News

AltaGas Reports Strong Operating Results for Second Quarter 2007 And Increases Distribution

August 08, 2007





CALGARY, ALBERTA--(Marketwire - Aug. 8, 2007) - AltaGas Income Trust (TSX:ALA.UN) (AltaGas or the Trust) today announced net income of $13.1 million ($0.23 per unit) for the three months ended June 30, 2007 compared to $29.9 million ($0.54 per unit) for the same quarter in 2006. Excluding the non-cash charge related to the tax on income trusts recorded this quarter of $14.5 million and the non-cash tax benefit of $6.6 million recorded in second quarter 2006, net income in second quarter 2007 was $27.6 million ($0.48 per unit), up from $23.3 million ($0.42 per unit) for the same period of 2006.

Net income for the six months ended June 30, 2007 was $37.6 million ($0.66 per unit) compared to $58.5 million ($1.06 per unit) for the same period in 2006. Excluding the non-cash charge related to the tax on income trusts recorded this quarter of $14.5 million and the non-cash tax benefit of $6.6 million recorded in second quarter 2006, net income for the six months ended June 30, 2007 was $52.1 million ($0.92 per unit) compared to $51.9 million ($0.94 per unit) in the same period in 2006.

AltaGas also 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 is AltaGas' fourth distribution increase since converting to a trust in May 2004. AltaGas' total distributions declared in the second quarter of 2007 were $0.51 per unit.

In addition, a special distribution of one AltaGas Utility Group Inc. (Utility Group) common share for every 100 trust units and exchangeable units of AltaGas held on August 27, 2007 will be made on September 17, 2007. As part of the distribution plan, any Trust unitholder allocated fewer than 50 common shares of Utility Group will receive cash. The cash received by Trust unitholders will be based on the proceeds received by Computershare Trust Company of Canada on sale of the Utility Group shares.

"We are extremely pleased with our operating results this quarter and are on track for another year of solid earnings growth. Our underlying businesses are strong and despite the non-cash charge related to the new tax on income trusts we continue to deliver solid unitholder value," said David Cornhill, Chairman, President and CEO of the Trust. He added, "Our results reflect the success of our business strategy. We continue to see weak gas prices which have impacted throughput in our Field Gathering and Processing segment, but we have been able to mitigate its effect through our contracting strategy. Our commodity diversification strategy has also worked well. While gas markets have weakened, the Alberta power market and frac spreads have remained strong, resulting in robust performance in our Power Generation and Extraction and Transmission segments."

"We also continue to work on growing our gas and power infrastructure to create unitholder value in the long term. I am pleased to announce that we have crossed a milestone in AltaGas' history. Yesterday we announced our 50 percent interest in the Sarnia Airport Pool Storage Project. This is our first energy infrastructure investment in Ontario and allows us to leverage the strong natural gas market knowledge we have in the east. In addition, on July 17, 2007 we submitted three non-binding project bids into the Manitoba Hydro 300 MW Wind Request for Proposal. We recently established a major projects group responsible for ensuring successful completion of our growth initiatives on time and on budget. This group is currently working on the Bear Mountain wind project, the Noel pipeline and sour gas processing plant, the Acme sweet gas facility and the southern Alberta gas-fired peaking plants."

"As of July 31, 2007 AltaGas assumed a leadership role on the Bear Mountain wind project in British Columbia. We are focused on moving the project forward and are finalizing wind turbine purchase and service agreements with Enercon, a leading turbine manufacturer in Germany, and expect to begin construction this fall. Once all major contracts are in place, we will focus on meeting with potential third-party investors. AltaGas plans to maintain a major ownership presence in the wind park."

"While we reported strong operating results this quarter, we were required to record the non-cash charge for the new tax on income trusts that will become effective in 2011. We will continue to review and consider our 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. Our decision will be the one that we believe best protects our unitholders."

Excluding the tax on Specified Investment Flow-Through (SIFT) entities reported this quarter and the non-cash tax benefit recorded in second quarter 2006, net income in second quarter 2007 was higher than in the same quarter last year. Net income increased primarily due to a one-time gain resulting from the sale of oil and gas production assets, one new facility, higher rates and routine equalization adjustments in the Field Gathering and Processing (FG&P) segment and higher hedge prices on power sales. These increases were partially offset by lower throughput in FG&P, higher operating and administrative costs and lower fractionation spreads and lower power pool prices.

Excluding the SIFT tax reported this quarter and the non-cash tax benefit recorded in second quarter 2006, net income for the six months ended June 30, 2007 was higher than in the same period last year. Net income increased as a result of a one-time gain resulting from the sale of oil and gas production assets, higher rates and volumes from new and expanded FG&P facilities, higher prices received on power sales, and lower interest expense due to a reduced debt balance. These increases were partially offset by the expiration of the Genesee power contract, lower throughput in the FG&P segment, lower fractionation spreads and higher operating and administrative costs.

FINANCIAL HIGHLIGHTS(1)

- Earnings before interest, taxes, depreciation and amortization were $43.1 million ($0.75 per unit) this quarter compared to $37.4 million ($0.68 per unit) in the same quarter in 2006. Earnings before interest, taxes, depreciation and amortization for the first half of 2007 were $84.3 million ($1.48 per unit), up from $83.4 million ($1.52 per unit) in the first half of 2006.

- Cash from operations was $46.6 million ($0.81 per unit) for second quarter 2007 compared to $43.8 million ($0.79 per unit) for the same period in 2006. Cash from operations for the first half of 2007 was $92.7 million ($1.63 per unit), up from $69.5 million ($1.26 per unit) in the first half of 2006.

- Funds from operations were $39.2 million ($0.69 per unit) for second quarter 2007, compared to $35.7 million ($0.65 per unit) for the same period in 2006. Funds from operations for the first half of 2007 were $77.4 million ($1.36 per unit), up from $76.7 million ($1.39 per unit) in the first half of 2006.

- Total debt was $229.7 million, compared to $265.5 million at December 31, 2006. The Trust's debt-to-total capitalization ratio was 30.0 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 second quarter Management's Discussion and Analysis.

IN THE SECOND QUARTER:

- AltaGas announced an investment of approximately $90 million for the construction of a new natural gas pipeline to bring 90 Mmcf/d of natural gas from the Noel region of British Columbia to a 90 Mmcf/d sour gas expansion of its Pouce Coupe gas processing facility in northwest Alberta by mid-2008. The project is subject to provincial and federal regulatory approvals.

- AltaGas announced the acquisition of 14.4 megawatts of power generation capacity, increasing its gas-fired generation under operation by more than 55 percent. The new peaking generation will be installed at current FG&P locations in southern Alberta at an estimated cost of $10 million.

- AltaGas announced that it will construct a new 10 Mmcf/d gas processing facility and associated gathering and sales lines near Acme, Alberta. Subsequent to the announcement, the scope of the project was expanded. The facility will process coal bed methane and construction of both facility and pipelines is now expected to cost approximately $13 million and be in service in fourth quarter 2007.

- AltaGas announced that effective June 1, 2007 it had sold the Cedar Energy Partnership to a private energy company for approximately $12 million. Cedar Energy Partnership held approximately 85 percent of the Trust's non-core oil and gas production assets. The Trust recorded a one-time after-tax gain of $2.1 million on the sale of the partnership.

- As a result of the new legislation related to the taxation of trusts and compliance with Canadian accounting guidelines, AltaGas recorded $14.5 million as a future non-cash tax expense in second quarter 2007.

SUBSEQUENT TO THE SECOND 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 on July 17, 2007. Responses to the bids are expected in September 2007.

- AltaGas expects to file a final short-form base shelf prospectus to facilitate the issuance of trust units or unsecured debt securities on August 8, 2007. This shelf has a 25-month life and permits the Trust to issue up to an aggregate of $500 million of securities.

- AltaGas signed an agreement to sell its 33.3335 percent interest in the Ikhil Joint Venture to AltaGas Utility Group Inc. for $9 million. No gain or loss is expected to result from the sale, which is effective July 1, 2007 and is subject to normal regulatory approvals.

- 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 will remain in effect and will continue 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 signed an agreement to purchase a 50 percent interest in the Sarnia Airport Pool Storage Project. Once developed, the Sarnia Airport Pool 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.

- 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 has also agreed to repay Aeolis' loans of approximately $1.0 million that it made to BMWLP to fund its share of development costs incurred to date. These loan repayments, 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 will hold a teleconference today at 2:00 p.m. MDT (4:00 p.m. EDT) to discuss the second 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/080807/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 3228628. The replay will expire at midnight (EDT) on August 15, 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 August 8, 2007 is a review of the results of operations and the liquidity and capital resources of the Trust for the three and six months ended June 30, 2007 compared to the three and six months ended June 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 six months ended June 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 Six Months
Ended June 30 Ended June 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------

Revenue 341.8 299.6 769.8 677.4
Unrealized gains (losses) on risk
management 0.4 - 0.5 -
Net revenue(1) 80.1 72.8 159.4 151.9
EBITDA(1) 43.1 37.4 84.3 83.4
EBITDA before unrealized gains (losses)
on risk management(1) 42.7 37.4 83.8 83.4
Operating Income(1) 31.2 26.0 60.3 60.9
Operating Income before unrealized gains
(losses) on risk management(1) 30.8 26.0 59.8 60.9
Net income 13.1 29.9 37.6 58.5
Net income before tax-adjusted unrealized
gains (losses) on risk management(1) 13.1 29.9 38.1 58.5
Net income before SIFT tax 27.6 29.9 52.1 58.5
Total assets 1,179.6 1,000.6 1,179.6 1,000.6
Total long-term liabilities 377.9 341.9 377.9 341.9
Net additions (reductions) to capital
assets (19.2) 13.4 (14.0) 30.4
Distributions declared(2) 29.2 27.4 58.2 54.0
Cash flows
Cash from operations 46.6 43.8 92.7 69.5
Funds from operations(1) 39.2 35.7 77.4 76.7
Distributable cash(1) 37.1 34.1 74.1 73.5
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Three Months Six Months
Ended June 30 Ended June 30
($ per unit) 2007 2006 2007 2006
----------------------------------------------------------------------------

EBITDA(1) 0.75 0.68 1.48 1.52
EBITDA before unrealized gains (losses)
on risk management(1) 0.75 0.68 1.47 1.52
Net income 0.23 0.54 0.66 1.06
Net income before tax-adjusted unrealized
gains (losses) on risk management(1) 0.23 0.54 0.67 1.06
Net income before SIFT tax 0.48 0.54 0.92 1.06
Distributions declared(2) 0.51 0.495 1.02 0.98
Cash flows
Cash from operations(1) 0.81 0.79 1.63 1.26
Funds from operations(1) 0.69 0.65 1.36 1.39
Distributable cash(1) 0.65 0.62 1.30 1.34
Units outstanding - basic (millions)
During the period(3) 57.2 55.2 56.9 55.0
End of period 57.5 55.4 57.5 55.4
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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 $0.17 per unit per month commencing in
August 2006. 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 June 30

Net income for the three months ended June 30, 2007 was $13.1 million ($0.23 per unit) compared to $29.9 million ($0.54 per unit) for the same period in 2006. Excluding the non-cash Specified Investment Flow-Through (SIFT) tax of $14.5 million recorded this quarter and the $6.6 million non-cash tax benefit recorded in second quarter 2006, net income was $27.6 million ($0.48 per unit) compared to $23.3 million ($0.42 per unit) for the same period in 2006. Net income excluding the impact of the non-cash taxes was higher this quarter than the same quarter last year as a result of a one-time after-tax gain of $2.1 million from the sale of oil and natural gas production assets, the new Clear Hills facility, higher rates and higher routine positive equalization adjustments in the FG&P segment, higher hedge prices for power sales, the expansion of the Cold Lake transmission system and increased ownership at one of the Empress extraction facilities. The increases were partially offset by lower throughput resulting from natural declines and lower producer activity in the FG&P segment, lower frac spreads, lower revenue from unhedged power sales and lower contributions from the energy management business. Excluding the non-cash tax items in second quarter 2007 and 2006 as well as the one-time after-tax gain reported on disposition of the oil and natural gas production assets, net income increased quarter-over-quarter by 9 percent.

On a consolidated basis, net revenue for second quarter 2007 was $80.1 million compared to $72.8 million in the same quarter last year. Net revenue increased for second quarter 2007 due to the one-time gain on the sale of oil and gas productions assets, the new Clear Hills FG&P facility, higher operating cost recoveries, higher rates and higher routine positive equalization adjustments in the FG&P segment, higher hedged power prices, the expansion of the Cold Lake transmission system and increased ownership at one of the Empress extraction facilities. The increases were partially offset by lower throughput in FG&P, lower frac spreads, lower revenue from unhedged power sales and lower revenues from the Energy Services segment as a result of non-recurring earnings realized in 2006.

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 second quarter 2007 was $37.0 million compared to $35.5 million in the same quarter last year. The increase was due to additional costs related to a new FG&P facility, higher costs as a result of increased ownership at one of the extraction facilities and higher compensation costs, partially offset by lower professional and consulting fees.

Amortization expense for second quarter 2007 was $11.9 million compared to $11.4 million in the same quarter last year. The increase was primarily attributable to new and expanded facilities in the field gathering and processing business, partially offset by lower amortization as a result of the disposition of oil and gas production assets.

Interest expense for second quarter 2007 was $3.0 million compared to $3.4 million in the same quarter last year. The decrease was due to a lower average debt balance of $240.0 million (second quarter 2006 - $278.3 million) as a result of repaying long-term debt with excess cash generated from operations. The average borrowing rate in second quarter 2007 was 5.3 percent compared to 4.9 percent in second quarter 2006.

Income tax expense for second quarter 2007 was $15.1 million compared to an income tax recovery of $7.3 million in the same period in 2006. The increase was due to the non-cash charge of $14.5 million to record future income tax liabilities for differences between the accounting and tax basis of AltaGas' assets and liabilities as a result of tax legislation substantively enacted on June 12, 2007, the $6.6 million non-cash tax benefit recorded in second quarter 2006 as a result of Alberta and federal income tax rate reductions and to higher operating income, partially offset by a future income tax recovery of $0.6 million from the sale of oil and natural gas production assets.

Six Months Ended June 30

Net income for the six months ended June 30, 2007 was $37.6 million ($0.66 per unit) compared to $58.5 million ($1.06 per unit) in the same period last year. Excluding the non-cash SIFT tax of $14.5 million recorded this quarter and the non-cash tax benefit of $6.6 million recorded in second quarter 2006, net income was $52.1 million ($0.92 per unit) compared to $51.9 million ($0.94 per unit) for the same period in 2006. Net income increased as a result of the one-time gain from the sale of oil and natural gas production assets, new and expanded facilities, higher rates and higher routine positive equalization adjustments in the FG&P segment, higher prices received on power sales, higher power peaking plant revenues, higher ethane and natural gas liquids (NGL) volumes and lower interest expense. The increases in net income were partially offset by the expiration of the Genesee power contract on March 31, 2006 which contributed $4.1 million to net income in first quarter 2006, continued lower throughput in the FG&P segment, lower frac spreads and higher operating and administrative expenses.

On a consolidated basis, net revenue in the first half of 2007 was $159.4 million compared to $151.9 million for the same period in 2006. The increase was due to the one-time gain on the sale of oil and natural gas production assets, new and expanded facilities, higher rates and higher operating cost recoveries in the FG&P segment, higher power prices received on power sales, higher peaking plant revenues and higher extraction volumes processed. The increase was partially offset by the expiration of the Genesee power contract, lower throughput and lower take-or-pay adjustments in the FG&P segment and lower frac spreads.

Operating and administrative expense for the six months ended June 30, 2007 was $75.1 million compared to $68.5 million in the same period last year. The increase was due to additional costs related to new facilities and increased ownership at one of the extraction facilities and to higher operating and administrative costs.

Amortization expense for the first half of 2007 was $24.0 million compared to $22.5 million in the same period last year primarily due to new and expanded facilities in the FG&P segment.

Interest expense for the six months ended June 30, 2007 was $6.2 million compared to $6.6 million in the same period last year. The decrease was due to a lower average debt balance of $248.1 million (first half of 2006 - $276.4 million) as a result of repaying long-term debt with excess cash generated from operations. The average borrowing rate in the first half of 2007 was 5.2 percent compared to 4.9 percent in the same period in 2006.

Income tax expense for the six months ended June 30, 2007 was $16.5 million compared to an income tax recovery of $4.2 million in the same period in 2006. The increase was due to the non-cash charge of $14.5 million to record future income tax liabilities for differences between the accounting and tax basis of AltaGas' assets and liabilities as a result of tax legislation substantively enacted on June 12, 2007, a $6.6 million non-cash tax benefit recorded in second quarter 2006 due to Alberta and federal income tax rate reductions, and a $1.0 million tax impact on unrealized gains related to risk management assets and liabilities, 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 (SIFT) 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. As a result, AltaGas recorded a future income tax expense of $14.5 million and increased its future income tax liability in second quarter 2007. 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 second quarter of 2007 was significantly reduced by this future income tax adjustment, the non-cash future income tax expense has no current impact on 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 the 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 Six Months
Ended June 30 Ended June 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Net Revenue 80.1 72.8 159.4 151.9
Add (deduct): Cost of sales 261.7 226.8 610.4 525.5
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Revenue (GAAP financial measure) 341.8 299.6 769.8 677.4
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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 Six Months
Ended June 30 Ended June 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Operating income 31.2 26.0 60.3 60.9
Add (deduct): Interest expense (3.0) (3.4) (6.2) (6.6)
Income tax expense (15.1) 7.3 (16.5) 4.2
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Net income (GAAP financial measure) 13.1 29.9 37.6 58.5
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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 of capital assets.



Operating Income Before Unrealized Gains (Losses) on Risk Management

Three Months Six Months
Ended June 30 Ended June 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Operating income before unrealized gains
(losses) on risk management 30.8 26.0 59.8 60.9
Add (deduct): Unrealized gains (losses) on
risk management 0.4 - 0.5 -
Interest expense (3.0) (3.4) (6.2) (6.6)
Income tax expense (15.1) 7.3 (16.5) 4.2
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Net income (GAAP financial measure) 13.1 29.9 37.6 58.5
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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 of capital assets.



EBITDA
Three Months Six Months
Ended June 30 Ended June 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
EBITDA 43.1 37.4 84.3 83.4
Add (deduct): Amortization (11.9) (11.4) (24.0) (22.5)
Interest expense (3.0) (3.4) (6.2) (6.6)
Income tax expense (15.1) 7.3 (16.5) 4.2
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Net income (GAAP financial measure) 13.1 29.9 37.6 58.5
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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 (Losses) on Risk Management

Three Months Six Months
Ended June 30 Ended June 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
EBITDA before unrealized gains (losses) on
risk management 42.7 37.4 83.8 83.4
Add (deduct): Unrealized gains (losses) on
risk management 0.4 - 0.5 -
Amortization (11.9) (11.4) (24.0) (22.5)
Interest expense (3.0) (3.4) (6.2) (6.6)
Income tax expense (15.1) 7.3 (16.5) 4.2
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Net income (GAAP financial measure) 13.1 29.9 37.6 58.5
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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 Risk Management

Three Months Six Months
Ended June 30 Ended June 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Net income before tax-adjusted unrealized
gains (losses) on risk management 13.1 29.9 38.1 58.5
Add (deduct): Unrealized gains (losses) on
risk management 0.4 - 0.5 -
Income tax expense on risk
management (0.4) - (1.0) -
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Net income (GAAP financial measure) 13.1 29.9 37.6 58.5
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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 Six Months
Ended June 30 Ended June 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Funds from operations 39.2 35.7 77.4 76.7
Add (deduct): Net change in non-cash working
capital and asset retirement
obligations settled 7.4 8.1 15.3 (7.2)
----------------------------------------------------------------------------
Cash from operations (GAAP financial
measure) 46.6 43.8 92.7 69.5
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


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.



Distributable Cash

Three Months Six Months
Ended June 30 Ended June 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Distributable cash 37.1 34.1 74.1 73.5
Add (deduct): Maintenance related invested
capital 2.1 1.6 3.3 3.2
Net change in non-cash working
capital and asset retirement
obligations settled 7.4 8.1 15.3 (7.2)
----------------------------------------------------------------------------
Cash from operations (GAAP financial
measure) 46.6 43.8 92.7 69.5
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Distributable cash is used by management to supplement cash from operations as an estimate of the amount which is available for distribution to unitholders. Distributable cash is defined as cash from operations less expenditures for maintenance capital and before changes in non-cash working capital and expenditures incurred to settle asset retirement obligations. Maintenance capital expenditures are incurred to sustain the productive capacity of the Trust's assets and are not incurred evenly throughout the year. Distributable cash is not a defined financial measure under GAAP and distributable cash cannot be assured. The Trust's calculation of distributable cash may differ from similar calculations used by other entities.

References to net revenue, operating income, operating income before unrealized gains (losses) on risk management, EBITDA, EBITDA before unrealized gains (losses) on risk management, net income before tax-adjusted unrealized gains (losses) on risk management, funds from operations and distributable cash throughout this document have the meanings set out in this section.



RESULTS OF OPERATIONS BY SEGMENT

Operating Income

Three Months Six Months
Ended June 30 Ended June 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Field Gathering and Processing 6.4 4.0 10.6 10.9
Extraction and Transmission 8.8 9.4 17.3 17.7
Power Generation 20.6 18.5 42.7 41.3
Energy Services 1.7 0.4 2.2 1.0
Corporate (6.3) (6.3) (12.5) (10.0)
----------------------------------------------------------------------------
31.2 26.0 60.3 60.9
----------------------------------------------------------------------------
Operating income before unrealized gains
(losses) on risk management 30.8 26.0 59.8 60.9
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


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 Six Months
Ended June 30 Ended June 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue 36.8 33.5 70.0 68.0
Net revenue 34.9 31.0 66.5 62.9
Operating and administrative 22.0 21.2 42.9 40.4
Amortization 6.5 5.8 13.0 11.6
Operating income 6.4 4.0 10.6 10.9
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----------------------------------------------------------------------------

Operating Statistics
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Capacity (Mmcf/d)(1) 1,021 1,002 1,021 1,002
Throughput (gross Mmcf/d)(2) 534 565 543 568
Capacity utilization (%)(2) 52 56 53 57
Average working interest (%)(1) 92 90 92 90
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) As at June 30.
(2) Average for the period.

 


Three Months Ended June 30

Operating income in the FG&P segment in second quarter 2007 was $6.4 million compared to $4.0 million for the same quarter last year. Despite the decline in throughput resulting from natural declines and lower producer activity, operating income remained strong as a result of new and expanded facilities as well as higher operating costs flowed through to customers and take-or-pay contractual arrangements. Operating income increased by $3.5 million as a result of higher rates, routine equalization adjustments and the new Clear Hills facility and by $0.8 million due to lower administrative expenses. The increases were partially offset by $2.1 million due to lower throughput resulting from natural declines and lower producer activity.

Throughput in second quarter 2007 averaged 534 Mmcf/d compared to 565 Mmcf/d in second quarter 2006. The 5 percent decrease in throughput was primarily due to natural declines and lower producer activity. In the North district, throughput decreased by 26 Mmcf/d due to natural declines and lower producer activity, partially offset by 7 Mmcf/d contributed by the new Clear Hills facility. Despite the declines, AltaGas believes the North district to be an area with potential opportunities to increase throughput due to expected high producer activity. The decline of 12 Mmcf/d in the South district was due to natural declines, partially offset by higher throughput from new wells at South Foothills.

Utilization reported in second quarter 2007 was 52 percent compared to 56 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 second quarter 2007 was $34.9 million compared to $31.0 million for the same period in 2006. The increase was primarily due to higher rates and the new Clear Hills facility ($3.1 million) and to increased recovery of operating costs and routine equalization adjustments ($2.8 million), partially offset by the impact of lower throughput ($2.1 million).

Operating and administrative expense for second quarter 2007 was $22.0 million compared to $21.2 million for the same period in 2006. The increase was due to additional operating costs at the new Clear Hills facility and higher labour costs and property taxes, partially offset by lower allocated corporate costs.

Amortization expense for the FG&P segment in second 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 second quarter 2007 was 18 percent compared to 13 percent in the same quarter in 2006. The increase in the second quarter was primarily due to increased revenue from higher rates, higher costs recovered and the contribution from the new Clear Hills facility. (See Non-GAAP Financial Measures section of this MD&A for description of operating income and net revenue.)

Six Months Ended June 30

Operating income in the FG&P segment in the first half of 2007 was $10.6 million compared to $10.9 million for the same period last year. Operating income declined $3.7 million in the first half of 2007 as a result of lower throughput and $0.7 million due to lower take-or-pay adjustments offset by $1.8 million due to new and expanded facilities, $1.4 million due to higher rates and $0.8 million as a result of lower operating and administrative costs.

Throughput in the first half of 2007 averaged 543 Mmcf/d compared to 568 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 15 Mmcf/d contributed by AltaGas' new Clear Prairie, Clear Hills and Princess facilities. Of the 25 Mmcf/d throughput decrease, 17 Mmcf/d was attributable to the North district and the balance to the South district. In the North district, the Wabasca winter only access drilling area experienced throughput declines of 11 Mmcf/d as a result of a less successful drilling program than the previous year. Despite the declines, AltaGas believes the North district to be an area with potential opportunities to increase throughput due to expected high producer activity. 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 six months ended June 30 was 53 percent and 57 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 FG&P segment in the first half of 2007 was $66.5 million compared to $62.9 million for the same period last year. The increase was due to $4.6 million from new and expanded facilities, $1.4 million due to higher rates, $1.6 million due to higher operating cost recoveries and $0.4 million from higher product revenue, partially offset by $3.7 million due to lower well tie-ins and natural declines and $0.7 million related to take-or-pay adjustments.

Operating and administrative expense for the first half of 2007 was $42.9 million compared to $40.4 million for the same period in 2006. The increase was due to additional costs related to new facilities and higher operating costs primarily due to higher labour costs and property taxes, partially offset by lower allocated corporate costs.

Amortization expense for the FG&P segment for the first half of 2007 was $13.0 million compared to $11.6 million for the same period in 2006 due to new and expanded facilities.

Operating income as a percentage of net revenue in the first half of 2007 was 16 percent, compared to 17 percent in the same period in 2006. The decrease was due to lower throughput and higher operating cost recoveries which were partially offset by the contribution from new and expanded facilities and higher rates. (See Non-GAAP Financial Measures section of this MD&A for description of operating income and net revenue.)

FG&P Outlook

AltaGas expects results in the FG&P segment in 2007 to be slightly higher than 2006 as a result of the addition and expansion of facilities. However, the weak natural gas markets are expected to result in continued lower producer drilling activity and hence lower year-over-year throughput. AltaGas continues to execute its strategy to increase the percentage of operating costs flowed through to customers, increase volumes by adding new facilities and enter into more contracts with take-or-pay provisions to mitigate the near-term impact of lower well tie-ins and natural declines. The majority of AltaGas' facilities are also moveable, providing the opportunity to redeploy equipment to areas that are more active and productive. Forward natural gas market prices for the end of the year are higher than current near-term prices. This forward curve, along with lower operating costs and lower cost of land acquisitions, suggests that drilling may increase in the next several months, with the potential for increased throughput. AltaGas expects current market conditions to yield opportunities to expand, construct, and acquire processing facilities as producers continue to focus capital investment on drilling opportunities. In 2007 AltaGas expects to spend approximately $50 million of capital in addition to the Noel pipeline and Pouce Coupe expansion.

AltaGas previously announced the Noel pipeline and Pouce Coupe processing facility expansion project which was estimated to cost approximately $90 million and be in service in mid-2008. AltaGas and Devon Canada Corporation expect to finalize the project configuration and scheduling in third quarter 2007. Once in service, AltaGas expects throughput to increase by more than 10 percent.

AltaGas also announced that it will construct a new gas processing facility and associated gathering and sales lines near Acme, Alberta capable of processing 10 Mmcf/d of natural gas. Subsequent to the announcement, the scope of the project was expanded. The facility will process coal bed methane (CBM) and is now expected to cost $13 million. The facility is expected to be in service in fourth quarter 2007.

Subsequent to the quarter, AltaGas signed an agreement to sell its 33.3335 percent interest in the Ikhil Joint Venture to AltaGas Utility Group Inc. for $9 million. During the second half of 2006, these assets contributed approximately $0.5 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 Six Months
Ended June 30 Ended June 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue 33.6 37.4 71.0 73.5
Net revenue 15.3 15.3 31.1 29.7
Operating and administrative 4.5 4.0 9.8 8.2
Amortization 2.0 1.9 4.0 3.8
Operating income 8.8 9.4 17.3 17.7
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Operating Statistics
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------

Extraction inlet capacity (Mmcf/d)(1) 554 539 554 539
Extraction volumes (Bbls/d)(2) 19,822 18,976 21,214 19,188
Transmission volumes (Mmcf/d)(2)(3) 407 399 408 399
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

 


Three Months Ended June 30

Operating income in the E&T segment in second quarter 2007 was $8.8 million compared to $9.4 million for the same period in 2006. The decrease was primarily due to lower NGL frac spreads ($0.5 million). Although realized frac spreads remained strong in second quarter 2007, average frac spreads were approximately $18.00/Bbl, or $5.00/Bbl lower than in the second quarter of 2006 when frac spreads were at historic levels. The decrease was partially offset by the expansion of the Cold Lake transmission system which began contributing to income in May 2007 and increased ownership at one of the Empress facilities which occurred in fourth quarter 2006.

Average ethane and NGL volumes in the extraction business were higher in second quarter 2007 compared to the same quarter last year due to the increased ownership at one of the Empress facilities and to increased utilization in April and June of 2007 at the other Empress facility. However, this was offset by reduced throughput in May 2007 due to a scheduled plant turnaround. Even with the turnaround, average volumes processed were higher at this facility in second quarter 2007 than the same quarter in 2006. Transmission volumes were up mainly due to higher volumes moved on the Suffield system.

Net revenue in both second quarter 2007 and 2006 was $15.3 million. Net revenue in the quarter was down due to lower frac spreads in the extraction business. The decrease was offset by the expansion of the Cold Lake transmission system, the increased ownership at one of the Empress facilities and higher costs recovered under contractual arrangements.

Operating and administrative expense in second quarter 2007 was $4.5 million compared to $4.0 million for the same period in 2006. The increase was primarily due to the increased ownership at one of the Empress facilities.

Amortization expense in second quarter 2007 was $2.0 million compared to $1.9 million for the same period in 2006. The slight increase was due to the addition of the increased ownership at one of the Empress facilities, and the enhanced ethane recovery project.

Operating income as a percentage of net revenue in second quarter 2007 was 58 percent compared to 61 percent for second quarter 2006. The decrease was primarily due to lower frac spreads in the extraction business. (See Non-GAAP Financial Measures section of this MD&A for description of operating income and net revenue.)

Six Months Ended June 30

Operating income in the E&T segment in the first half of 2007 was $17.3 million compared to $17.7 million for the same period in 2006. Operating income decreased $0.7 million as a result of lower frac spreads and $0.4 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 volumes processed in the extraction business and the expansion of the Cold Lake transmission system. Although frac spreads remained strong at $14.50/Bbl for the first half of the year, they were lower than the historic high of $18.00/Bbl for the same period in 2006.

Average ethane and NGL volumes increased as a result of higher volumes processed, the increased ownership at one of the Empress facilities and the enhanced ethane recovery project that increased gas processing capability and ethane recovery at the Edmonton extraction plant. Transmission volumes were up mainly due to higher volumes transported on the Suffield system.

Net revenue in the first half of 2007 was $31.1 million, compared to $29.7 million for the same period in 2006. The increase was due to higher ethane volumes from the enhanced ethane recovery project, higher ethane yields and increased operating costs recovered, higher ethane and NGL volumes from additional gas supply arrangements, the increased ownership at one of the Empress facilities and the expansion of the Cold Lake transmission system. 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 six months ended June 30, 2007 was $9.8 million compared to $8.2 million for the same period last year. The increase was due to the enhanced ethane recovery project, the increased ownership at one of the Empress facilities, higher variable costs associated with increased utilization and increased operating costs on the Suffield system. Approximately $6.7 million of operating costs were recovered and hence included in the net revenue in the first half of 2007 compared to $5.7 million in the same period in 2006.

Amortization expense in the first half of 2007 was $4.0 million compared to $3.8 million for the same period in 2006. The increase was due to the enhanced recovery project and increased ownership at one of the Empress facilities.

Operating income as a percentage of net revenue in the first half of 2007 was 56 percent compared to 60 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 similar to 2006 results. In the extraction 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. Based on current natural gas and product price forecasts, frac spreads for the remainder of 2007 are expected to be approximately $20.00/Bbl. Any impact from lower frac spreads is anticipated to be mitigated by the recent growth in the extraction business. For the remainder of 2007 there is one turnaround planned at the Edmonton ethane extraction plant. The turnaround is not expected to have a material impact on operating income.

In the transmission business, results for the year are expected to be slightly higher when compared to 2006 primarily due to the expansion of the Cold Lake transmission system which began contributing to earnings in May 2007. Based on projected volumes to be shipped on the Suffield system, AltaGas does not expect to record any further revenue deferrals for the remainder of the year.

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 Six Months
Ended June 30 Ended June 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue 40.7 39.5 85.0 91.2
Net revenue 22.9 20.7 47.4 45.6
Operating and administrative 0.4 0.4 1.0 0.7
Amortization 1.9 1.8 3.7 3.6
Operating income 20.6 18.5 42.7 41.3
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Operating Statistics Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Volume of power sold (GWh) 650 656 1,315 1,498
Average price received on the sale of
power ($/MWh)(1) 62.62 60.26 64.61 60.91
Alberta Power Pool average spot price
($/MWh)(1) 49.97 53.59 56.79 55.17
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Average for the period.

 


Three Months Ended June 30

Operating income for the Power Generation segment in second quarter 2007 was $20.6 million compared to $18.5 million for the same quarter in 2006. Operating income increased by $1.8 million due to higher hedge prices offset by lower revenue from unhedged volumes as a result of lower average spot power prices. Lower costs also contributed to the increase in operating income in the quarter.

Net revenue in second quarter 2007 was $22.9 million compared to $20.7 million for the same period in 2006 due to higher hedge prices and lower costs, offset by lower revenue from unhedged volumes and the gas-fired peaking plants.

Operating and administrative expense was $0.4 million in second quarter 2007, the same as in second quarter 2006. Beginning March 15, 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 at $1.9 million in second quarter 2007, remained similar to $1.8 million in the same period in 2006.

Operating income as a percentage of net revenue in second quarter 2007 was 90 percent compared to 89 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.)

Six Months Ended June 30

Operating income for the first half of 2007 was $42.7 million compared to $41.3 million for the same period in 2006. The increase was due to higher Sundance revenues as a result of higher power prices received on both hedged and unhedged power sales ($4.9 million), higher peaking plant revenue ($0.6 million) and lower PPA costs, partially offset by the expiration of the Genesee contract in March 2006 which contributed $4.1 million to operating income in first quarter 2006.

The volume of power sold in the first half of 2007 was lower than in the same period in 2006 primarily as a result of the Genesee contract expiration on March 31, 2006.

Net revenue for the first half of 2007 was $47.4 million compared to $45.6 million for the same period in 2006. The increase was due to higher prices on hedged and unhedged power sales and increased peaking plant revenue partially offset by the expiration of the Genesee power contract.

Operating and administrative expense of $1.0 million in the first half of 2007 was slightly higher than the $0.7 million reported in the first half of 2006 primarily due to the operating and maintenance services AltaGas began providing to the leased peaking plants in March 2007.

Amortization expense of $3.7 million in the first half of 2007 was similar to $3.6 million in the same period in 2006.

Operating income as a percentage of net revenue was 90 percent in the first half of 2007, similar to 91 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.)

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 the power volumes is exposed to the spot price in Alberta. Current forward prices for the remainder of 2007 are similar to what was realized in the second half of 2006. With similar spot prices and higher average hedge prices, operating income is expected to be higher for the year. Although one of the Sundance units is currently undergoing a planned outage, AltaGas does not expect the financial impact to be material as the Trust receives payments for the lost production based on the 30-day rolling average power price.

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 $2.5 million (approximately $5.0 million annualized). 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 the meantime, the owner and operator of Sundance power plant is investigating opportunities to increase plant efficiency that are more economical than the current proposed cost of $15/tonne of carbon dioxide equivalent.

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 current FG&P locations in southern Alberta with access to natural gas supply and the electrical grid. The facilities are expected to be integrated into ongoing operations and be in service in late 2007 and early 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.

On August 2, 2007, Bear Mountain Wind Limited Partnership (BMWLP) a partnership 50 percent owned by AltaGas 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 has also agreed to repay Aeolis' loans of approximately $1.0 million that it made to BMWLP to fund its share of development costs incurred to date. As a result, AltaGas owns 100 percent of BMWLP and the Bear Mountain Wind Project.

In addition, BMWLP has signed a services agreement with Aeolis, pursuant to which Aeolis would provide certain project support. AltaGas intends to finance the project, currently estimated at approximately $200 million, through its credit facilities. While its existing interest in the project is 100 percent, AltaGas intends to include one or more third-party investors. The previously announced 120 MW Bear Mountain wind park is underpinned by a 25-year electricity purchase agreement with BC Hydro. BMWLP continues to optimize the project configuration and finalize wind turbine purchase and service agreements with Enercon GmbH, a leading German manufacturer of gearless turbines. Construction is scheduled to begin in the fall of 2007, with a planned in-service date of late 2009. The project continues to be subject to certain regulatory and environmental approvals, which are anticipated to be received by the fall of 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. Until May 31, 2007 the segment included a small portfolio of oil and natural gas production assets which was sold in the current quarter.



Financial Results Three Months Six Months
Ended June 30 Ended June 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue 248.6 209.7 584.2 482.7
Net revenue 6.9 6.4 13.0 12.5
Operating and administrative 4.2 4.7 8.6 9.1
Amortization 1.0 1.3 2.2 2.4
Operating income 1.7 0.4 2.2 1.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Operating Statistics Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Energy management service contracts(1) 1,442 1,289 1,442 1,289
Average volumes transacted (GJ/d)(2) 356,380 322,420 381,826 316,626
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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 June 30

Operating income in the Energy Services segment in second quarter 2007 was $1.7 million compared to $0.4 million for the same quarter in 2006. Operating income increased due to a one-time pre-tax gain of $1.5 million recorded as a result of the sale of oil and natural gas production assets and to increased margins in the gas services business, partially offset by lower contributions from the energy management business due to non-recurring earnings reported in 2006.

Net revenue in second quarter 2007 was $6.9 million compared to $6.4 million for the same period in 2006. Net revenue increased as a result of the one-time gain of $1.5 million from the sale of oil and natural gas production assets, $0.4 million due to higher fixed-price commodity gas volumes and increased transportation revenues and expansion into the Ontario electricity market, partially offset by $0.7 million of non-recurring earnings reported in second quarter 2006 and lower operating revenue of $0.6 million from the oil and gas production assets. Oil and natural gas production net revenue in second quarter 2007 was $1.2 million compared to $1.8 million in second quarter 2006, reflecting lower oil and natural gas production of $0.5 million and lower natural gas prices of $0.1 million.

Operating and administrative expense in second quarter 2007 was $4.2 million compared to $4.7 million for the same quarter in 2006. The decrease was due to lower costs as a result of the sale of oil and natural gas production assets and lower general and administrative expenses due to lower activity in the energy management business.

Amortization expense in second quarter 2007 was $1.0 million compared to $1.3 million in the same quarter in 2006 primarily due to the sale of oil and natural gas production assets in May 2007.

Operating income as a percentage of net revenue increased to 25 percent in second quarter 2007 as a result of the one-time pre-tax gain on sale of oil and natural gas production assets. This was up from 6 percent in the same period in 2006. Operating income as a percentage of net revenue without the effect of this one-time gain in second quarter 2007 was 4 percent, slightly lower compared to the same period in 2006. (See Non-GAAP Financial Measures section of this MD&A for description of operating income and net revenue.)

Six Months Ended June 30

Operating income in the Energy Services segment in the first half of 2007 was $2.2 million compared to $1.0 million for the same period in 2006. The increase was due to 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 Ontario electricity market, partially offset by non-recurring earnings reported in 2006, higher gas costs to meet a natural gas supply contract and lower contributions from the operations of the oil and natural gas production assets. The contribution to operating income in the first half of 2007 from the oil and gas production assets was $0.5 million lower than the same period in 2006.

Net revenue in the first half of 2007 was $13.0 million compared to $12.5 million in the same period in 2006. The increase was due to the one-time pre-tax gain from the sale of oil and natural gas production assets of $1.5 million, $1.1 million due to higher fixed-price commodity gas volumes and higher transportation revenue and $0.5 million due to expansion into the Ontario electricity market and growth in targeted sectors, partially offset by $1.0 million related to non-recurring earnings reported in the first half of 2006, $1.1 million lower contribution due to the disposition and lower volumes and prices related to the operation of the oil and gas production assets and $0.5 million due to higher gas costs to supply a natural gas contract. Oil and natural gas production net revenue in the first half of 2007 was $2.7 million compared to $3.8 million in the same period in 2006, reflecting lower oil and natural gas production ($0.8 million) and lower natural gas prices ($0.3 million).

Operating and administrative expense for the Energy Services segment in the first half of 2007 was $8.6 million compared to $9.1 million for the same period in 2006. The decrease was primarily due to lower activity in the energy management business and lower costs related to the operation of the oil and natural gas production assets. Operating and administrative expense for the oil and natural gas production assets was $1.6 million compared to $1.7 million for the same period in 2006.

Amortization expense in the first half of 2007 was $2.2 million compared to $2.4 million in the same period in 2006. The decrease was primarily due to the sale of oil and natural gas production assets. Amortization expense included $1.2 million in the first half of 2007 compared to $1.5 million in the same period in 2006 related to oil and natural gas production assets.

Operating income as a percentage of net revenue increased to 17 percent in second quarter 2007 compared to 8 percent in the same period in 2006 as a result of the one-time gain on sale of oil and natural gas production assets.

Excluding the one-time gain, operating income as a percentage of net revenue was 6 percent in the first half of 2007 compared to 8 percent in the first half of 2006, due to lower earnings from non-recurring opportunities in the energy management business reported in the first half of 2006, partially offset by stronger earnings from the gas services business. (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 to be lower than 2006 results. The Trust expects continued growth in the energy management business based on continued expansion into electricity supply management in Ontario and a focused national accounts strategy in specific targeted sectors. The growth is expected to be offset by non-recurring earnings realized in 2006 which will continue to affect the Energy Management business through the balance of 2007.

The gas services 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 growth is expected to be offset by lower revenues resulting from higher gas costs related to a natural gas supply contract.

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.

Results in the remainder of 2007 will also be positively impacted by the disposition of the oil and natural gas production assets. For the period June to December 2006, AltaGas reported an operating loss of $0.2 million from these assets.

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 Six Months
Ended June 30 Ended June 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue(1) 0.7 0.2 2.7 2.3
Net revenue 1.1 0.2 3.2 2.3
Operating and administrative 6.9 6.0 14.6 11.2
Amortization 0.5 0.5 1.1 1.1
Operating loss (6.3) (6.3) (12.5) (10.0)
Operating loss before unrealized gains
(losses) on risk management (6.7) (6.3) (13.0) (10.0)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

 


Three Months Ended June 30

The operating loss before unrealized gains on risk management in second quarter 2007 was $6.7 million compared to $6.3 million for the same period in 2006. The increase was primarily due to higher compensation costs of $0.3 million and $1.4 million lower costs allocated to the operating segments, partially offset by $0.4 million related to equity income adjustments. The unrealized gain reported as a result of the accounting for the change in fair value of natural gas marketing contracts was $0.4 million. Effective for 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 on the operating loss this quarter as a result of changing the method of accounting from the equity method to the cost method was negligible.

Revenue in second quarter 2007 was $0.7 million compared to $0.2 million for the same period in 2006 due to a one-time adjustment relating to first quarter 2007 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 second quarter 2007 the fair value of financial instruments increased by $2.6 million of which $0.4 million was recorded as an operating gain and the balance a $2.6 million increase in other comprehensive income. At June 30, 2007 AltaGas recorded financial instrument related assets and liabilities of $135.6 million and $147.5 million respectively.

Operating and administrative expense for second quarter 2007 was $6.9 million compared to $6.0 million in the same quarter in 2006. The increase was primarily related to $1.4 million lower costs allocated to the operating segments and to $0.3 million higher compensation costs, partially offset by $0.6 million lower general corporate overhead related to lower consulting fees.

Amortization expense for second quarter 2007 remained flat at $0.5 million compared to the same period in 2006.

Six Months Ended June 30

The operating loss before unrealized gains on risk management in the first half of 2007 was $13.0 million compared to $10.0 million for the same period in 2006. The increase was primarily due to higher compensation costs and lower costs allocated to the operating segments, partially offset by a one-time gain from unwinding interest rate swaps as a result of the issue of $100 million of medium-term notes (MTNs) in January 2007. Effective for second quarter 2007 AltaGas reduced its influence over 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 first half of 2007 was negligible.

Revenue in the first half of 2007 was $2.7 million compared to $2.3 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.

Effective January 1, 2007 AltaGas adopted accounting standards that require the fair value of all financial instruments to be reflected on the financial statements. In the first half of 2007 the fair value of financial instruments increased by $2.4 million of which $0.5 million was recorded as an operating gain and the balance a $2.9 million increase in other comprehensive income.

Operating and administrative expense for the first half of 2007 was $14.6 million compared to $11.2 million in the same period in 2006. The increase was primarily related to higher compensation costs ($2.0 million) and $2.0 million lower costs allocated to the operating segments partially offset by lower general corporate overhead.

Amortization expense for the first half of 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, higher amortization costs related to increased investments in technology to support the growth of the Trust and lower costs allocated to the operating segments.

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 second quarter 2007 AltaGas increased its capital assets, long-term investments and other assets by $22.8 million compared to $15.2 million in second quarter 2006. The increase was due to $11.9 million in non-monetary consideration received including a $11.6 million promissory note recorded in long-term investments and other assets for the sale of oil and natural gas production assets in May 2007 as well as acquiring an additional $11.1 million in capital assets. Of the $30.3 million disposals of capital assets in the second quarter 2007, $30.2 million was from the disposition of the oil and natural gas production assets in the Energy Services segment.

During the first six months of 2007, the increase in capital assets, long-term investments and other assets was $29.8 million compared to $33.7 million for the same period in 2006. The increase in the second half of 2007 was due to the non-monetary consideration of $11.9 million recorded in long-term investments and other assets and capital acquisitions of $17.8 million. The $31.8 million of disposals included the $30.2 million disposition of the oil and natural gas production assets in Energy Services.



Net Invested Capital - Investment Three Months Ended
Type June 30, 2007
Field
Gathering Extraction
and and Power Energy
($ millions) Processing Transmission Generation Services Corporate Total
----------------------------------------------------------------------------
Invested capital:
Capital assets 5.0 1.7 3.9 0.1 0.4 11.1
Long-term
investments
and other
assets - - 0.3 - 11.4 11.7
----------------------------------------------------------------------------
5.0 1.7 4.2 0.1 11.8 22.8
Disposals:
Capital assets (0.1) - - (30.2) - (30.3)
----------------------------------------------------------------------------
Net invested
capital 4.9 1.7 4.2 (30.1) 11.8 (7.5)
----------------------------------------------------------------------------
----------------------------------------------------------------------------



Net Invested Capital - Investment Six Months Ended
Type June 30, 2007
Field
Gathering Extraction
and and Power Energy
($ millions) Processing Transmission Generation Services Corporate Total
----------------------------------------------------------------------------
Invested capital:
Capital assets 8.2 4.1 3.9 0.6 1.0 17.8
Long-term
investments
and other
assets - - 0.5 - 11.5 12.0
----------------------------------------------------------------------------
8.2 4.1 4.4 0.6 12.5 29.8
Disposals:
Capital assets (1.3) (0.3) - (30.2) - (31.8)
----------------------------------------------------------------------------
Net invested
capital 6.9 3.8 4.4 (29.6) 12.5 (2.0)
----------------------------------------------------------------------------
----------------------------------------------------------------------------



Net Invested Capital - Investment Three Months Ended
Type June 30, 2006
Field
Gathering Extraction
and and Power Energy
($ millions) Processing Transmission Generation Services Corporate Total
----------------------------------------------------------------------------
Invested capital:
Capital assets 13.1 0.3 0.1 0.2 (0.1) 13.6
Energy services
arrangements,
contracts and
relationships - - 0.4 - - 0.4
Long-term
investments and
other assets - - 1.7 - (0.5) 1.2
----------------------------------------------------------------------------
13.1 0.3 2.2 0.2 (0.6) 15.2

Disposals:
Capital assets (0.2) - - - - (0.2)
----------------------------------------------------------------------------
Net invested
capital 12.9 0.3 2.2 0.2 (0.6) 15.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------



Net Invested Capital - Investment Six Months Ended
Type June 30, 2006
Field
Gathering Extraction
and and Power Energy
($ millions) Processing Transmission Generation Services Corporate Total
----------------------------------------------------------------------------
Invested capital:
Capital assets 28.1 0.7 1.3 0.4 0.4 30.9
Energy services
arrangements,
contracts and
relationships - - 0.4 - - 0.4
Long-term
investments
and other
assests - - 1.7 - 0.7 2.4
----------------------------------------------------------------------------
28.1 0.7 3.4 0.4 1.1 33.7
Disposals:
Capital assets (0.5) - - - - (0.5)
----------------------------------------------------------------------------
Net invested
capital 27.6 0.7 3.4 0.4 1.1 33.2
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


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

Maintenance capital projects totaling $2.1 million in second quarter 2007 (second quarter 2006 - $1.6 million) were undertaken in the FG&P and E&T segments. Of the $8.1 million (second quarter 2006 - $13.0 million) of growth capital spent in second quarter 2007, $3.9 million was in relation to the acquisition of new peaking generation equipment in the Power Generation segment. In the FG&P segment, $1.8 million was due to the expansion of existing facilities and $1.3 million was spent on the Noel pipeline and Pouce Coupe plant expansion project announced on April 10, 2007. In the E&T segment, growth capital of $1.2 million related primarily to the expansion of the Cold Lake transmission system. Of the $12.6 million spent on administrative capital, $11.9 million was due to the non-monetary consideration received from the sale of oil and natural gas production assets and an additional $0.7 million was spent on computer hardware and software projects.

Maintenance capital projects totaling $3.3 million in the first half of 2007 (first half of 2006 - $3.2 million) were primarily undertaken in the FG&P segment. Of the $12.7 million in growth capital spent in the first half of 2007 (first half of 2006 - $29.3 million), $3.9 million was primarily due to the expansions at the Shaunavon, Sylvan Lake, Acadia Valley and Princess facilities, and $1.3 million was due to the Noel pipeline and Pouce Coupe plant expansion project in the FG&P segment. In the Power Generation segment, $3.9 million was spent on the new peaking generation equipment. In the E&T segment, $3.4 million was spent primarily on the expansion of the Cold Lake transmission system and the ethane enhancement recovery project at the Edmonton ethane extraction facility. Administrative capital included the $11.9 million non-monetary consideration received for the sale of oil and natural gas production assets and $1.9 million was primarily spent on computer hardware and software projects.



Invested Capital - Use Three Months Ended
June 30, 2007
Field
Gathering Extraction
and and Power Energy
($ millions) Processing Transmission Generation Services Corporate Total
----------------------------------------------------------------------------
Invested capital:
Maintenance 1.6 0.5 - - - 2.1
Growth 3.1 1.2 4.2 0.1 (0.5) 8.1
Administrative 0.3 - - - 12.3 12.6
----------------------------------------------------------------------------
Invested capital 5.0 1.7 4.2 0.1 11.8 22.8
----------------------------------------------------------------------------
----------------------------------------------------------------------------



Invested Capital - Use Six Months Ended
June 30, 2007
Field
Gathering Extraction
and and Power Energy
($ millions) Processing Transmission Generation Services Corporate Total
----------------------------------------------------------------------------
Invested capital:
Maintenance 2.6 0.7 - - - 3.3
Growth 5.2 3.4 4.4 0.1 (0.4) 12.7
Administrative 0.4 - - 0.5 12.9 13.8
----------------------------------------------------------------------------
Invested capital 8.2 4.1 4.4 0.6 12.5 29.8
----------------------------------------------------------------------------
----------------------------------------------------------------------------



Invested Capital - Use Three Months Ended
June 30, 2006
Field
Gathering Extraction
and and Power Energy
($ millions) Processing Transmission Generation Services Corporate Total
----------------------------------------------------------------------------
Invested capital:
Maintenance 1.3 0.3 - - - 1.6
Growth 11.8 0.1 2.2 0.2 (1.3) 13.0
Administrative - (0.1) - - 0.7 0.6
----------------------------------------------------------------------------
Invested capital 13.1 0.3 2.2 0.2 (0.6) 15.2
----------------------------------------------------------------------------
----------------------------------------------------------------------------



Invested Capital - Use Six Months Ended
June 30, 2006
Field
Gathering Extraction
and and Power Energy
($ millions) Processing Transmission Generation Services Corporate Total
----------------------------------------------------------------------------
Invested capital:
Maintenance 2.6 0.5 - 0.1 - 3.2
Growth 25.5 0.2 3.4 0.2 - 29.3
Administrative - - - 0.1 1.1 1.2
----------------------------------------------------------------------------
Invested
capital 28.1 0.7 3.4 0.4 1.1 33.7
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


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 June 30, 2007, the Trust had positions in the following types of derivatives:

- Commodity forward contracts: The Trust executes gas and power 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. 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 $0.00/MWh to $738.60/MWh in second quarter 2007, the average spot price for the quarter was $49.97. AltaGas moderated the impact of this volatility on its business through the use of financial hedges on a portion of its 2007 power portfolio that management deemed optimal. The average price received for power sales by the Trust in second quarter 2007 was $62.62/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 June 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 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 June 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 Six Months
Ended June 30 Ended June 30
($ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Cash from operations 46.6 43.8 92.7 69.5
Investing activities (16.1) (23.4) (27.0) (45.9)
Financing activities (40.6) (20.1) (66.6) (24.3)
----------------------------------------------------------------------------
Change in cash (10.1) 0.3 (0.9) (0.7)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Cash from Operations

Cash from operations reported on the Consolidated Statements of Cash Flows increased 6 percent to $46.6 million in second quarter 2007, from $43.8 million in same period in 2006. The increase was due to stronger operating results.

There was a working capital deficit of $1.1 million at the end of second quarter 2007 compared to a surplus of $19.2 million at the end of second quarter 2006 and a surplus of $23.7 million as at December 31, 2006. The risk management activities accounted for $16.2 million of the difference in working capital between second quarter 2007 and second quarter 2006.



Working Capital June 30 December 31
($ millions) 2007 2006
----------------------------------------------------------------------------
Current assets 264.7 263.4
Current liabilities 265.8 239.7
----------------------------------------------------------------------------
Working capital (1.1) 23.7
Current ratio 1.0 1.1
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Investing Activities

During second quarter 2007 the Trust used cash for investing activities of $16.1 million compared to $23.4 million for the same period in 2006. Acquisition of capital assets and long-term investments and other assets totaled $10.3 million in second quarter 2007 compared to $17.7 million in second quarter 2006. Investing activities for the six months ended June 30, 2007 was $27.0 million compared to $45.9 million in the same period in 2007. Cash used for the acquisition of capital assets and long-term and other assets for the first half of 2007 was $21.7 million compared to $42.9 million in the same period 2006.

Financing Activities

Cash used for financing activities in second quarter 2007 was $40.6 million compared to $20.1 million for the same quarter last year. The increase was due to greater reduction in debt balances and higher distributions to unitholders offset by higher proceeds from unit issuances. For the six months ended June 30, 2007 cash used for financing activities was $66.6 million compared to $24.3 million for the same period in 2006. The increase was due to a reduction of long-term debt during the first half of 2007 compared to an increase in long-term debt for the same period in 2006 and higher distributions to unitholders, offset by higher proceeds from the issuance of units and an increase in short-term debt. The higher reduction in long-term debt in 2007 compared to 2006 was primarily a result of higher cash from operations.

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 June 30, 2007 AltaGas had total debt outstanding of $229.7 million, down from $265.5 million as at December 31, 2006. At June 30, 2007 the Trust had $200 million in MTNs outstanding and had access to prime loans, bankers' acceptances and letters of credit through bank lines totaling $425.0 million. At June 30, 2007 the Trust had drawn bank debt of $216.8 million and letters of credit outstanding of $72.2 million.

In first quarter 2007 the Trust recorded a $1.1 million reduction in its long-term debt as a result of adopting the new financial instrument standards. The reduction reflected the reclassification of deferred debt charges against long-term debt which were previously recorded in Other current assets and in Long-term investments and other assets on the Trust's balance sheet.

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 June 30, 2007 was 30.0 percent, down from 33.4 percent at December 31, 2006. The Trust's earnings interest coverage for the rolling 12 months ended June 30, 2007 was 9.89 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. In December 2006 DBRS confirmed AltaGas' MTN and stability ratings at BBB (low) and STA 3 (middle) respectively and changed the trend on the MTN rating to Positive from Stable.

Standard & 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-. In January 2007 S&P affirmed AltaGas' ratings.

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

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 second quarter 2007 the Trust sold $13.4 million of natural gas and provided $0.1 million of operating services to Utility Group. In addition, the Trust paid management fees of $0.1 million and transportation costs of $0.1 million to Utility Group over the same period. In addition, the Trust received management fees of $7,500 from the Utility group for administrative services.

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 second quarter 2007 (second quarter 2006 - $21,163). The five-year lease expires at the end of 2007 and is renewable at the option of AltaGas for another three years. (See note 11 of the interim Consolidated Financial Statements.)

SUMMARY OF CONSOLIDATED RESULTS FOR THE EIGHT MOST RECENT QUARTERS



($ millions) Q2-07 Q1-07 Q4-06 Q3-06 Q2-06 Q1-06 Q4-05 Q3-05
----------------------------------------------------------------------------
Net revenue(1) 80.1 79.3 84.6 82.5 72.8 79.1 78.7 71.3
Operating income(1) 31.2 29.0 32.0 33.7 26.0 35.0 29.0 22.9
Net income 13.1 24.6 27.3 28.8 29.9 28.6 26.4 17.2
----------------------------------------------------------------------------
----------------------------------------------------------------------------

($ per unit) Q2-07 Q1-07 Q4-06 Q3-06 Q2-06 Q1-06 Q4-05 Q3-05
----------------------------------------------------------------------------
Net income
Basic 0.23 0.43 0.49 0.52 0.54 0.52 0.48 0.32
Diluted 0.23 0.43 0.49 0.52 0.54 0.52 0.48 0.32
Distributions declared(2) 0.51 0.51 0.51 0.505 0.495 0.485 0.48 0.47
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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.

 


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 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;

- Strong power prices, higher frac spreads and lower interest expense in all quarters in 2006 resulted in strong financial results in all quarters, partially offset by the contribution from the NGD segment in first quarter 2005 which was spun out in November 2005;

- 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 $14.5 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.

SUBSEQUENT EVENTS

- 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 on July 17, 2007. Responses to the bids are expected in September 2007.

- AltaGas expects to file a final short-form base shelf prospectus to facilitate the issuance of trust units or unsecured debt securities on August 8, 2007. This shelf has a 25-month life and permits the Trust to issue up to an aggregate of $500 million of securities.

- AltaGas signed an agreement to sell its 33.3335 percent interest in the Ikhil Joint Venture to AltaGas Utility Group Inc. for $9 million. No gain or loss is expected to result from the sale, which is effective July 1, 2007 and is subject to normal regulatory approvals.

- 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 will remain in effect and will continue 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 signed an agreement to purchase a 50 percent interest in the Sarnia Airport Pool Storage Project. Once developed, the Sarnia Airport Pool 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.

- Bear Mountain Wind Limited Partnership, a partnership in which AltaGas owned 50 percent, signed agreements with AltaGas, Aeolis and Peace to exchange their equity interests in BMWLP for a royalty agreement pursuant to which Aeolis and Peace will receive royalty payments. AltaGas has also agreed to repay Aeolis' loans of approximately $1.0 million that it made to BMWLP to fund its share of development costs incurred to date. These loan repayments, 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.

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 June 30, 2007 the Trust had 55,405,742 trust units and 2,076,606 exchangeable units outstanding and a market capitalization of $1.5 billion based on a closing trading price on June 29, 2007 of $25.51 per trust unit. At June 30, 2007 there were 1,080,650 options outstanding and 161,525 options exercisable under the terms of the unit option plan.

DISTRIBUTIONS

AltaGas' distributions are determined giving consideration to the ongoing sustainable distributable cash flow as impacted by the consolidated net income, maintenance and growth capital and debt repayment requirements of the Trust. In second quarter 2007, the Trust declared distributions of $29.2 million compared to $27.4 million in second quarter 2006. The Trust's distributable cash in second quarter 2007 was $37.1 million compared to $34.1 million in the same period last year and was more than sufficient to fund all distributions to unitholders. The Trust targets to pay substantially all of its ongoing sustainable distributable cash through regular monthly distributions made to unitholders. (See Non-GAAP Financial Measures in this MD&A.)

In the six months ended June 30, 2007 the Trust declared distributions of $58.2 million compared to $54.0 million in the same period in 2006. The Trust's distributable cash in the six months ended June 30, 2007 was $74.1 million compared to $73.5 million in the same period last year and was more than sufficient to fund all distributions to unitholders.

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 is AltaGas' fourth distribution increase since converting to a trust in May 2004. AltaGas' total distributions declared in the second quarter of 2007 were $0.51 per unit.

In addition, a special distribution of one AltaGas Utility Group Inc. (Utility Group) common share for every 100 trust units and exchangeable units of AltaGas held on August 27, 2007 will be made on September 17, 2007. As part of the distribution plan, any Trust unitholder allocated fewer than 50 common shares of Utility Group will receive cash. The cash received by Trust unitholders will be based on the proceeds received by Computershare Trust Company of Canada on sale of the Utility Group shares.



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 - 0.505 0.47
Fourth quarter - 0.510 0.48
Distribution of shares(1) - - 0.54
----------------------------------------------------------------------------
1.02 1.995 2.39
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) 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 in first quarter 2007.

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 six months ended June 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 six months ended June 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 six months ended June 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 six months ended June 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 second quarter 2007 there were no material changes to the Trust's internal controls over financial reporting.



Consolidated Balance Sheets
(unaudited)
June 30 December 31
($ thousands) 2007 2006
----------------------------------------------------------------------------

ASSETS
Current assets
Cash and cash equivalents $ 12,309 $ 13,226
Accounts receivable 157,699 224,533
Inventory 111 61
Customer deposits 22,487 16,304
Risk management (note 4) 69,120 -
Other 2,981 9,277
----------------------------------------------------------------------------
264,707 263,401
Capital assets 660,427 677,941
Energy service arrangements, contracts and
relationships 99,523 103,330
Goodwill 18,260 18,260
Risk management (note 4) 66,488 -
Long-term investments and other assets 70,156 46,643
----------------------------------------------------------------------------
$ 1,179,561 $ 1,109,575
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities $ 138,225 $ 200,882
Distributions payable to unitholders 9,772 9,588
Short-term debt 1,845 -
Current portion of long-term debt 1,192 1,147
Customer deposits 22,487 16,304
Deferred revenue 1,211 788
Risk management (note 4) 85,318 -
Other 5,726 10,982
----------------------------------------------------------------------------
265,776 239,691
Long-term debt 226,663 264,340
Asset retirement obligations 20,317 23,350
Future income taxes (note 5) 59,217 51,252
Risk management (note 4) 69,747 -
Other long-term liabilities 1,962 1,526
----------------------------------------------------------------------------
643,682 580,159
Unitholders' equity (notes 6 and 7) 535,879 529,416
----------------------------------------------------------------------------
$ 1,179,561 $ 1,109,575
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the Consolidated Financial Statements.


Consolidated Statements of Income and Accumulated Earnings
(unaudited)

Three months ended Six months ended
($ thousands except per June 30 June 30
unit amounts and number of units) 2007 2006 2007 2006
----------------------------------------------------------------------------

REVENUE
Operating $ 340,634 $ 299,434 $ 766,676 $ 675,138
Unrealized gains on risk
management 413 - 475 -
Other 731 188 2,692 2,222
----------------------------------------------------------------------------
341,778 299,622 769,843 677,360
----------------------------------------------------------------------------

EXPENSES
Cost of sales 261,682 226,802 610,455 525,440
Operating and administrative 37,014 35,468 75,075 68,487
Amortization 11,854 11,424 24,046 22,540
----------------------------------------------------------------------------
310,550 273,694 709,576 616,467
----------------------------------------------------------------------------
Operating income 31,228 25,928 60,267 60,893
Interest expense
Short-term debt 88 122 148 230
Long-term debt 2,960 3,253 5,976 6,436
----------------------------------------------------------------------------
Income before income taxes 28,180 22,553 54,143 54,227
Income tax expense (recovery) 15,127 (7,351) 16,510 (4,237)
----------------------------------------------------------------------------
Net income 13,053 29,904 37,633 58,464
Accumulated earnings, beginning of
period 426,198 315,667 401,618 287,107
----------------------------------------------------------------------------
Accumulated earnings, end
of period $ 439,251 $ 345,571 $ 439,251 $ 345,571
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net income per unit (note 7)
Basic $ 0.23 $ 0.54 $ 0.66 $ 1.06
Diluted $ 0.23 $ 0.54 $ 0.66 $ 1.06

Weighted average number of
units outstanding (thousands)
(note 7)
Basic 57,199 55,206 56,931 55,009
Diluted 57,235 55,315 56,966 55,116

See accompanying notes to the Consolidated Financial Statements.


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

Three Six
months ended months ended
June 30 June 30
($ thousands) 2007 2007
----------------------------------------------------------------------------

Net income $ 13,053 $ 37,633

Other comprehensive income, net of tax (note 4)
Unrealized net gains on available for sale
financial assets 10,383 10,399
Unrealized net loss on derivative designated as
cash flow hedges (4,570) (4,086)
Reclassification to net income of net loss on
derivatives designated as cash flow hedges
pertaining to prior periods (3,170) (3,389)
----------------------------------------------------------------------------
2,643 2,924
----------------------------------------------------------------------------
Comprehensive income $ 15,696 $ 40,557
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Accumulated other comprehensive loss, beginning
of period $ (2,353) -
Adjustment resulting from adoption of new
financial instrument accounting standards
(note 2) - (2,634)
Other comprehensive income, net of tax 2,643 2,924
----------------------------------------------------------------------------
Accumulated other comprehensive income, end of
period $ 290 $ 290
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the Consolidated Financial Statements.


Consolidated Statements of Cash Flows
(unaudited)

Three months ended Six months ended
June 30 June 30
($ thousands) 2007 2006 2007 2006
----------------------------------------------------------------------------
Cash from operations
Net income $ 13,053 $ 29,904 $ 37,633 $ 58,464
Items not involving cash:
Amortization 11,854 11,424 24,046 22,540
Accretion of asset retirement
obligations 424 345 850 687
Unit-based compensation 157 18 331 34
Future income tax expense
(recovery) 15,127 (7,016) 16,510 (4,251)
Gain on sale of assets (note 8) (1,490) - (1,563) -
Equity income (317) (118) (1,693) (2,045)
Distribution from equity
investments 503 725 1,258 1,450
Unrealized gains on risk
management (413) - (475) -
Other 300 444 547 (162)
----------------------------------------------------------------------------
Funds from operations 39,198 35,726 77,444 76,717
Asset retirement obligations
settled (20) (2) (140) (42)
Net change in non-cash working
capital (note 9) 7,397 8,119 15,396 (7,174)
----------------------------------------------------------------------------
46,575 43,843 92,700 69,501
----------------------------------------------------------------------------

Investing activities
Increase in customer deposits (6,287) (5,448) (6,183) (2,988)
Acquisition of capital assets (9,875) (15,867) (20,888) (41,000)
Disposition of capital assets 90 149 507 328
Acquisition of energy services
arrangements, contracts and
relationships - (367) - (384)
Acquisition of long-term
investments and other assets (420) (1,876) (799) (1,876)
Disposition of long-term investments
and other assets 375 - 375 -
----------------------------------------------------------------------------
(16,117) (23,409) (26,988) (45,920)
----------------------------------------------------------------------------

Financing activities
Increase (decrease) in
short-term debt (5,655) (7) 1,845 (2,710)
Increase (decrease) in long-term
debt (19,894) (4,544) (37,113) 10,867
Distributions to unitholders (28,959) (27,291) (57,810) (53,571)
Net proceeds from issuance of
units (note 7) 13,979 11,672 26,449 21,090
----------------------------------------------------------------------------
(40,529) (20,170) (66,629) (24,324)
----------------------------------------------------------------------------
Change in cash and cash equivalents (10,071) 264 (917) (743)
Cash and cash equivalents,
beginning of period 22,380 10,678 13,226 11,685
----------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 12,309 $ 10,942 $ 12,309 $ 10,942
----------------------------------------------------------------------------

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.

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 June 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 Other comprehensive income (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 10.5 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 6.)



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 5-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. 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 June 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 June 30, 2007 the fair value of the Trust's assets and liabilities was
as follows:

Summary of Fair Values

($ millions) Current Long-term Total
----------------------------------------------------------------------------
Financial assets
Held for trading $ 64,921 $ 60,908 $ 125,829
Available for sale - 36,258 36,258
Loans and receivables 131,243 12,643 143,886
----------------------------------------------------------------------------
196,164 109,809 305,973
Cash flow hedges 4,199 5,581 9,780
----------------------------------------------------------------------------
$ 200,363 $ 115,390 $ 315,753
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Financial liabilities
Held for trading $ 65,820 $ 64,249 $ 130,069
Other financial liabilities 113,529 218,221 331,750
----------------------------------------------------------------------------
179,349 282,470 461,819
Cash flow hedges 19,498 5,498 24,996
----------------------------------------------------------------------------
$ 198,847 $ 287,968 $ 486,815
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Unrealized income

The impact on net income from the adoption of the new financial instruments resulted in a negligible unrealized loss in second quarter 2007 and an unrealized loss of $0.5 million for the six months ended June 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 gain of $3.2 million was reclassified to net income in second quarter 2007 and a $3.4 million after-tax unrealized gain was reclassified to net income in the first half of 2007. Of the $0.3 million gain deferred in Accumulated other comprehensive income at June 30, 2007, $10.4 million is expected to be reclassified to net income in the next 12 months because the long-term amounts deferred in Other comprehensive income are comprised of unrealized gains.

The available for sale assets, included in the balance sheet captions Long-term investments and other assets, are recognized at fair value, net of tax, in Other comprehensive income. In second quarter and the first half of 2007, the fair value, net of tax, increased by $10.4 million. The 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 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 second quarter and the first six months of 2007 the charge to Net income for the amortization of transaction costs using the effective interest 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 2011.



At June 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 to 45 111,028,890 - $(36,264)
Commodity
forward $2.16 to $10.37 1 to 45 - 111,028,890 $ 32,069
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

 


For second quarter 2007, an after-tax gain of $0.2 million was recognized from the Trust's natural gas risk management activities, and an after-tax loss of $0.1 million was recognized in the first half of 2007.

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 June 30, 2007 the Trust had no intention to terminate any contracts prior to maturity.



At June 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
forward $52.50 to $69.50 1 to 12 4,368 - $ (134)
Commodity
forward $55.50 to $69.50 1 to 12 - 4,368 $ 113
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


The Trust's power risk management activities from financial contracts not included in the hedging program had an unrealized loss of $0.1 million for the second quarter 2007 and an unrealized loss of $0.1 million for the first half of 2007.



At June 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
collars $65.00 to $84.25 3 to 18 1,922,760 - $(21,725)
Swaps and
collars $56.50 to $65.00 3 to 126 - 387,336 $ 6,157
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


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 second quarter 2007 the Trust's foreign exchange risk management activities had an unrealized loss of $0.1 million and an unrealized loss for the first half of 2007 of $0.4 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 second 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 $0.2 million for second quarter 2007 and an unrealized gain of $0.5 million in first half of 2007. These swaps had a fair market value position of $0.5 million at June 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 June 30, 2007 AltaGas did not have a significant concentration of credit risk with any single counterparty to financial instruments.

5. 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 $14.5 million and increased its future income tax liability in second quarter 2007. 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.



6. UNITHOLDERS' EQUITY

June 30 December 31
2007 2006
----------------------------------------------------------------------------
Unitholders' capital (note 7) $ 490,199 $ 463,750
Contributed surplus 3,654 3,322
Accumulated earnings 439,251 401,618
Accumulated dividends (41,114) (41,114)
Accumulated unitholders' distributions declared(1) (330,458) (272,464)
Distributions of common shares of AltaGas Utility
Group Inc. (25,696) (25,696)
Transition adjustment resulting from adopting new
financial instruments accounting standards (247) -
Accumulated other comprehensive loss
(notes 2 and 4) 290 -
----------------------------------------------------------------------------
$ 535,879 $ 529,416
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Accumulated distributions paid by the Trust as at June 30, 2007 were
$320.7 million (as at December 31, 2006 - $262.9 million).


7. 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 1,400 32
Units issued under DRIP(1) 1,078,582 26,417
Units issued for exchangeable units 12,208 72
----------------------------------------------------------------------------
June 30, 2007 55,405,742 $ 478,316
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 (12,208) (72)
----------------------------------------------------------------------------
June 30, 2007 2,076,606 $ 11,883
----------------------------------------------------------------------------
Total Trust Units and Exchangeable Units at
June 30, 2007 57,482,348 $ 490,199
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


Units Outstanding(1)
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Number of units - Basic(2) 57,199,103 55,205,618 56,931,021 55,009,333
Dilutive stock options 36,233 109,097 34,715 107,002
----------------------------------------------------------------------------
Number of units - Diluted(2) 57,235,336 55,314,715 56,965,736 55,116,335
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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 June 30, 2007 10 percent of units outstanding were reserved for issuance under the plan. To June 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 June 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 $26.80 (December 31, 2006 - $27.23) and a weighted average remaining term of 9.17 years (December 31, 2006 - 9.23 years). At June 30, 2007 the unexpensed fair value of unit option compensation cost associated with future periods was $0.8 million (December 31, 2006 - $0.9 million).



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

Number Exercise
of options price(1)
----------------------------------------------------------------------------
Unit options outstanding, December 31, 2006 923,550 $ 27.23
Granted 247,500 25.62
Exercised (1,400) 20.71
Cancelled (89,000) 27.98
----------------------------------------------------------------------------
Unit options outstanding, June 30, 2007 1,080,650 $ 26.80
----------------------------------------------------------------------------
Unit options exercisable, June 30, 2007 161,525 $ 22.64
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Weighted average.


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

Options Outstanding Options Exercisable
--------------------------------------------------------------

Range of Remaining
Exercise Price Number Exercise contractual Number Exercise
on Options outstanding(1) price(2) life(3) exercisable(1) price(2)
----------------------------------------------------------------------------
$5.00-$7.00 9,500 $ 6.15 3.18 9,500 $ 6.15
$7.01-$15.50 28,500 10.26 5.91 28,500 10.26
$15.51-$25.08 118,400 24.17 8.49 37,900 24.27
$25.09-$29.15 924,250 27.86 9.47 85,625 27.87
----------------------------------------------------------------------------
1,080,650 $ 26.80 9.17 161,525 $ 22.64
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) As of June 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 second quarter 2007 in respect of this plan was $1.0 million (second quarter 2006 - $1.7 million) and $2.7 million in the six months ended June 30, 2007 (first half of 2006 - $3.4 million). At June 30, 2007 the unexpensed fair value of unit-based compensation costs related to the phantom units was $8.8 million (December 31, 2006 - $9.9 million).

8. GAIN ON SALE OF ASSETS

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 of the asset retirement obligation of $3.1 million and a future income tax recovery of $0.6 million.

9. NET CHANGE IN NON-CASH WORKING CAPITAL

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



Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Accounts receivable $ 34,605 $ 20,877 $ 66,834 $ 80,172
Inventory - 11 (50) 34
Other current assets (482) 1,333 6,296 578
Accounts payable and accrued
liabilities (31,959) (22,214) (62,657) (96,434)
Customer deposits 6,287 5,448 6,183 2,988
Deferred revenue 225 - 423 -
Other current liabilities 337 375 (5,256) (4,541)
----------------------------------------------------------------------------
9,013 5,830 11,773 (17,203)
Less: change in capital costs
included in accounts payable (1,616) 2,289 3,623 10,029
----------------------------------------------------------------------------
$ 7,397 $ 8,119 $ 15,396 $ (7,174)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Interest paid $ 3,134 $ 3,461 $ 6,253 $ 6,955
Income taxes paid $ 15 $ 1 $ 96 $ 47
----------------------------------------------------------------------------
----------------------------------------------------------------------------


10. PENSION PLANS AND RETIREMENT BENEFITS

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

Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Defined contribution plan $ 383 $ 329 $ 765 $ 651
Defined benefit plan 3 5 6 8
Supplemental executive
retirement plan 259 393 518 393
----------------------------------------------------------------------------
$ 645 $ 727 $ 1,289 $ 1,052
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


11. 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 Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Fees for administration, management
and other services paid by:
AltaGas Utility Group Inc.
(Utility Group) to the Trust $ 7 $ 180 $ 15 $ 258
The Trust to Utility Group $ 127 $ 102 $ 265 $ 235
Natural gas sales by the Trust to
Utility Group subsidiaries $ 13,428 $ 9,360 $ 52,344 $ 47,458
Fees for operating services paid
by a Utility Group subsidiary $ 77 - $ 143 -
Transportation services provided
by a Utility Group subsidiary $ 119 $ 141 $ 243 $ 284
Office space and furniture rental
payments made by the Trust to a
corporation owned by an employee $ 21 $ 21 $ 42 $ 54
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


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

Included in accounts receivable at June 30, 2007 was $2.3 million (June 30, 2006 - $2.3 million) due to the Trust from related parties. Included in accounts payable at June 30, 2007 was $0.1 million (June 30, 2006 - $0.8 million) due from the Trust to related parties.

12. 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 oil and natural gas production; 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
June 30, 2007

Field
Gathering Extraction
and and Power Energy
Processing Transmission Generation Services
----------------------------------------------------------------------------
Revenue $ 36,811 $ 33,652 $ 40,691 $ 248,574
Unrealized gains (losses)
on risk management - - - -
Cost of sales (1,961) (18,387) (17,760) (241,627)
Operating and administrative (22,009) (4,435) (466) (4,327)
Amortization (6,459) (2,006) (1,860) (961)
----------------------------------------------------------------------------
Operating income $ 6,382 $ 8,824 $ 20,605 $ 1,659
Operating income before
unrealized gains (losses)
on risk management $ 6,382 $ 8,824 $ 20,605 $ 1,659
----------------------------------------------------------------------------
Net additions (reductions) to:
Capital assets $ 4,930 $ 1,639 $ 3,897 $ (30,104)
Long-term investment and
other assets - - $ 324 -
----------------------------------------------------------------------------
Goodwill $ 215 $ 18,045 - -
Segmented assets $ 508,133 $ 237,419 $ 121,661 $ 99,737
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Intersegment
Corporate Elimination Total
----------------------------------------------------------------------------
Revenue $ 731 $ (19,094) $ 341,365
Unrealized gains (losses) on
risk management 413 - 413
Cost of sales - 18,053 (261,682)
Operating and administrative (6,818) 1,041 (37,014)
Amortization (568) - (11,854)
----------------------------------------------------------------------------
Operating income $ (6,242) - $ 31,228
Operating income before unrealized gains
(losses) on risk management $ (6,655) - $ 30,815
----------------------------------------------------------------------------
Net additions (reductions) to:
Capital assets $ 454 - $ (19,184)
Long-term investment and other assets $ 11,404 - $ 11,728
----------------------------------------------------------------------------
Goodwill - - $ 18,260
Segmented assets $ 212,611 - $1,179,561
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Six Months Ended
June 30, 2007

Field
Gathering Extraction
and and Power Energy
Processing Transmission Generation Services
----------------------------------------------------------------------------
Revenue $ 70,041 $ 70,973 $ 84,984 $ 584,158
Unrealized gains (losses)
on risk management - - - -
Cost of sales (3,580) (39,881) (37,593) (571,167)
Operating and administrative (42,902) (9,781) (921) (8,606)
Amortization (12,979) (4,007) (3,721) (2,203)
----------------------------------------------------------------------------
Operating income $ 10,580 $ 17,304 $ 42,749 $ 2,182
Operating income before
unrealized gains (losses)
on risk management $ 10,580 $ 17,304 $ 42,749 $ 2,182
----------------------------------------------------------------------------
Net additions (reductions) to:
Capital assets $ 6,892 $ 3,744 $ 3,897 $ (29,566)
Long-term investment and
other assets - - $ 478 -
----------------------------------------------------------------------------
Goodwill $ 215 $ 18,045 - -
Segmented assets $ 508,133 $ 237,419 $ 121,661 $ 99,737
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Intersegment
Corporate Elimination Total
----------------------------------------------------------------------------
Revenue $ 2,692 $ (43,480) $ 769,368
Unrealized gains (losses) on risk
management 475 - 475
Cost of sales - 41,766 (610,455)
Operating and administrative (14,579) 1,714 (75,075)
Amortization (1,136) - (24,046)
----------------------------------------------------------------------------
Operating income $ (12,548) - $ 60,267
Operating income before unrealized gains
(losses) on risk management $ (13,023) - $ 59,792
----------------------------------------------------------------------------
Net additions (reductions) to:
Capital assets $ 1,048 - $ (13,985)
Long-term investment and other assets $ 11,476 - $ 11,954
----------------------------------------------------------------------------
Goodwill - - $ 18,260
Segmented assets $ 212,611 - $1,179,561
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Three Months Ended
June 30, 2006

Field
Gathering Extraction
and and Power Energy
Processing Transmission Generation Services
----------------------------------------------------------------------------
Revenue $ 33,481 $ 37,394 $ 39,563 $ 209,687
Cost of sales (2,441) (22,117) (18,832) (203,346)
Operating and administrative (21,174) (3,951) (352) (4,689)
Amortization (5,836) (1,928) (1,827) (1,286)
----------------------------------------------------------------------------
Operating income $ 4,030 $ 9,398 $ 18,552 $ 366
Operating income before
unrealized gains (losses)
on risk management $ 4,030 $ 9,398 $ 18,552 $ 366
----------------------------------------------------------------------------
Net additions (reductions) to:
Capital assets $ 12,974 $ 317 $ 30 $ 211
Energy services arrangements,
contracts and relationships - - $ 421 $ (54)
Long-term investment and
other assets - - $ 1,720 -
----------------------------------------------------------------------------
Goodwill $ 815 $ 18,045 - -
Segmented assets $ 476,292 $ 233,496 $ 121,149 $ 120,326
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Intersegment
Corporate Elimination Total
----------------------------------------------------------------------------
Revenue $ 236 $ (20,739) $ 299,622
Cost of sales - 19,934 (226,802)
Operating and administrative (6,107) 805 (35,468)
Amortization (547) - (11,424)
----------------------------------------------------------------------------
Operating income $ (6,418) - $ 25,928
Operating income before unrealized gains
(losses) on risk management $ (6,418) - $ 25,928
----------------------------------------------------------------------------
Net additions (reductions) to:
Capital assets $ (145) - $ 13,387
Energy services arrangements,
contracts and relationships - - $ 367
Long-term investment and other assets $ (513) - $ 1,207
----------------------------------------------------------------------------
Goodwill - - $ 18,860
Segmented assets $ 49,343 - $1,000,606
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Six Months Ended
June 30, 2006

Field
Gathering Extraction
and and Power Energy
Processing Transmission Generation Services
----------------------------------------------------------------------------
Revenue $ 67,994 $ 73,537 $ 91,242 $ 482,738
Cost of sales (5,060) (43,812) (45,612) (470,291)
Operating and administrative (40,453) (8,164) (670) (9,103)
Amortization (11,560) (3,846) (3,652) (2,379)
----------------------------------------------------------------------------
Operating income $ 10,921 $ 17,715 $ 41,308 $ 965
Operating income before
unrealized gains (losses) on
risk management $ 10,921 $ 17,715 $ 41,308 $ 965
----------------------------------------------------------------------------
Net additions (reductions) to:
Capital assets $ 27,636 $ 749 $ 1,274 $ 417
Energy services arrangements,
contracts and relationships - - $ 421 $ (37)
Long-term investment and
other assets - - $ 1,720 -
----------------------------------------------------------------------------
Goodwill $ 815 $ 18,045 - -
Segmented assets $ 476,292 $ 233,496 $ 121,149 $ 120,326
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Intersegment
Corporate Elimination Total
----------------------------------------------------------------------------
Revenue $ 2,277 $ (40,428) $ 677,360
Cost of sales - 39,334 (525,441)
Operating and administrative (11,190) 1,094 (68,486)
Amortization (1,103) - (22,540)
----------------------------------------------------------------------------
Operating income $ (10,016) - $ 60,893
Operating income before unrealized gains
(losses) on risk management $ (10,016) - $ 60,893
----------------------------------------------------------------------------
Net additions (reductions) to:
Capital assets $ 360 - $ 30,436
Energy services arrangements,
contracts and relationships - - $ 384
Long-term investment and other assets $ 631 - $ 2,351
----------------------------------------------------------------------------
Goodwill - - $ 18,860
Segmented assets $ 49,343 - $1,000,606
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


13. COMPARATIVE FIGURES

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

14. SUBSEQUENT EVENTS

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 on July 17, 2007. Responses to the bids are expected in September 2007.

AltaGas expects to file a final short-form base shelf prospectus to facilitate the issuance of trust units or unsecured debt securities on August 8, 2007. This shelf has a 25-month life and permits the Trust to issue up to an aggregate of $500 million of securities.

AltaGas signed an agreement to sell its 33.3335 percent interest in the Ikhil Joint Venture to AltaGas Utility Group Inc. for $9 million. No gain or loss is expected to result from the sale, which is effective July 1, 2007 and is subject to normal regulatory approvals.

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 will remain in effect and will continue 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 signed an agreement to purchase a 50 percent interest in the Sarnia Airport Pool Storage Project. Once developed, the Sarnia Airport Pool 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.

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 has also agreed to repay Aeolis' loans of approximately $1.0 million that it made to BMWLP to fund its share of development costs incurred to date. These loan repayments, 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.



Supplementary Quarterly Financial and Operating Information

($ millions unless otherwise
indicated) Q2-07 Q1-07 Q4-06 Q3-06 Q2-06
----------------------------------------------------------------------------
FINANCIAL HIGHLIGHTS(1)
Net Revenue(2)
Field Gathering and Processing 34.9 31.6 34.4 32.4 31.0
Extraction and Transmission 15.3 15.8 15.6 17.9 15.3
Power Generation 22.9 24.5 27.8 26.2 20.7
Energy Services 6.9 6.0 6.1 6.1 6.4
Corporate 1.1 2.0 1.6 0.5 0.2
Intersegment Elimination (1.0) (0.6) (0.9) (0.6) (0.8)
----------------------------------------------------------------------------
80.1 79.3 84.6 82.5 72.8
----------------------------------------------------------------------------

EBITDA(2)
Field Gathering and Processing 12.9 10.7 13.8 13.3 9.9
Extraction and Transmission 10.8 10.5 9.1 12.3 11.3
Power Generation 22.5 24.0 27.4 26.0 20.3
Energy Services 2.7 1.7 1.5 2.7 1.7
Corporate (5.8) (5.7) (7.3) (9.2) (5.8)
----------------------------------------------------------------------------
43.1 41.2 44.5 45.1 37.4
----------------------------------------------------------------------------

Operating Income(2)
Field Gathering and Processing 6.4 4.2 7.0 7.5 4.0
Extraction and Transmission 8.8 8.5 7.1 10.4 9.4
Power Generation 20.6 22.1 25.5 24.1 18.5
Energy Services 1.7 0.5 0.2 1.6 0.4
Corporate (6.3) (6.3) (7.8) (9.9) (6.3)
----------------------------------------------------------------------------
31.2 29.0 32.0 33.7 26.0
----------------------------------------------------------------------------

OPERATING HIGHLIGHTS
Field Gathering and Processing
Capacity (gross Mmcf/d)(3) 1,021 1,021 1,021 1,021 1,002
Throughput (gross Mmcf/d)(4) 534 552 549 537 565
Capacity utilization (%)(4) 52 54 54 53 56
Extraction and Transmission
Extraction inlet capacity
(Mmcf/d)(3) 554 554 554 539 539
Extraction volumes (Bbls/d)(4) 19,822 22,622 20,512 19,880 18,976
Transmission volumes
(Mmcf/d)(4)(5) 407 408 412 388 399
Power Generation
Volume of power sold
(thousands of MWh)(4) 650 666 711 669 656
Average price received on sale
of power ($/MWh)(4) 62.62 66.54 83.45 72.88 60.26
Alberta Power Pool average
spot price ($/MWh)(4) 49.97 63.62 116.81 94.87 53.59
Energy Services
Energy management service
contracts(3) 1,442 1,413 1,394 1,342 1,289
Average volumes transacted
(GJ/d)(4) 356,380 407,272 349,218 325,419 322,420
----------------------------------------------------------------------------
(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