRS for 2011, the financial impact of the transition to IFRS cannot be reasonably estimated at this time.

3. UPDATE TO SUMMARY OF ACCOUNTING POLICIES

As a result of the Trust's adoption of the financial instrument accounting standards, the Trust has updated the following significant accounting policies.

Revenue recognition

In the Field Gathering and Processing segment, revenue is recorded as the services are rendered. In the Power Generation and Energy Services segments, revenue is recognized at the time the product or service is delivered. Within the Extraction and Transmission segment, extraction revenue is recognized at the time the product or service is delivered and transmission revenue is recorded as the services are rendered. Realized gains and losses from risk management activities related to commodity prices are recognized in the related segment revenues when the related sale occurs or when the underlying financial asset or financial liability is removed from the balance sheet. Unrealized gains and losses in respect of fair value changes to the Trust's risk management activities are recorded as revenue based on the related mark-to-market calculations at the end of the reporting period in the Corporate segment.

Transaction costs related to financial instruments

Transaction costs related to the acquisition of held for trading financial assets and liabilities and the Trust's revolving operating credit facility are expensed as incurred. For financial instruments classified as other than held for trading, transaction costs attributable to the acquisition or issue of the financial asset or liability are added to the initial carrying amount of the financial instrument and recognized in earnings using the effective interest method.

Recognition date

AltaGas uses settlement date for transactions. Any difference in value between the trade and settlement date for third-party transactions will be recognized on the balance sheet and in Net income or in Other comprehensive income as appropriate.

Designation of available for sale financial assets

Available for sale financial assets are investments in equity instruments that are not classified as held for trading, held to maturity, or loans and receivables, and that management intends to hold indefinitely. Available for sale assets are measured at fair value. The changes in fair value are recorded in Other comprehensive income until the asset is removed from the balance sheet. Available for sale assets are included in the Long-term investments and other assets classification.

Effective interest method

The Trust uses the effective interest method to calculate the amortized cost of a financial asset or liability and to allocate the interest income or expense over the relevant period. The effective interest rate is the rate that exactly discounts the estimated cash flows associated with the instrument over the expected life of the financial instrument, or where appropriate a shorter period, to the net carrying amount of the financial asset or liability.

4. SECOND QUARTER 2007 SIFT TAX ADJUSTMENT

During the third quarter AltaGas recalculated the estimate for the Specified Investment Flow-Through (SIFT) tax reported in second quarter 2007. The recalculation resulted in a decrease in SIFT tax liability as at June 30, 2007 from $14.5 million to $6.5 million. The change resulted in an increase in net income for second quarter 2007 to $21.1 million ($0.37 per unit) from $13.1 million ($0.23 per unit) previously reported. Net income for the six months ended June 30, 2007 was adjusted to $45.6 million ($0.80 per unit) from $37.6 million ($0.66 per unit) previously reported. The adjustment also reduced the previously reported future income tax liability on the balance sheet from $59.2 million to $51.2 million. The results reported for the nine months ended September 30, 2007 reflect the adjustment made to results for second quarter 2007.

5. FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT

In the course of normal operations the Trust purchases and sells natural gas, natural gas liquids and power commodities and issues short and long-term debt. The Trust uses derivative instruments to reduce exposure to fluctuations in commodity prices, interest rates and foreign currency exchange rates that arise from these activities. The Trust does not make use of derivative instruments for speculative purposes.

At September 30, 2007 all derivatives, other than those that meet the expected purchase, sale or usage requirements exception, were carried on the balance sheet at fair value. The fair value of power and natural gas derivatives was calculated using estimated forward prices for the relevant period. The calculation of fair value of the interest rate derivatives used quoted market rates.



At September 30, 2007 the fair value of the Trust's assets and liabilities
was as follows:

Summary of Fair Values

($ thousands) Current Long-term Total
----------------------------------------------------------------------------
Financial assets
Held for trading $ 62,975 $ 41,676 $ 104,651
Available for sale - 37,386 37,386
Loans and receivables 142,395 - 142,395
----------------------------------------------------------------------------
205,370 79,062 284,432
Cash flow hedges 6,873 5,630 12,503
----------------------------------------------------------------------------
$ 212,243 $ 84,692 $ 296,935
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Financial liabilities
Held for trading $ 63,873 $ 43,875 $ 107,748
Other financial liabilities 107,725 216,898 324,623
----------------------------------------------------------------------------
171,598 260,773 432,371
Cash flow hedges 8,588 1,965 10,553
----------------------------------------------------------------------------
$ 180,186 $ 262,738 $ 442,924
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Unrealized income

The impact on net income from the adoption of the new financial instruments standards resulted in a $1.1 million unrealized gain in third quarter 2007 and an unrealized gain of $1.6 million for the nine months ended September 30, 2007.

Other Comprehensive Income

As a part of its hedging program, the Trust uses certain derivative financial instruments to manage risks. An after-tax unrealized loss of $5.9 million was reclassified to net income in third quarter 2007 and a $2.5 million after-tax unrealized loss was reclassified to net income in the first nine months of 2007. Of the $1.4 million gain deferred in Accumulated OCI at September 30, 2007, a $1.1 million loss is expected to be reclassified to net income in the next 12 months.

The available for sale assets included in the balance sheet caption, long-term investments and other assets are recognized at fair value, net of tax, in OCI. In third quarter the fair value, net of tax, increased by $0.9 million and $11.3 million in the first nine months of 2007. The year-to-date increase was mainly due to the designation of the Taylor investment as available for sale due to the change in accounting for the investment from the equity method to the cost method.

Effective January 1, 2007 the Trust began offsetting long-term debt transaction costs against the associated debt and began amortizing these costs using the effective interest rate method. Previously these costs were amortized on a straight-line basis over the life of the debt instrument to which they pertained. There was no material effect on the Trust's financial statements as a result of this change in policy. In the third quarter and the first nine months of 2007 the charge to Net income for the amortization of transaction costs using the effective interest rate method was immaterial. The effective interest rate for the medium-term notes issued in 2005 and 2007 is 4.57 percent and 5.11 percent, respectively.

Commodity Price Risk Management

Natural Gas

The Trust purchases and sells natural gas to its customers. The fixed price and market price contracts for both the purchase and sale of natural gas extend to 2012.



At September 30, 2007 the Trust had the following contracts outstanding:

Notional volume (GJ)
----------------------
Derivative Fixed price Period
Instruments (per GJ)(1) (months) Sales Purchases Fair Value
----------------------------------------------------------------------------
Commodity
forward $2.16 to $10.37 1 - 50 103,879,112 - $ (6,638)
Commodity
forward $2.16 to $10.37 1 - 50 - 103,879,112 $ 3,069
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Certain of the contracts are indexed and as such a price range is not
provided.

 


For third quarter 2007 an unrealized gain of $0.6 million was recognized from the Trust's natural gas risk management activities and an unrealized gain of $1.5 million was recognized in the first nine months of 2007.

Natural Gas Liquids

In the third quarter, the Trust entered into a series of swaps to lock in a portion of the margin exposed to Natural Gas Liquids (NGL) frac spread. These swap arrangements will terminate in December 2007.



At September 30, 2007 the Trust had the following contracts outstanding:

Notional volume
----------------------
Period
Product Fixed price (months) Sales Purchases Fair Value
----------------------------------------------------------------------------
$1.20 US/ 1,601,062
Propane gallon 1 - 3 (gallon) - $ (198)

Normal $1.38 US/ 389,492
butane gallon 1 - 3 (gallon) - (72)

Condensate $74.25 US/Bbl 1 - 3 4,122 Bbls - (30)

Natural gas $5.70/GJ 1 - 3 - 222,089 GJ $ (19)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


For third quarter 2007 and the first nine months of 2007, the Trust recognized an unrealized loss of $0.3 million from the Trust's NGL risk management activities.

Power

Under the power purchase arrangements AltaGas has an obligation to buy power at agreed terms and prices to December 31, 2020. The Trust sells the power to the Alberta Electric System Operator at market prices and uses swaps and collars to fix the prices over time on a portion of the volumes. AltaGas' strategy is to lock in margins to provide predictable earnings. Certain contracts met the expected purchase, sale or usage requirements exception and have not been included in risk management assets or liabilities. At September 30, 2007 the Trust had no intention to terminate any contracts prior to maturity.



At September 30, 2007 the Trust had the following contracts outstanding:

Notional volume (MWh)
----------------------

Derivative Fixed price Period
Instruments (per MWh) (months) Sales Purchases Fair Value
----------------------------------------------------------------------------
Commodity $64.98 to
forward $82.13 1 - 12 4,392 - $ (14)
Commodity $79.00 to
forward $79.00 1 - 12 - 4,392 $ 21
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


The Trust's power risk management activities from financial contracts not included in the hedging program had an unrealized gain of $28,018 for the third quarter 2007 and an unrealized loss of $36,765 for the first nine months of 2007.



At September 30, 2007 the Trust had the following commodity swaps and
collars outstanding:

Notional volume (MWh)
----------------------

Derivative Fixed price Period
Instruments (per MWh) (months) Sales Purchases Fair Value
----------------------------------------------------------------------------
Swaps and $65.00 to
collars $88.00 1 to 27 2,129,520 - $ (2,700)
Swaps and $56.50 to
collars $65.00 1 to 123 - 325,515 $ 4,650
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Foreign Exchange Risk Management

To manage the risk of fluctuating cash flows due to variations in foreign exchange rates, the Trust enters into foreign exchange forward contracts. For third quarter 2007 the Trust's foreign exchange risk management activities had an unrealized gain of $0.5 million and an unrealized gain for the first nine months of 2007 of $0.1 million.

Interest Rate Risk Management

To hedge against the effect of future interest rate movements, the Trust enters into interest rate swap agreements to fix the interest rate on a portion of its bankers' acceptances issued under credit facilities. In January 2007 the Trust unwound certain of these interest rate swaps as a result of the issue of $100 million of medium-term notes and recorded a gain of $0.4 million. In the third quarter the Trust terminated the hedge relationship on certain swap agreements resulting in an immaterial unrealized gain. The remaining interest rate swaps have an average remaining term of 10 to 23 months and a weighted average interest rate of 3.56 percent. The Trust's interest rate risk management activities resulted in an unrealized gain of $0.3 million for third quarter 2007 and an unrealized gain of $0.3 million in the first nine months of 2007. These swaps had a fair market value position of $0.3 million at September 30, 2007.

Credit Risk on Financial Instruments

Credit risk results from the possibility that a counterparty to a derivative in which the Trust has an unrealized gain fails to perform according to the terms of the contract.

Credit exposure is minimized by entering into transactions with creditworthy counterparties in accordance with established credit policies and practices. At September 30, 2007 AltaGas did not have a significant concentration of credit risk with any single counterparty to financial instruments.

6. FUTURE INCOME TAXES

On June 12, 2007 the Bill C-52 Budget Implementation Act received Third Reading and was substantively enacted by the Government of Canada, creating a new 31.5 percent tax to be applied to the distributions from certain income trusts and partnerships, including AltaGas, effective January 1, 2011.

Based on the amount of the Trust's temporary differences that are anticipated to reverse after January 1, 2011, the Trust has recorded a future income tax expense of $6.0 million and increased its future income tax liability in the nine months ended September 30, 2007 (a decrease of $0.5 million in third quarter 2007 based on activity during the quarter). This non-cash expense relates to temporary differences between the accounting and tax basis of AltaGas' assets and liabilities and has no immediate impact on cash flows. A tax rate of nil was applied to any temporary differences reversing before 2011.

The anticipated amount and timing of reversals of temporary differences will be dependent on the Trust's actual results, distributions and actual acquisition and disposition of assets and liabilities. As a result, a change in estimates or assumptions could materially affect the estimate of the future tax liability.



7. UNITHOLDERS' EQUITY

September 30 December 31
2007 2006
----------------------------------------------------------------------------
Unitholders' capital (note 8) $ 498,895 $ 463,750
Contributed surplus 3,781 3,322
Accumulated earnings 478,609 401,618
Accumulated dividends (41,114) (41,114)
Accumulated unitholders' distributions
declared(1) (360,650) (272,464)
Distributions of common shares of AltaGas Utility
Group Inc. (29,848) (25,696)
Transition adjustment resulting from adopting new
financial instruments accounting standards (247) -
Accumulated other comprehensive income (note 2) 12,725 -
----------------------------------------------------------------------------
$ 562,151 $ 529,416
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Accumulated distributions paid by the Trust as at September 30, 2007
were $350.6 million (as at December 31, 2006 - $262.9 million).

 


On September 17, 2007 the holders of trust units of the Trust and holders of exchangeable partnership units of AltaGas Holding Limited Partnership No. 1 (AltaGas LP #1) received one common share of Utility Group for every 100 Trust Units or Partnership Units held on August 27, 2007. As part of the distribution plan, any Trust unitholder allocated fewer than 50 common shares of Utility Group received cash. The number of common shares of Utility Group distributed to unitholders was 577,416, which reduced unitholders equity by $4.2 million. This distribution resulted in a 27 percent reduction of the Trust's interest in Utility Group to 19.6 percent.



8. UNITHOLDERS' CAPITAL

Trust Units Issued and Outstanding Number
of units Amount
----------------------------------------------------------------------------
December 31, 2006 54,313,552 $ 451,795
Units issued for cash on exercise of options 2,900 65
Units issued under DRIP(1) 1,422,131 35,080
Units issued for exchangeable units 47,958 274
----------------------------------------------------------------------------
September 30, 2007 55,786,541 $ 487,214
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Exchangeable Units Issued and Outstanding Number
of units Amount
----------------------------------------------------------------------------
December 31, 2006 issued by AltaGas Holding Limited
Partnership No. 1 2,088,814 $ 11,955
AltaGas Holding Limited Partnership No. 1 units
redeemed for Trust units (47,958) (274)
----------------------------------------------------------------------------
September 30, 2007 2,040,856 $ 11,681
----------------------------------------------------------------------------
Total Trust Units and Exchangeable Units at
September 30, 2007 57,827,397 $ 498,895
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Premium DistributionTM, Distribution Reinvestment and Optional Unit
Purchase Plan.

Units Outstanding(1) Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Number of units - Basic(2) 57,692,359 55,660,939 57,187,589 55,228,922
Dilutive stock options 52,025 114,228 39,537 100,475
----------------------------------------------------------------------------
Number of units - Diluted(2) 57,744,384 55,775,167 57,227,126 55,329,397
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes exchangeable units.
(2) Weighted average.

 


The Trust has a unit option plan under which employees and directors are eligible to receive grants. At September 30, 2007, 10 percent of units outstanding were reserved for issuance under the plan. To September 30, 2007 options granted under the plan generally had a term of 10 years to expiry and vested no longer than over a four-year period.

At September 30, 2007 outstanding options were exercisable at various dates to the year 2017 (December 31, 2006 - 2016). Options outstanding under the plan have a weighted average exercise price of $26.77 (December 31, 2006 - $27.23) and a weighted average remaining term of 8.67 years (December 31, 2006 - 9.23 years). At September 30, 2007 the unexpensed fair value of unit option compensation cost associated with future periods was $0.6 million (December 31, 2006 - $0.9 million).



The following table summarizes the information about the Trust's unit
options:

Number
of options Exercise price(1)
----------------------------------------------------------------------------
Unit options outstanding, December 31, 2006 923,550 $ 27.23
Granted 252,500 25.67
Exercised (2,900) 22.31
Cancelled (140,875) 27.84
----------------------------------------------------------------------------
Unit options outstanding, September 30, 2007 1,032,275 $ 26.77
----------------------------------------------------------------------------
Unit options exercisable, September 30, 2007 289,300 $ 25.08
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Weighted average.


A summary of the unit option plan as at September 30, 2007:

Options Outstanding Options Exercisable
------------------------------------ -----------------------
Range of Number Remaining Number
Exercise Price outstanding Exercise contractual exercisable Exercise
on Options (1) price(2) life(3) (1) price(2)
----------------------------------------------------------------------------
$5.00-$7.00 9,500 $ 6.15 2.68 9,500 $ 6.15
$7.01-$15.50 28,500 10.26 5.41 28,500 10.26
$15.51-$25.08 120,400 24.21 7.73 53,050 24.14
$25.09-$29.15 873,875 27.87 8.97 198,250 28.37
----------------------------------------------------------------------------
1,032,275 $ 26.77 8.67 289,300 $ 25.08
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) As of September 30, 2007.
(2) Weighted average.
(3) Weighted average number of years.

 


In 2004 AltaGas implemented a unit-based compensation plan which awards phantom units to certain employees. The phantom units are valued on distributions declared and the trading price of the Trust's units. The units vest on a graded vesting schedule. The compensation expense recorded in third quarter 2007 in respect of this plan was $1.1 million (third quarter 2006 - $1.7 million) and $3.8 million in the nine months ended September 30, 2007 (nine months ended September 30, 2006 - $5.2 million). At September 30, 2007 the unexpensed fair value of unit-based compensation costs related to the phantom units was $11.0 million (December 31, 2006 - $9.9 million).

9. DISPOSITION ON SALE OF CAPITAL ASSETS

During third quarter 2007 AltaGas sold its 33.3335 percent interest in the Ikhil Joint Venture for cash effective July 31, 2007 to AltaGas Utility Group Inc. for $9.0 million. The gain on the sale was negligible. In second quarter 2007 AltaGas recorded a one-time gain of $1.5 million from the sale of oil and natural gas production assets for non-monetary consideration totaling $11.9 million including a promissory note of $11.6 million. The disposition also resulted in the reduction in the asset retirement obligation of $3.1 million and a future income tax recovery of $0.6 million.

10. ACQUISITION OF ASSETS

On July 31, 2007 the Trust acquired all the outstanding partnership units in Bear Mountain Wind Limited Partnership and 100 percent of the shares in Bear Mountain Wind Power Corporation for cash consideration of $1.0 million.



11. NET CHANGE IN NON-CASH WORKING CAPITAL

The following non-cash working capital items affect cash flows from
operations:

Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Accounts receivable $ (4,862) $ (8,987) $ 61,972 $ 71,335
Inventory - - (50) 34
Other current assets (1,742) (5,538) 4,554 (4,961)
Accounts payable and accrued
liabilities (13,712) 12,253 (76,369) (84,182)
Customer deposits 3,337 856 9,520 3,844
Deferred revenue 272 - 695 -
Other current liabilities 1,933 809 (3,323) (4,035)
----------------------------------------------------------------------------
(14,774) (607) (3,001) (17,965)
Less: change in capital costs
included in accounts payable (1,665) (1,802) 1,958 8,381
----------------------------------------------------------------------------
$ (16,439) $ (2,409) $ (1,043) $ (9,584)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The following cash payments have been included in the determination of
earnings:

Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Interest paid $ 2,846 $ 3,310 $ 9,099 $ 10,190
Income taxes paid $ 85 $ 16 $ 181 $ 51
----------------------------------------------------------------------------
----------------------------------------------------------------------------

12. PENSION PLANS AND RETIREMENT BENEFITS

The net pension expense by plan for the period was as follows:

Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Defined contribution plan $ 386 $ 335 $ 1,148 $ 983
Defined benefit plan (17) 5 (11) 13
Supplemental executive
retirement plan 282 215 800 608
----------------------------------------------------------------------------
$ 651 $ 555 $ 1,937 $ 1,604
----------------------------------------------------------------------------
----------------------------------------------------------------------------

13. RELATED PARTY TRANSACTIONS

In the normal course of business, the Trust and its affiliates transact with
related parties. These transactions are recorded at their exchange amounts
and are as follows:

Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Fees for administration,
management and other
services paid by:
AltaGas Utility Group Inc.
(Utility Group) to the Trust $ 8 $ 206 $ 23 $ 464
The Trust to Utility Group $ 129 $ 130 $ 394 $ 365
Natural gas sales by the
Trust to Utility Group
subsidiaries $ 5,309 $ 4,621 $ 57,653 $ 52,003
Fees for operating services
paid by a Utility Group
subsidiary $ 163 - $ 306 -
Transportation services
provided by a Utility Group
subsidiary $ 119 $ 137 $ 362 $ 421
Office space and furniture
rental payments made by the
Trust to a corporation owned
by an employee $ 21 $ 20 $ 63 $ 60
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


The resulting amounts due from and to related parties are non-interest bearing and are related to transactions in the normal course of business.

Included in accounts receivable at September 30, 2007 was $2.3 million (September 30, 2006 - $2.0 million) due to the Trust from related parties. Included in accounts payable at September 30, 2007 was $0.1 million (September 30, 2006 - $0.4 million) due from the Trust to related parties.

During the quarter, AltaGas sold its 33.3335 percent interest in the Ikhil Joint Venture for cash, effective July 31, 2007 to AltaGas Utility Group Inc. for $9.0 million. The gain on the sale was negligible.

14. 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. Transactions among the reporting segments are recorded at fair value. The following describes the Trust's five reporting segments:



Field Gathering and Processing - natural gas gathering lines and processing
facilities;
Extraction and Transmission - ethane and natural gas liquids extraction
plants and natural gas and condensate
transmission pipelines;
Power Generation - coal-fired and gas-fired power output
under power purchase arrangements and
other agreements;
Energy Services - energy management and gas services for
natural gas and electricity; 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 assets and liabilities.


The following tables show the composition by segment:

Three Months Ended
September 30, 2007

Field
Gathering Extraction
and and Power Energy
Processing Transmission Generation Services
----------------------------------------------------------------------------
Revenue $ 33,381 $ 32,671 $ 51,736 $ 211,114
Unrealized gains (losses)
on risk management - - - -
Cost of sales (1,831) (15,675) (17,829) (207,240)
Operating and
administrative (21,870) (5,043) (511) (3,531)
Amortization (6,562) (2,044) (1,873) (552)
----------------------------------------------------------------------------
Operating income (loss) $ 3,118 $ 9,909 $ 31,523 $ (209)
Operating income (loss)
before unrealized gains
(losses) on risk
management $ 3,118 $ 9,909 $ 31,523 $ (209)
----------------------------------------------------------------------------
Net additions
(reductions) to:
Capital assets $ (8,731) $ 669 $ 5,412 $ 8,052
Long-term investment and
other assets - - $ (1,007) -
----------------------------------------------------------------------------
Goodwill $ 215 $ 18,045 - -
Segmented assets $ 488,888 $ 253,509 $ 117,189 $ 119,983
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Intersegment
Corporate Elimination Total
----------------------------------------------------------------------------
Revenue $ 762 $ (8,737) $ 320,927
Unrealized gains (losses) on risk
management 1,142 - 1,142
Cost of sales - 8,679 (233,896)
Operating and administrative (8,176) 58 (39,073)
Amortization (619) - (11,650)
----------------------------------------------------------------------------
Operating income (loss) $ (6,891) - $ 37,450
Operating income (loss) before
unrealized gains (losses) on
risk management $ (8,033) - $ 36,308
----------------------------------------------------------------------------
Net additions (reductions) to:
Capital assets $ 535 - $ 5,937
Long-term investment and other
assets $ (7,027) - $ (8,034)
----------------------------------------------------------------------------
Goodwill - - $ 18,260
Segmented assets $ 182,907 - $1,162,476
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Nine Months Ended
September 30, 2007

Field
Gathering Extraction
and and Power Energy
Processing Transmission Generation Services
----------------------------------------------------------------------------
Revenue $ 103,420 $ 103,644 $ 136,720 $ 795,274
Unrealized gains (losses)
on risk management - - - -
Cost of sales (5,411) (55,556) (55,422) (778,407)
Operating and
administrative (64,772) (14,824) (1,432) (12,137)
Amortization (19,541) (6,051) (5,594) (2,755)
----------------------------------------------------------------------------
Operating income (loss) $ 13,696 $ 27,213 $ 74,272 $ 1,975
Operating income (loss)
before unrealized gains
(losses) on risk
management $ 13,696 $ 27,213 $ 74,272 $ 1,975
----------------------------------------------------------------------------
Net additions
(reductions) to:
Capital assets $ (1,839) $ 4,413 $ 9,308 $ (21,514)
Long-term investment and
other assets - - $ (529) -
----------------------------------------------------------------------------
Goodwill $ 215 $ 18,045 - -
Segmented assets $ 488,888 $ 253,509 $ 117,189 $ 119,983
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Intersegment
Corporate Elimination Total
----------------------------------------------------------------------------
Revenue $ 3,454 $ (52,217) $1,090,295
Unrealized gains (losses) on risk
management 1,617 - 1,617
Cost of sales - 50,445 (844,351)
Operating and administrative (22,755) 1,772 (114,148)
Amortization (1,755) - (35,696)
----------------------------------------------------------------------------
Operating income (loss) $ (19,439) - $ 97,717
Operating income (loss) before
unrealized gains (losses)
on risk management $ (21,056) - $ 96,100
----------------------------------------------------------------------------
Net additions (reductions) to:
Capital assets $ 1,583 - $ (8,049)
Long-term investment and other
assets $ 16,008 - $ 15,479
----------------------------------------------------------------------------
Goodwill - - $ 18,260
Segmented assets $ 182,907 - $1,162,476
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Three Months Ended
September 30, 2006

Field
Gathering Extraction
and and Power Energy
Processing Transmission Generation Services
----------------------------------------------------------------------------
Revenue $ 34,735 $ 41,075 $ 48,724 $ 211,224
Cost of sales (2,439) (23,101) (22,539) (205,070)
Operating and
administrative (19,035) (5,621) (248) (3,321)
Amortization (5,817) (1,937) (1,832) (1,198)
----------------------------------------------------------------------------
Operating income (loss) $ 7,444 $ 10,416 $ 24,105 $ 1,635
Operating income (loss)
before unrealized gains
(losses) on risk
management $ 7,444 $ 10,416 $ 24,105 $ 1,635
----------------------------------------------------------------------------
Net additions
(reductions) to:
Capital assets $ 23,253 $ 644 $ (1,302) $ 37
Energy services
arrangements,
contracts and
relationships - - $ (53) $ 37
Long-term investment and
other assets - - $ 2,138 -
----------------------------------------------------------------------------
Goodwill $ 815 $ 18,045 - -
Segmented assets $ 499,506 $ 243,285 $ 121,487 $ 113,902
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Intersegment
Corporate Elimination Total
----------------------------------------------------------------------------
Revenue $ 490 $ (18,390) $ 317,858
Cost of sales - 17,735 (235,414)
Operating and administrative (9,667) 655 (37,237)
Amortization (655) - (11,439)
----------------------------------------------------------------------------
Operating income (loss) $ (9,832) - $ 33,768
Operating income (loss) before
unrealized gains (losses) on
risk management $ (9,832) - $ 33,768
----------------------------------------------------------------------------
Net additions (reductions) to:
Capital assets $ 915 - $ 23,547
Energy services arrangements,
contracts and relationships - - $ (16)
Long-term investment and other
assets $ (499) - $ 1,639
----------------------------------------------------------------------------
Goodwill - - $ 18,860
Segmented assets $ 52,378 - $1,030,558
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Nine Months Ended
September 30, 2006

Field
Gathering Extraction
and and Power Energy
Processing Transmission Generation Services
----------------------------------------------------------------------------
Revenue $ 102,729 $ 114,612 $ 139,966 $ 693,962
Cost of sales (7,499) (66,913) (68,151) (675,361)
Operating and
administrative (59,485) (13,785) (918) (12,498)
Amortization (17,376) (5,783) (5,484) (3,577)
----------------------------------------------------------------------------
Operating income (loss) $ 18,369 $ 28,131 $ 65,413 $ 2,526
Operating income (loss)
before unrealized gains
(losses) on risk
management $ 18,369 $ 28,131 $ 65,413 $ 2,526
----------------------------------------------------------------------------
Net additions
(reductions) to:
Capital assets $ 50,889 $ 1,393 $ (28) $ 454
Energy services
arrangements,
contracts and
relationships - - (36) -
Long-term investment and
other assets - - 4,242 -
----------------------------------------------------------------------------
Goodwill $ 815 $ 18,045 - -
Segmented assets $ 499,506 $ 243,285 $ 121,487 $ 113,902
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Intersegment
Corporate Elimination Total
----------------------------------------------------------------------------
Revenue $ 2,767 $ (58,818) $ 995,218
Cost of sales - 57,069 (760,855)
Operating and administrative (20,786) 1,749 (105,723)
Amortization (1,758) - (33,978)
----------------------------------------------------------------------------
Operating income (loss) $ (19,777) - $ 94,662
Operating income (loss) before
unrealized gains (losses) on
risk management $ (19,777) - $ 94,662
----------------------------------------------------------------------------
Net additions (reductions) to:
Capital assets $ 1,276 - $ 53,984
Energy services arrangements,
contracts and relationships - - (36)
Long-term investment and other
assets 132 - 4,374
----------------------------------------------------------------------------
Goodwill - - $ 18,860
Segmented assets $ 52,378 - $1,030,558
----------------------------------------------------------------------------
----------------------------------------------------------------------------

15. COMPARATIVE FIGURES

Certain comparative figures have been reclassified to conform to the current
financial presentation.

16. SUBSEQUENT EVENTS

There were no subsequent events after September 30, 2007 requiring
disclosure.

Supplementary Quarterly Financial and Operating Information

($ millions unless otherwise
indicated) Q3-07 Q2-07 Q1-07 Q4-06 Q3-06
----------------------------------------------------------------------------
FINANCIAL HIGHLIGHTS(1)
Net Revenue(2)
Field Gathering and Processing 31.6 34.9 31.6 34.4 32.4
Extraction and Transmission 17.0 15.3 15.8 15.6 17.9
Power Generation 33.9 22.9 24.5 27.8 26.2
Energy Services 3.9 6.9 6.0 6.1 6.1
Corporate 1.9 1.1 2.0 1.6 0.5
Intersegment Elimination - (1.0) (0.6) (0.9) (0.6)
----------------------------------------------------------------------------
88.3 80.1 79.3 84.6 82.5
----------------------------------------------------------------------------

EBITDA(2)
Field Gathering and Processing 9.7 12.9 10.7 13.8 13.3
Extraction and Transmission 12.0 10.8 10.5 9.1 12.3
Power Generation 33.4 22.5 24.0 27.4 26.0
Energy Services 0.3 2.7 1.7 1.5 2.7
Corporate (6.3) (5.8) (5.7) (7.3) (9.2)
----------------------------------------------------------------------------
49.1 43.1 41.2 44.5 45.1
----------------------------------------------------------------------------

Operating Income(2)
Field Gathering and Processing 3.1 6.4 4.2 7.0 7.5
Extraction and Transmission 9.9 8.8 8.5 7.1 10.4
Power Generation 31.5 20.6 22.1 25.5 24.1
Energy Services (0.2) 1.7 0.5 0.2 1.6
Corporate (6.8) (6.3) (6.3) (7.8) (9.9)
----------------------------------------------------------------------------
37.5 31.2 29.0 32.0 33.7
----------------------------------------------------------------------------

OPERATING HIGHLIGHTS
Field Gathering and Processing
Capacity (gross Mmcf/d)(3) 1,008 1,021 1,021 1,021 1,021
Throughput (gross Mmcf/d)(4) 510 534 552 549 537
Capacity utilization (%)(4) 51 52 54 54 53
Extraction and Transmission
Extraction inlet capacity
(Mmcf/d)(3) 554 554 554 554 539
Extraction volumes (Bbls/d)(4) 16,859 19,822 22,622 20,512 19,880
Transmission volumes
(Mmcf/d)(4)(5) 407 407 408 412 388
Power Generation
Volume of power sold (GWh)(4) 673 650 666 711 669
Average price received on sale
of power ($/MWh)(4) 76.92 62.62 66.54 83.45 72.88
Alberta Power Pool average spot
price ($/MWh)(4) 92.00 49.97 63.62 116.81 94.87
Energy Services
Energy management service
contracts(3) 1,451 1,442 1,413 1,394 1,342
Average volumes transacted
(GJ/d)(4) 342,143 356,380 407,272 349,218 325,419
----------------------------------------------------------------------------
(1) Columns may not add due to rounding.
(2) Non-GAAP financial measure. See Non-GAAP Financial Measures section of
the Management Discussion & Analysis.
(3) As at period end.
(4) Average for the period.
(5) Excludes condensate pipeline volumes.


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 and services organizations. The Trust creates value by growing and optimizing assets and services across the energy value chain to serve North America's energy demand. Since 1994, AltaGas Income Trust has expanded its business to include natural gas gathering, processing and transmission, extraction of ethane and natural gas liquids, power generation, marketing of natural gas and natural gas liquids, as well as retail energy services to commercial, industrial and institutional end users across Canada.

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.


FOR FURTHER INFORMATION PLEASE CONTACT:
Media:
AltaGas Income Trust
C.J. Wilkins
(403) 691-9890
Email: cj.wilkins@altagas.ca

or

Investment Community:
AltaGas Income Trust
Stephanie Labowka-Poulin
(403) 691-7136
Email: stephanie.labowka-poulin@altagas.ca

or

AltaGas Income Trust
Investor Relations
1-877-691-7199
Email: investor.relations@altagas.ca
Website: www.altagas.ca