CALGARY, ALBERTA--(Marketwire - Nov. 5, 2008) - AltaGas Income Trust (AltaGas or the Trust) (TSX:ALA.UN) today announced net income of $53.5 million ($0.75 per unit - basic) for the three months ended September 30, 2008, compared to $31.4 million ($0.54 per unit - basic) for the same period of 2007. Net income for the nine months ended September 30, 2008 was $124.0 million ($1.83 per unit - basic) compared to $77.0 million ($1.35 per unit - basic) for the same period in 2007. "Our gas and power businesses delivered strong third quarter results creating value for our investors. We expect operating results in fourth quarter to be similar to third quarter," said David Cornhill, Chairman and CEO of AltaGas. "Despite current economic conditions, our solid business and financial strength, position AltaGas for strong results in 2009," added Cornhill. Results in fourth quarter 2008 and for all of 2008 are expected to be stronger than fourth quarter 2007 and annual results for 2007 as a result of the Trust's increased energy infrastructure assets, supported by higher prices realized on the hedged portion of the power and natural gas liquids production. For the year, earnings growth has been moderated by several turnarounds at extraction facilities. The majority of AltaGas' revenues are underpinned by contractual arrangements that provide stable and predictable cash flow. Sixty percent of 2009 volumes exposed to frac spreads have been hedged at more than $27/Bbl. AltaGas is on track to hedge two-thirds of its Sundance power generation for 2009 by year-end at prices similar to the 2008 average hedge price. In addition, the Trust continues to optimize current operations and develop new assets. The volume additions at the Harmattan Complex, as well as the Bear Mountain Wind Park and Sarnia gas storage project, will contribute to earnings and cash flow next year and into the future. AltaGas also declared a distribution of $0.18 per trust unit and exchangeable unit payable on December 15, 2008 to unitholders of record on November 25, 2008. AltaGas declared total cash distributions of $0.535 per unit in third quarter 2008. Net income in third quarter 2008 increased over the same period last year as a result of the increased energy infrastructure assets from the Taylor acquisition, stronger performance from our field gathering and processing business, higher prices received on hedged power and a $13.8 million income tax recovery. The income tax recovery was a result of reorganizations within the trust structure, which required the application of lower tax rates on future income tax liabilities. Net income was negatively impacted by higher costs in the Power Generation segment, lower spot power prices and higher interest expense. Net income was also impacted by turnarounds and unplanned outages for approximately $2.6 million on an after-tax basis. FINANCIAL HIGHLIGHTS (1): - Earnings before interest, taxes, depreciation and amortization were $68.1 million ($0.96 per unit) for third quarter compared to $49.1 million ($0.85 per unit) in the same quarter in 2007. - Operating income was $50.7 million ($0.71 per unit) for third quarter 2008 compared to $37.5 million ($0.65 per unit) for the same period in 2007. - Funds from operations were $56.3 million ($0.79 per unit) for third quarter 2008 compared to $47.6 million ($0.83 per unit) for the same period in 2007. - Total debt at September 30, 2008 was $556.7 million, compared to $504.3 million at June 30, 2008 and $220.7 million at December 31, 2007. Debt was used to fund acquisitions and growth of the Trust. The Trust's debt-to-total capitalization ratio at September 30, 2008 was 37.5 percent, versus 36.4 percent at June 30, 2008 and 27.4 percent at the end of 2007. (1) Includes non-GAAP financial measures. Please see discussion in the Non-GAAP Financial Measures section of the Trust's third quarter Management's Discussion and Analysis. IN THE THIRD QUARTER: - AltaGas acquired NovaGreenPower Inc. (NovaGreen), a wholly-owned subsidiary of NovaGold Resources Inc. for $35 million with an additional $5 million on completion of certain conditions. NovaGreen is developing the Forrest Kerr run-of-river hydroelectric project, which is located in Northwest B.C. and is expected to have a capacity of 195 MW. NovaGreen is also pursuing three other development projects, all within the same region as Forrest Kerr, with a total potential run-of-river hydroelectric capacity of approximately 130 MW. - AltaGas acquired GreenWing Energy Management Ltd.'s (GreenWing) 45 percent interest in GreenWing Energy Development Limited Partnership (GEDLP) for $12.3 million. As a result, the Trust owns 100 percent of GEDLP, which includes 640 MW of mature wind development projects and approximately 800 MW of early development wind projects in Western Canada and the Western U.S. - Standard & Poor's Ratings Services (S&P) revised its outlook on AltaGas to positive from stable and affirmed the BBB- long-term corporate credit and senior unsecured debt ratings. The outlook revision reflected the efficient integration of Taylor, which AltaGas acquired on January 10, 2008, and the Trust's earnings and funds from operations, which have outperformed S&P's expectations. - DBRS revised its trend on AltaGas to positive from stable and confirmed its medium-term notes at BBB (low) and its stability rating at STA-3 (middle). The confirmation and change in trend to positive from stable for the debt ratings reflects the Trust's continued strong operating performance and the integration of Taylor. - A fire occurred in a natural gas-fired heater at the Harmattan Complex; lost revenues related to the fire were $0.5 million. - AltaGas sold a power project under development for proceeds of $6.6 million. An after-tax gain of $0.9 million was recorded. AltaGas will hold a teleconference today at 2:00 p.m. Mountain time (4:00 p.m. Eastern) to discuss the third quarter 2008 financial and operating results and other general issues and developments concerning the Trust. Members of the media, investment community and other interested parties may dial (416) 406-6419 or call toll free at 1-888-575-8232. No passcode is required. Please note that the conference call will also be webcast. To listen, please connect here: http://events.onlinebroadcasting.com/altagas/110508/index.php?page. Shortly after the conclusion of the call, a replay will be available by dialling (416) 695-5800 or 1-800-408-3053. The passcode is 3273171. The replay expires at midnight (Eastern) on November 13, 2008. 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 are provided to enable readers to assess the results of operations, liquidity and capital resources of the Trust as at and for the three and nine months ended September 30, 2008 compared to the three and nine months ended September 30, 2007. This MD&A dated November 5, 2008 should be read in conjunction with the accompanying unaudited Consolidated Financial Statements and notes thereto of the Trust as at and for the three and nine months ended September 30, 2008 and with the audited Consolidated Financial Statements and MD&A contained in the Trust's annual report for the year ended December 31, 2007. 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. Specifically, such forward-looking statements are set forth in respect of the Trust's overall capital outlook as it relates to the various projects under development by the Trust under the heading "Capital Outlook". In addition, such forward-looking statements are set forth in respect of each of the Trust's principal business segments under the headings "Extraction and Transmission - E&T Outlook", "Field Gathering and Processing - FG&P Outlook", "Energy Services - Energy Services Outlook", "Power Generation - Power Generation Outlook" and "Corporate - Corporate Outlook". These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Such statements reflect the Trust's current views with respect to future events based on certain material factors and assumptions and are subject to certain risks and uncertainties including without limitation, changes in market competition, governmental or regulatory developments, changes in tax legislation, general economic conditions and other factors set out in the Trust's public disclosure documents. Many factors could cause the Trust's or any particular segment's actual results, performance or achievements to vary from those described in this MD&A, including without limitation those listed above and the assumptions upon which they are based proving incorrect. These factors should not be construed as exhaustive. Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially from those described in this MD&A as intended, planned, anticipated, believed, sought, proposed, estimated or expected, and such forward-looking statements included in this MD&A herein should not be unduly relied upon. These statements speak only as of the date of this 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, including its annual MD&A and audited financial statements, Annual Information Form, Information Circular, Business Acquisition Report and Proxy Statement, material change reports and press releases issued by the Trust, are also available through the Trust's website or directly through the SEDAR system at www.sedar.com. ALTAGAS INCOME TRUST The material businesses of the Trust are operated by AltaGas Ltd., AltaGas Operating Partnership, AltaGas Limited Partnership and AltaGas Pipeline Partnership, Taylor NGL Limited Partnership (Taylor), as well as AltaGas Energy Limited Partnership (formerly known as PremStar Energy Canada Limited Partnership) 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 predominately derived 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. /T/ CONSOLIDATED FINANCIAL RESULTS Three Months Ended Nine Months Ended September 30 September 30 ($ millions) 2008 2007 2008 2007 ---------------------------------------------------------------------------- Revenue 460.7 322.1 1,392.2 1,091.9 Unrealized gains on risk management 3.7 1.1 1.4 1.6 Net revenue(1) 122.7 88.2 350.7 247.6 EBITDA(1) 68.1 49.1 185.5 133.4 EBITDA before unrealized gains on risk management(1) 64.4 48.0 184.1 131.8 Operating income(1) 50.7 37.5 135.3 97.7 Operating income before unrealized gains on risk management(1) 47.0 36.4 133.9 96.1 Net income 53.5 31.4 124.0 77.0 Net income before tax-adjusted unrealized gains on risk management(1) 52.7 30.7 124.4 76.8 Net income before tax(1) 44.7 34.6 116.0 88.7 Total assets 2,113.5 1,162.5 2,113.5 1,162.5 Total long-term liabilities 828.1 352.5 828.1 352.5 Net additions (reductions) to capital assets 95.1 5.9 760.5 (8.0) Distributions declared(2) 38.0 30.0 108.3 88.2 Cash flows Cash from operations 50.4 30.8 167.7 123.5 Funds from operations(1) 56.3 47.6 163.2 125.1 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Three Months Ended Nine Months Ended September 30 September 30 ($ per unit) 2008 2007 2008 2007 ---------------------------------------------------------------------------- EBITDA(1) 0.96 0.85 2.73 2.33 EBITDA before unrealized gains on risk management(1) 0.91 0.83 2.71 2.30 Net income - basic 0.75 0.54 1.83 1.35 Net income - diluted 0.75 0.54 1.81 1.35 Net income before tax-adjusted unrealized gains on risk management(1) 0.74 0.53 1.83 1.34 Net income before tax(1) 0.63 0.60 1.71 1.55 Distributions declared(2) 0.535 0.520 1.585 1.540 Cash flows Cash from operations 0.71 0.53 2.47 2.16 Funds from operations(1) 0.79 0.83 2.41 2.19 Units outstanding - basic (millions) During the period(3) 71.1 57.7 67.9 57.2 End of period 71.3 57.8 71.3 57.8 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Non-GAAP financial measure. See discussion in Non-GAAP Financial Measures section of this MD&A. (2) Distributions declared of $0.18 per unit per month commencing in August 2008. From August 2007 to July 2008 distributions of $0.175 per unit per month were declared. From January 2007 to July 2007 distributions of $0.17 per unit per month were declared. (3) Weighted average. /T/ CONSOLIDATED FINANCIAL REVIEW Three Months Ended September 30 Financial results in third quarter 2008 were significantly higher than the same quarter 2007 as net income increased 70 percent. The results represented strong operating performance from the increased asset base due to the acquisition of Taylor NGL Limited Partnership (Taylor) in January 2008, as well as stronger performance from the Field Gathering and Processing (FG&P) business. This quarter, operating income in the gas business was strong despite the $3.5 million impact of two turnarounds and a fire at the Harmattan Complex. Power also delivered strong results from higher hedged prices reflecting the impact of the Trust's disciplined hedging strategy. In third quarter 2008, the Trust also reported a $13.8 million tax recovery as a result of changes within the trust structure, which required the use of lower tax rates for future tax liabilities. Net income for the three months ended September 30, 2008 was $53.5 million ($0.75 per unit - basic) compared to $31.4 million ($0.54 per unit - basic) for the same period in 2007. Excluding the $13.8 million tax recovery and the after-tax gain of $0.8 million related to risk management contracts, net income for the three months ended September 30, 2008 was $38.9 million ($0.55 per unit - basic). Excluding the after-tax gain of $0.7 million related to risk management contracts, net income for the three months ended September 30, 2007 was $30.7 million ($0.53 per unit - basic). In third quarter 2008, operating income across all segments increased 35 percent to $50.7 million from $37.5 million. Operating income from the gas business was $26.0 million in third quarter 2008 compared to $12.8 million in same quarter 2007. Operating income increased primarily due to the larger energy infrastructure asset base as a result of the Taylor acquisition in January 2008, higher rates and throughput, partially offset by natural declines in certain FG&P operating areas. Operating income in third quarter 2008 was negatively impacted by $3.5 million as a result of two turnarounds and unplanned downtime due to a fire at the Harmattan Complex. In the power business, operating income was $30.1 million in third quarter 2008 compared to $31.5 million in third quarter 2007. Operating income decreased due to lower volumes sold, lower spot prices, higher environmental compliance costs, partially offset by a higher hedge prices, higher hedged volumes and a gain on the sale of a power development project. The operating loss in the Corporate segment decreased primarily due to unrealized gains in the fair value of risk management contracts and costs related to the write-off of a development project in third quarter 2007, partially offset by lower investment income and higher general and administrative costs due to the Taylor acquisition and overall escalating costs. On a consolidated basis, net revenue for the quarter ended September 30, 2008 was $122.7 million compared to $88.2 million in same quarter 2007. In the gas business, net revenue increased due to additional extraction, processing and transmission facilities, higher operating cost recoveries and higher rates and other revenues in FG&P. These increases were partially offset by natural declines in certain FG&P areas and the sale of assets in mid-2007. Net revenue in the quarter was impacted by turnarounds at two extraction facilities and the fire at the Harmattan Complex resulting in reduced net revenue of $3.5 million. In the power business, net revenue increased due to higher hedged prices and hedged volumes and a gain on the sale of a power development project, partially offset by lower net revenue from the sale of power at spot prices, higher environmental compliance costs and a favourable 30-rolling average power price (RAPP) in third quarter 2007. In addition, an unrealized gain on the fair value of risk management contracts increased net revenue. Operating and administrative expense for third quarter 2008 was $54.6 million, up from $39.1 million in same quarter in 2007. The increase was primarily a result of new and expanded facilities in the gas business and increased costs to support the growth of the Trust and overall escalating costs. Amortization expense for third quarter 2008 was $17.4 million compared to $11.7 million in the same quarter last year. The increase was due to the Taylor acquisition as well as a third quarter adjustment of approximately $1.0 million related to changes in the purchase price allocation related to the Taylor acquisition, partially offset by the sale of non-core assets in 2007. Interest expense for third quarter 2008 was $6.0 million compared to $2.9 million in same quarter 2007. The increase was due to higher average debt balances of $548.3 million compared to $225.2 million for the same period in 2007, partially offset by lower average interest rates. The average borrowing rate was 4.9 percent in third quarter 2008 compared to 5.3 percent for third quarter 2007. Income tax recovery in third quarter 2008 was $8.8 million compared to income tax expense of $3.2 in the same period 2007. The decrease was primarily due to the one-time $13.8 million recovery of future income taxes, partially offset by $2.9 million due to unrealized gains on risk management contracts and current tax provision on the sale of assets. The one-time future income tax recovery was a result of legal entity ownership changes within the trust structure. Nine Months Ended September 30 Financial results for the nine months ended September 2008 reflect the strong operating performance of AltaGas' energy infrastructure assets. In 2008 the Trust increased its assets by approximately $600 million as a result of the Taylor acquisition. Net income increased by 61 percent in the first nine months of 2008 compared to the first nine months of 2007. The gas and power businesses each reported higher operating income of 93 percent and 15 percent respectively for the nine months ended September 30, 2008 compared to the first nine months in 2007. The gas business reported strong results despite turnarounds at three extraction facilities this year which resulted in lost revenues of $5.0 million and operating costs of $2.5 million. The Trust reported higher interest due to the increase debt as a result of the Taylor acquisition and lower taxes as a result of internal reorganizations. Net income for the nine months ended September 30, 2008 was $124.0 million ($1.83 per unit - basic) compared to $77.0 million ($1.35 per unit - basic) in the same period last year. Excluding $13.8 million reduction in future tax liability, an after-tax charge of $1.9 million recorded in the second quarter related to costs written-off on development projects and $0.4 million after-tax loss on risk management contracts, net income was $112.5 million ($1.66 per unit - basic). Excluding the non-cash SIFT tax of $6.0 million reported in the first nine months of 2007, net income for the nine months ended September 30, 2007 was $83.0 million ($1.45 per unit - basic). Operating income across all segments increased 38 percent to $135.3 million in the nine months ended September 30, 2008 compared to $97.7 million for the same period in 2007. Operating income from the gas business was $78.6 million in the first nine months of 2008 compared to $42.9 million in the same period of 2007. In the power business, operating income was $85.4 million in the first nine months of 2008 compared to $74.3 million in the same period of 2007. In the nine months ended September 30, 2008 operating income from the gas and power businesses was 48 percent and 52 percent, respectively, of total operating income compared to 37 percent and 63 percent, respectively, for same period of 2007. The improved balance between the gas and power businesses reflects the impact of the Trust's strategy to have a more balanced portfolio of assets. In the gas business, operating income increased mainly due to the larger energy infrastructure asset base as a result of the Taylor acquisition, higher frac spreads, higher rates and other revenues in FG&P, partially offset by natural declines, lower throughput due to planned and unplanned downtime in certain FG&P areas and lower volumes processed at the Edmonton Ethane Extraction Plant. In the nine months ended September 30, 2008 direct costs of $2.5 million were incurred and lost revenue was $5.0 million as a result of major turnarounds at three extraction facilities and a fire at the Harmattan Complex. These facilities are on a three-year turnaround cycle. In the power business, operating income increased due to a higher average price received on the sale of power, higher contributions from the peaking plants, a deferral account settlement from the Alberta Electric System Operator (AESO) and a gain on the sale of one of the Trust's power development projects, partially offset by higher costs related to the power purchase arrangements (PPAs), favourable RAPP in 2007, higher environmental compliance costs and higher transmission costs. The operating loss in the Corporate segment increased primarily due to the Taylor acquisition, higher costs to support the growth of the Trust, general costs escalations and lower investment income. Consolidated net revenue for the nine months ended September 30, 2008 was $350.7 million compared to $247.6 million for the same period in 2007. In the gas business, net revenue increased due to additional extraction, processing and transmission facilities, higher frac spreads, higher operating cost recoveries and higher rates and other revenues in FG&P. These increases were partially offset by lower throughput in certain FG&P areas, the sale of non-core assets in mid-2007, lower fixed-price gas and transport sales, lower volumes processed at the Edmonton Ethane Extraction Plant and lower volumes in the Energy Services segment. In the power business, net revenue increased due to a higher average price received on the sale of power, higher contributions from the peaking plants, a deferral account settlement from the AESO and the gain on sale of a power development project, partially offset by higher costs related to the PPAs, higher RAPP in 2007, environmental compliance costs and transmission costs. Operating and administrative expense for the nine months ended September 30, 2008 was $165.1 million compared to $114.1 million in the same period last year. The increase was due to costs related to new facilities, turnaround costs and higher compensation and administrative costs. Amortization expense for the nine months ended September 30, 2008 was $50.2 million compared to $35.7 million in the same period last year. The increase was primarily due to new and expanded facilities in the gas business, partially offset by the disposition of non-core assets in second quarter 2007. Interest expense for the nine months ended September 30, 2008 was $19.3 million compared to $9.0 million in the same period last year. The increase was primarily due to higher average debt balances of $580.8 million compared to $240.4 million in the first nine months of 2007, partially offset by slightly lower average interest rates. The average borrowing rate for the first nine months of 2008 was 4.9 percent compared to 5.2 percent in the same period in 2007. Income tax recovery for the first nine months of 2008 was $8.0 million compared to income tax expense of $11.7 million in the same period 2007. The decrease was primarily due to $13.8 million for a one-time reduction in future income tax liability and $6.0 million SIFT tax reported in the first nine months of 2007. Consolidated Outlook Results in fourth quarter 2008 and for all of 2008 are expected to be stronger than fourth quarter 2007 and annual results for 2007 as a result of the increased energy infrastructure assets and higher prices realized on the hedged portion of the power and natural gas liquids production. Spot frac spreads are expected to average $10/Bbl in fourth quarter 2008 compared to $29/Bbl in fourth quarter 2007. The Trust expects to realize an average frac spread of $20/Bbl due to hedged volumes at approximately $23/Bbl. Fourth quarter 2008 average spot power prices are expected to be higher than spot prices realized in fourth quarter 2007, which will also contribute to a stronger fourth quarter. GLOBAL MARKET CONDITIONS Global financial markets have recently experienced severe turmoil, however AltaGas' financial position and ability to generate cash in the short and long-term from its operations remains sound. The Trust conducted a funding program for 2008, which consisted of a common equity issue valued at approximately $115 million in June 2008 and a new $250 million credit facility in March 2008. In addition, units issued under the Trust's Distribution Reinvestment and Optional Unit Purchase Plan (DRIP) are expected to be approximately $35 million in 2008. The Trust's liquidity position remains sound, underpinned by highly predictable cash flow from operations, as well as revolving bank lines of $750 million, of which $354 million remains available. The Trust has credit facilities with a syndicate which includes all five Canadian chartered banks. CAPITAL PROJECTS UPDATE The outlook for 2008 and 2009 capital expenditures is approximately $225 million and $250 million respectively. These expenditures are expected to be split approximately 45 percent gas and 55 percent power over the two years. Gas Projects Harmattan Co-streaming Project The proposed Harmattan Co-streaming Project is expected to bring natural gas from TransCanada's Alberta system to the Harmattan Complex for processing to recover ethane, propane, butane and condensate. The NGL Extraction Inquiry hearing at the Alberta Energy Resources Conservation Board (ERCB) concluded at the end of September and the ERCB is expected to provide a ruling by year-end. Once the ruling has been issued, the Trust will re-submit the application for its Harmattan Co-streaming project. Upon approval, construction of the co-streaming project will commence, requiring approximately 14 months to complete. The project, as currently envisioned, is expected to cost in the range of $100 million to $120 million. These costs have escalated due to the increase in steel prices. Power Projects Forrest Kerr and Other Hydroelectric Projects AltaGas is developing a portfolio of run-of-river hydroelectric projects in British Columbia. The largest of these is the 195-MW Forrest Kerr project in Northwest B.C. In addition to Forrest Kerr, AltaGas is in various stages of developing three projects in the Forrest Kerr area with a combined additional capacity of approximately 130 MW. These projects were acquired by AltaGas through the NovaGreen acquisition for $35 million with an additional $5 million payable on completion of certain conditions. Prior to the acquisition of NovaGreen, AltaGas had under development a number of run-of-river hydroelectric projects with approximate capacity of 70 MW of renewable energy. The projects continue to be at various stages of development. GreenWing Energy Development Limited Partnership The Trust acquired from GreenWing Energy Management Ltd. (GreenWing) its 45 percent interest in GreenWing Energy Development Limited Partnership (GEDLP) for $12.3 million on August 15, 2008. The acquisition of the remainder of GEDLP resulted in AltaGas holding 640 MW of mature wind development projects and approximately 800 MW of early development wind projects in western Canada and western United States. Bear Mountain Wind Park Construction of the 102-MW Bear Mountain Wind Park near Dawson Creek, British Columbia is on time and on budget. Foundations to support turbine construction are complete. AltaGas currently owns 100 percent of the Bear Mountain Wind Limited Partnership (BMWLP) and the Bear Mountain Wind Park. AltaGas intends to finance the project, which is expected to cost approximately $195 million, through its credit facilities. The Bear Mountain Wind Park is backstopped by a 25-year electricity purchase agreement with BC Hydro. AltaGas entered into an engineering-procurement-construction agreement with Enercon GmbH (Enercon) to supply and install the wind turbines. AltaGas has also entered into a long-term service agreement with Enercon to operate and maintain the wind turbines. AltaGas intends to have the project completed by November 2009. Expenditures for the project are expected to be approximately $50 million in 2008 and $130 million in 2009. AltaGas has paid 25 percent of the total Euros required for the project and has hedged 90 percent of the remaining Euro amounts, which are payable over time commencing in second quarter 2009. The above disclosed projects are third quarter updates. For information on all outstanding AltaGas projects, please see the 2007 Annual Report and the two prior 2008 interim reports. NON-GAAP FINANCIAL MEASURES This MD&A contains references to certain financial measures that do not have a standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP) and may not be comparable to similar measures presented by other entities. The non-GAAP measures and their reconciliation to GAAP financial measures are shown below. All of the measures have been calculated consistently with previous disclosures. References to net revenue, operating income, EBITDA, EBITDA before unrealized gains (losses) on risk management, net income before tax-adjusted unrealized gains (losses) on risk management, net income before tax and funds from operations throughout this document have the meanings as set out in this section. /T/ Net Revenue Three Months Ended Nine Months Ended September 30 September 30 ($ millions) 2008 2007 2008 2007 ---------------------------------------------------------------------------- Net revenue 122.7 88.2 350.7 247.6 Add: Cost of sales 338.0 233.9 1,041.5 844.3 ---------------------------------------------------------------------------- Revenue (GAAP financial measure) 460.7 322.1 1,392.2 1,091.9 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ 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. /T/ Operating Income Three Months Ended Nine Months Ended September 30 September 30 ($ millions) 2008 2007 2008 2007 ---------------------------------------------------------------------------- Operating income 50.7 37.5 135.3 97.7 Add (deduct): Interest expense (6.0) (2.9) (19.3) (9.0) Income tax recovery (expense) 8.8 (3.2) 8.0 (11.7) ---------------------------------------------------------------------------- Net income (GAAP financial measure) 53.5 31.4 124.0 77.0 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ 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. The measure is used by management to assess the operating performance of the business segments as it is a better indicator of operating performance than net income. 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. /T/ EBITDA Three Months Ended Nine Months Ended September 30 September 30 ($ millions) 2008 2007 2008 2007 ---------------------------------------------------------------------------- EBITDA 68.1 49.1 185.5 133.4 Add (deduct): Amortization (17.4) (11.6) (50.2) (35.7) Interest expense (6.0) (2.9) (19.3) (9.0) Income tax recovery (expense) 8.8 (3.2) 8.0 (11.7) ---------------------------------------------------------------------------- Net income (GAAP financial measure) 53.5 31.4 124.0 77.0 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ 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. /T/ EBITDA Before Unrealized Gains on Risk Management Three Months Ended Nine Months Ended September 30 September 30 ($ millions) 2008 2007 2008 2007 ---------------------------------------------------------------------------- EBITDA before unrealized gains on risk management 64.4 48.0 184.1 131.8 Add (deduct): Unrealized gains on risk management 3.7 1.1 1.4 1.6 Amortization (17.4) (11.6) (50.2) (35.7) Interest expense (6.0) (2.9) (19.3) (9.0) Income tax recovery (expense) 8.8 (3.2) 8.0 (11.7) ---------------------------------------------------------------------------- Net income (GAAP financial measure) 53.5 31.4 124.0 77.0 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ EBITDA before unrealized gains (losses) on risk management is a measure of the Trust's operating profitability without the impact of the change in fair value of risk management contracts. EBITDA before unrealized gains or losses on risk management reports the results of the Trust's principal business activities on a realized basis and prior to how business activities are financed, assets are amortized or how the results are taxed. AltaGas does not speculate on commodity prices, but rather enters into financial instruments to manage risk, and therefore evaluates company performance prior to the accounting of the unrealized gains or losses from risk management activities. EBITDA before gains or 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 or losses on risk management less operating and administrative expenses. /T/ Net Income Before Tax-Adjusted Three Months Ended Nine Months Ended Unrealized Gains on Risk Management September 30 September 30 ($ millions) 2008 2007 2008 2007 ---------------------------------------------------------------------------- Net income before tax-adjusted unrealized gains on risk management 52.7 30.7 124.4 76.8 Add (deduct): Unrealized gains on risk management 3.7 1.1 1.4 1.6 Income tax recovery (expense) on risk management (2.9) (0.4) (1.8) (1.4) ---------------------------------------------------------------------------- Net income (GAAP financial measure) 53.5 31.4 124.0 77.0 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ Net income before tax-adjusted unrealized gains (losses) on risk management is a better reflection of actual performance than net income, as changes related to risk management are based on unrealized estimates relating to commodity prices and foreign exchange rates over time. AltaGas enters into financial instruments to manage risk, not as a principal business activity and therefore evaluates company performance prior to accounting for the unrealized gains (losses) from risk management activities. Net income before tax-adjusted unrealized gains (losses) on risk management is calculated from the Consolidated Statements of Income and Accumulated Earnings and is defined as net income adjusted for unrealized gains (losses) on risk management and its related income tax expense. /T/ Net Income Before Tax Three Months Ended Nine Months Ended September 30 September 30 ($ millions) 2008 2007 2008 2007 ---------------------------------------------------------------------------- Net income before tax 44.7 34.6 116.0 88.7 Add (deduct): Income tax recovery (expense) 8.8 (3.2) 8.0 (11.7) ---------------------------------------------------------------------------- Net income (GAAP financial measure) 53.5 31.4 124.0 77.0 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ Net income before tax is a better reflection of performance because it is not dependent on how those results are taxed, which can change from year to year. Net income before tax is calculated from the Consolidated Statements of Income and Accumulated Earnings and is defined as net income adjusted for income tax expenses or recoveries. /T/ Funds from Operations Three Months Ended Nine Months Ended September 30 September 30 ($ millions) 2008 2007 2008 2007 ---------------------------------------------------------------------------- Funds from operations 56.3 47.6 163.2 125.1 Add (deduct): Net change in non-cash working capital (5.7) (16.4) 4.9 (1.0) Asset retirement obligations settled (0.2) (0.4) (0.4) (0.6) ---------------------------------------------------------------------------- Cash from operations (GAAP financial measure) 50.4 30.8 167.7 123.5 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ Funds from operations is used to assist management and investors in analyzing financial 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. /T/ RESULTS OF OPERATIONS BY SEGMENT Operating Income Three Months Ended Nine Months Ended September 30 September 30 ($ millions) 2008 2007 2008 2007 ---------------------------------------------------------------------------- Extraction and Transmission 18.0 9.9 61.6 27.2 Field Gathering and Processing 7.2 3.1 17.3 13.7 Energy Services 0.8 (0.2) (0.3) 2.0 Power Generation 30.1 31.5 85.4 74.3 Corporate (5.4) (6.8) (28.7) (19.5) ---------------------------------------------------------------------------- 50.7 37.5 135.3 97.7 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ EXTRACTION AND TRANSMISSION The Extraction and Transmission (E&T) segment consists of interests in six ethane and NGL extraction plants, five natural gas and three NGL transmission systems. As a result of the Taylor acquisition in January 2008, AltaGas added an interest in the Younger Extraction Plant in British Columbia, acquired the Harmattan Complex, the Ethylene Delivery System (EDS) and Joffre Feedstock Pipeline (JFP) in Alberta and increased its ownership in the Joffre Extraction Plant to 100 percent from 50 percent. /T/ Financial Results Three Months Ended Nine Months Ended September 30 September 30 ($ millions) 2008 2007 2008 2007 ---------------------------------------------------------------------------- Revenue 111.8 32.7 332.0 103.6 Net revenue 43.8 17.0 133.5 48.1 Operating and administrative expense 18.4 5.0 51.4 14.8 Amortization expense 7.4 2.1 20.5 6.1 Operating income 18.0 9.9 61.6 27.2 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Operating Statistics Three Months Ended Nine Months Ended September 30 September 30 2008 2007 2008 2007 ---------------------------------------------------------------------------- Extraction inlet gas processed (Mmcf/d)(1) 781 554 805 554 Extraction ethane volumes (Bbls/d)(1) 23,543 10,584 25,150 13,051 Extraction NGL volumes (Bbls/d)(1) 12,048 6,275 12,503 6,696 Total extraction volumes (Bbls/d)(1) 35,591 16,859 37,653 19,747 Frac spread - realized ($/Bbl)(1)(2) 26.02 25.24 26.55 18.28 Frac spread - average spot price ($/Bbl)(1) 36.92 26.41 31.75 18.69 Transmission volumes (Mmcf/d)(1)(3) 381 407 383 407 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Average for the period. (2) AltaGas reports an indicative frac spread or NGL margin, expressed in dollars per barrel of NGL, which is derived from Edmonton postings for propane, butane and condensate and the daily AECO natural gas price. (3) Excludes natural gas liquids pipeline volumes. /T/ Three Months Ended September 30 In third quarter 2008 the E&T segment accounted for approximately 32 percent of operating income from the operating segments compared to 22 percent in third quarter 2007. Operating income in third quarter 2008 was $18.0 million compared to $9.9 million reported for the same period in 2007. The primary contributor to the increase in operating income was the addition of new extraction and transmission facilities with the Taylor acquisition. In third quarter, plant turnarounds and a fire within a natural gas heater at the Harmattan Complex resulted in lost revenue of $3.5 million. Changes to the purchase price allocation resulted in a one-time increase to amortization expense of $1.0 million. Average ethane and NGL volumes in the extraction business increased 111 percent in third quarter 2008 compared to same quarter 2007, mainly due to the addition of the Harmattan Complex, Younger Extraction Plant and the remaining 50 percent ownership in the Joffre Extraction Plant. Natural gas volumes transported in the transmission business during the third quarter 2008 decreased from the same quarter in 2007 due to lower volumes moved on the Suffield system. However, in the transmission business, pipeline throughput has minimal impact on the financial results due to cost-of-service and take-or-pay contractual arrangements in place. Net revenue in third quarter 2008 more than doubled to $43.8 million, up from $17.0 million in the same period in 2007. Net revenue increased by $26.8 million primarily as a result of the extraction and transmission assets acquired with Taylor. Net revenue was impacted by $3.0 million in lost revenues due to the plant turnarounds and $0.5 million in lost revenue related to a fire on a natural gas heater at the Harmattan Complex. Operating and administrative expense in third quarter 2008 was $18.4 million compared to $5.0 million for the same period in 2007. The increase was mainly due to the costs incurred to operate the new facilities. Amortization expense in third quarter 2008 was $7.4 million compared to $2.1 million for the same period in 2007. The increase was due to additional assets from the Taylor acquisition and $1.0 million as a result of changes to the Taylor purchase price allocation. Nine Months Ended September 30 Operating income in the E&T segment for the first nine months of 2008 was $61.6 million compared to $27.2 million for the same period in 2007. The primary contributor to the increase in operating income was the addition of new extraction and transmission facilities with the Taylor acquisition and higher frac spreads, partially offset by lower volumes processed at the Edmonton Ethane Extraction Plant. Operating income was impacted by $7.5 million as a result of plant turnarounds and a fire at the Harmattan Complex. In the first nine months of 2008, average ethane and NGL volumes increased primarily as a result of the addition of the Harmattan Complex, Younger Extraction Plant and the remaining 50 percent ownership in the Joffre Extraction Plant offset by lower volumes processed at the Edmonton Ethane Extraction Plant. Transmission volumes decreased slightly in the first nine months of 2008 due to lower volumes on the Suffield system. Net revenue in the first nine months ended September 30, 2008 was $133.5 million, up substantially from $48.1 million for the same period in 2007. Net revenue increased by $85.4 million primarily as a result of the extraction and transmission assets acquired with Taylor, $3.2 million due to higher realized frac spreads and $0.5 million due to higher volumes of NGLs exposed to frac spreads, partially offset by $1.3 million due to lower volumes processed through the Edmonton Ethane Extraction Plant. Net revenue has been impacted by $4.5 million due to the plant turnarounds and $0.5 million in lost revenue as a result of a fire at the Harmattan facility. Operating and administrative expense for the nine months ended September 30, 2008 was $51.4 million compared to $14.8 million for the same period in 2007. The increase was mainly due to the costs incurred to operate the Taylor assets acquired in first quarter 2008. Operating and administrative costs in the first nine months of 2008 included approximately $2.5 million related to the Harmattan turnaround. Amortization expense in the nine months ended September 30, 2008 was $20.5 million compared to $6.1 million for the same period in 2007. The increase was due to the Taylor acquisition in January 2008. E&T Outlook Results in the E&T segment are expected to continue to increase materially in 2008. The addition of new extraction and transmission facilities with the acquisition of Taylor has added approximately 1 Bcf/d of inlet extraction capacity and 140,000 Bbls/d of NGL transportation capacity. Operating income in the E&T segment as a percentage of total operating income from all operating segments is expected to increase from 25 percent in 2007 to approximately 40 percent in 2008. The Harmattan Complex has been fully operational since August 11, 2008 following the July 24 fire that was confined to a gas-fired heater. Damages related to the fire are being evaluated. It is expect that $0.8 million insurance deductible will be expensed in fourth quarter 2008. In fourth quarter 2008, one of the extraction facilities will complete a turnaround resulting in $0.5 million in operating costs and lost revenues. One of the four turnarounds previously planned for the third quarter 2008 has been deferred to 2009. The current 2008 capital program is expected to further enhance this segment's performance. Beginning in fourth quarter 2008, volumes processed are expected to increase as a result of the $55 million capital program underway to consolidate processing facilities and optimize and upgrade the Harmattan Complex, resulting in increased utilization, lower emissions and lower operating costs per unit of volume processed. Approximately 12 percent (5,000 Bbls/d) of total extraction volumes produced are sold at current market prices and approximately 60 percent of those volumes have been hedged at over $23/Bbl for the remainder of 2008. For 2009, approximately 60 percent of exposed volumes has been hedged at over $27/Bbl, and for 2010, approximately 15 percent of exposed volumes have been hedged at over $27/Bbl. Based on management's analysis of historical NGL prices along with industry published commodity prices, the current forward curve for fourth quarter 2008 is $10/Bbl. With the hedges in place, AltaGas expects to realize approximately $20/Bbl in fourth quarter 2008. In the transmission business, the addition of the EDS and JFP pipelines in January 2008 and full year results from the Cold Lake expansion are also expected to contribute to increased earnings compared to 2007. An arrangement to redeploy capacity on a lateral of the EDS pipeline began contributing to earnings beginning second quarter 2008. AltaGas is spending approximately $12.5 million to upgrade another portion of the EDS pipeline. The upgrade is expected to be completed by the end of December 2008 and AltaGas will earn a return on the capital invested on the upgrade commencing in January 2009. Despite the lower price forecast for frac spreads, AltaGas remains well positioned for 2009 within the E&T segment by virtue of having a variety of revenue streams that are not dependent on commodity prices. The majority of net revenue is derived from fixed-price arrangements, which include fee-for-service, cost-of-service and fixed-fee earnings. Management has confirmed its unhedged sensitivity to frac spreads, assuming 60 percent hedged, is approximately $0.01/unit net income for every $1/Bbl change in frac spread, based on a 26 percent tax rate, on an annual basis. FIELD GATHERING AND PROCESSING The FG&P segment includes natural gas gathering pipelines and processing facilities. In January 2008 AltaGas added three interconnected processing facilities, Retlaw, Enchant and Turin and related gathering systems (RET) with processing capacity of 150 Mmcf/d as a result of the Taylor acquisition. /T/ Financial Results Three Months Ended Nine Months Ended September 30 September 30 ($ millions) 2008 2007 2008 2007 ---------------------------------------------------------------------------- Revenue 41.3 33.4 119.3 103.4 Net revenue 38.1 31.5 110.3 98.0 Operating and administrative expense 23.9 21.9 72.1 64.8 Amortization expense 7.0 6.5 20.9 19.5 Operating income 7.2 3.1 17.3 13.7 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Operating Statistics Three Months Ended Nine Months Ended September 30 September 30 2008 2007 2008 2007 ---------------------------------------------------------------------------- Capacity (Mmcf/d)(1) 1,178 1,008 1,178 1,008 Throughput (gross Mmcf/d)(2) 545 510 547 532 Capacity utilization (%)(2) 46 51 46 53 Average working interest (%)(1) 90 92 90 92 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) As at the end of the reporting period. (2) Average for the period. /T/ Three Months Ended September 30 Operating income in the FG&P segment for third quarter 2008 was $7.2 million compared to $3.1 million for the same quarter of 2007. Operating income increased due to higher rates, the addition of new plants and lower operating expenses, partially offset by lower volumes at some previously owned facilities. Processing capacity increased by 170 Mmcf/d mainly as a result of the addition of the RET facility, Acme and Corbett Creek facilities; both the Acme and Corbett Creek facilities are dedicated to coal bed methane (CBM) gas processing. Utilization reported in third quarter 2008 was 46 percent compared to 51 percent reported in third quarter 2007 primarily due to lower utilization at the new plants, as well as lower throughput at some previously owned facilities. Throughput in third quarter 2008 averaged 545 Mmcf/d compared to 510 Mmcf/d third quarter 2007. The 7 percent increase was primarily due to the acquisition of new plants and additional well tie-ins, partially offset by natural declines and lower producer activity in certain operating areas. Net revenue for the FG&P segment was $38.1 million in third quarter 2008 compared to $31.5 million for the same period in 2007. Net revenue increased due to $4.8 million from new facilities, $2.7 million due to higher operating cost recoveries and $1.0 million from rate increases and higher other facility service revenues. These increases were partially offset by $1.4 million as a result of lower volumes due to natural declines and lower producer activity and the sale of AltaGas' one-third interest in the Ikhil Joint Venture in 2007. Operating and administrative expense in third quarter 2008 was $23.9 million compared to $21.9 million for the same quarter in 2007. The increase was primarily due to the addition of new facilities, partially offset by lower operating expenses incurred at previously owned facilities. Amortization expense for the FG&P segment in third quarter 2008 was $7.0 million compared to $6.5 million for the same period in 2007. The increase was due to additional facilities. Nine Months Ended September 30 Operating income in the FG&P segment was $17.3 million for the first nine months of 2008 compared to $13.7 million for the same period in 2007. The increase was due to the contribution from new facilities, higher rates and other facility service revenues, partially offset by lower throughput. Throughput in the first nine months of 2008 averaged 547 Mmcf/d compared to 532 Mmcf/d for the same period in 2007. The increase was primarily due to the acquisition of new plants and additional well tie-ins, partially offset by natural declines, lower producer activity, unscheduled plant outages at the Princess and Clear Hills facilities and the scheduled turnaround at the Rainbow Lake facility. Net revenue in the FG&P segment for the first nine months of 2008 was $110.3 million compared to $98.0 million for the same period in 2007. The increase was due to $13.4 million from new facilities, $4.8 million due to higher operating cost recoveries, $2.4 million from increased rates and higher other facility service revenues. These increases were partially offset by $5.7 million due to natural volume declines, lower producer drilling activity and operational downtime, as well as $2.6 million from the sale of the Ikhil Joint Venture. Operating and administrative expense in the FG&P segment in the first nine months of 2008 was $72.1 million compared to $64.8 million for the same period in 2007. The increase was mainly attributable to $6.6 million for new facilities and $3.7 million due to the Rainbow Lake turnarounds. These increases were partially offset by $1.8 million due to continuing efforts on cost controls, $1.3 million related to the sale of the Ikhil Joint Venture and lower operating costs related to planned and unplanned downtime. Approximately three quarters or $2.8 million of the Rainbow Lake facility turnaround costs were recoverable. Amortization expense in the FG&P segment in the first nine months of 2008 was $20.9 million compared to $19.5 million in the same period in 2007. The increase was due to new and expanded facilities, partially offset by the sale of the Ikhil Joint Venture in 2007. FG&P Outlook FG&P expects to report higher results in 2008 than in 2007. The increase is due to the addition of the RET facilities, a full year of operations at Acme and Corbett Creek, recontracting at higher rates, an increase in operating recoveries and optimization of facilities and continued focus on increasing throughput and operating and administrative cost control. In the fourth quarter, the Bantry sour gas processing plant will be converted to acid gas injection. This will improve the reliability of the facility and reduce greenhouse gas emissions. Recent commodity price volatility and credit liquidity issues may cause producers within AltaGas' operating areas to reduce their exploration and development programs. As a result, well tie-in activity may decrease in the short-term and delivered volumes may decline. These market dynamics may also present opportunities to acquire or develop new processing facilities as producers focus capital on exploration and drilling. AltaGas continues to pursue opportunities to grow and optimize its FG&P assets. ENERGY SERVICES The Energy Services segment consists of two main businesses: an energy management business providing energy consulting and supply management services and arranging gas and power contracts for non-residential end-users; and a gas services business buying and reselling natural gas, transportation and storage. The segment previously included a small portfolio of oil and natural gas production assets that were sold effective May 31, 2007. /T/ Financial Results Three Months Ended Nine Months Ended September 30 September 30 ($ millions) 2008 2007 2008 2007 ---------------------------------------------------------------------------- Revenue 263.9 211.1 824.9 795.3 Net revenue 4.4 3.9 10.8 16.9 Operating and administrative expense 3.0 3.5 9.5 12.1 Amortization expense 0.6 0.6 1.6 2.8 Operating income 0.8 (0.2) (0.3) 2.0 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Operating Statistics Three Months Ended Nine Months Ended September 30 September 30 2008 2007 2008 2007 ---------------------------------------------------------------------------- Energy management service contracts(1) 1,572 1,451 1,572 1,451 Average volumes transacted (GJ/d)(2) 298,608 342,143 306,922 372,931 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (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. /T/ Three Months Ended September 30 Operating income in the Energy Services segment in third quarter 2008 was $0.8 million compared to an operating loss of $0.2 million for the same quarter in 2007. Operating income increased as a result of a $0.8 million one-time pricing adjustment related to a supply contract, $0.5 million in lower operating and administrative expenses and $0.1 million in lower amortization expense, partially offset by $0.3 million in lower fixed-price gas and transport sales. Net revenue in third quarter 2008 was $4.4 million compared to $3.9 million for the same period in 2007. Net revenue increased as a result of the one-time $0.8 million pricing adjustment, partially offset by a $0.3 million due to lower fixed-price gas and transport sales lower volumes. Nine Months Ended September 30 The Energy Services segment reported an operating loss of $0.3 million for the first nine months of 2008 compared to operating income of $2.0 million for the same period in 2007. The decrease was due to the $1.6 million gain reported on the sale of oil and natural gas production assets in second quarter 2007, lower fixed-price gas and transport sales, declining volumes and a one-time cost for commissions paid to a trade association related to 2007. The decreases were partially offset by a one-time pricing adjustment and lower operating and administrative expenses. Net revenue was $10.8 million in the first nine months of 2008 compared to $16.9 million in the same period in 2007. The decrease included $4.1 million from the sale of oil and natural gas assets in second quarter 2007 and $2.8 million due to lower fixed-price gas and transport sales and declining volumes, partially offset by a $0.8 million one-time pricing adjustment. Energy Services Outlook AltaGas expects results in the Energy Services segment in 2008 to be slightly lower than 2007 results, excluding the gain on sale of the oil and gas production assets in 2007. However, the recent acquisition of Taylor is expected to provide opportunities to enhance unitholder value due to the increased geographic footprint and energy infrastructure. The Energy Services segment is an important element in increasing the value of assets in AltaGas' other segments. Energy Services works with the other segments to optimize AltaGas' assets and in this capacity is expected to contribute to earnings growth across the segments. POWER GENERATION The Power Generation segment comprises approximately 392.4 MW of total power generation capacity in Alberta through a 50 percent ownership interest in the Sundance B power purchase arrangements and a capital lease for 25 MW of gas-fired power peaking capacity. In addition, gas-fired peaking plants at Bantry and Parkland have been installed with generating capacity of 14.4MW. The segment also includes a 25 percent interest in a 7-MW run-of-river hydroelectric generation facility in British Columbia acquired in January 2008 with the Taylor acquisition. /T/ Financial Results Three Months Ended Nine Months Ended September 30 September 30 ($ millions) 2008 2007 2008 2007 ---------------------------------------------------------------------------- Revenue 55.6 51.7 165.3 136.7 Net revenue 32.8 33.9 93.1 81.3 Operating and administrative expense 1.0 0.5 2.2 1.4 Amortization expense 1.7 1.9 5.5 5.6 Operating income 30.1 31.5 85.4 74.3 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Operating Statistics Three Months Ended Nine Months Ended September 30 September 30 2008 2007 2008 2007 ---------------------------------------------------------------------------- Volume of power sold (GWh) 651 673 1,958 1,988 Average price received on the sale of power ($/MWh)(1) 83.10 76.92 83.57 68.77 Alberta Power Pool average spot price ($/MWh)(1) 80.36 92.00 88.21 68.53 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Average for the period. /T/ Three Months Ended September 30 Operating income in the Power Generation segment in third quarter 2008 was $30.1 million compared to $31.5 million for the same quarter in 2007. Operating income decreased as a result of higher RAPP received due to a planned outage at Sundance in third quarter 2007, lower power spot prices, lower contributions from gas-fired peaking plants, higher costs to comply with Alberta's Specified Gas Emitters Regulation (SGER), higher PPA costs and higher transmission costs. These decreases were partially offset by higher hedge prices, higher hedged volumes and a gain on the sale of a power project that was under development. Net revenue in third quarter 2008 was $32.8 million compared to $33.9 million for the same period in 2007. Net revenue decreased $6.2 million due to lower power prices received on spot sales, $2.1 million in a favourable RAPP received in the third quarter 2007, $1.3 million as a result of higher transmission costs, $0.7 million in higher costs to comply with Alberta's SGER, $0.6 million due to lower contributions from gas-fired peaking plants and $0.5 million in higher PPA costs. These decreases were partially offset by $8.9 million due to higher hedge prices and hedged volumes and $1.4 million from the sale of one of AltaGas' power projects under development in the United States. Operating and administrative expense was $1.0 million in third quarter 2008 compared to $0.5 million for the same period in 2007. The increase was due primarily due to administrative costs related to the development of run-of-river projects. Amortization expense of $1.7 million in third quarter 2008 was similar with the same period in 2007. Nine Months Ended September 30 Operating income in the Power Generation segment for the first nine months of 2008 was $85.4 million compared to $74.3 million for the same period in 2007. The increase was due to higher prices received on the sale of power, an AESO deferral account settlement, higher contributions from peaking plants and a gain from the sale of a power project under development, partially offset by higher PPA costs, higher transmission costs and higher costs to comply with Alberta's SGER. Net revenue for the first nine months of 2008 was $93.1 million compared to $81.3 million for the same period in 2007. The increase included $24.6 million due to higher prices received on higher hedged volumes, $1.8 million from an AESO deferral account settlement, $1.6 million in higher contributions from the gas-fired peaking plants, $1.4 million from higher prices received on spot sales and $1.4 million from the sale of a power development project. These increases were partially offset by $10.2 million due to a favourable RAPP received in 2007, $4.9 million as a result of higher transmission costs, $3.2 million of costs incurred to comply with Alberta's SGER and $0.7 million in higher PPA costs. Operating and administrative expense of $2.2 million in the first nine months of 2008 was higher than the $1.4 million reported in the same period in 2007, primarily due to the operating and maintenance services AltaGas began providing to the leased peaking plants in March 2007 and administrative costs related to the development of run-of-river projects. Amortization expense of $5.5 million in the first nine months of 2008 was similar to the same period in 2007. Power Generation Outlook Operating income in the Power Generation segment is expected to be higher in 2008 than in 2007 due to the contribution from hedged power volumes as a result of average hedge prices of approximately $77/MWh in 2008 compared to $66/MWh in 2007. Approximately two-thirds of the power available from the Sundance B PPAs for 2008 has been hedged and the remainder is exposed to the spot price of power in Alberta. In fourth quarter 2008, AltaGas has hedged three-quarters of the power available to mitigate the impact of power price volatility for the remainder of the year. The forward market for Alberta power prices, as published in daily broker reports, indicates that prices will remain relatively strong, at over $100/MWh for the remainder of 2008. PPA costs are expected to be higher in 2008 due to higher volumes of power generated. The price for coal purchased through the PPAs is based on pre-defined formulae tied to inflation rather than the prevailing market price of coal and therefore is not expected to have a significant impact on PPA costs. Despite the current commodity market and credit liquidity turmoil, forward Alberta power prices have been relatively stable over the medium-term. The Trust is on track to meet its hedge targets for 2009 and expects average hedge prices to be similar to 2008. AltaGas has also begun executing its hedging strategy for 2010 at prices similar to 2008 levels. AltaGas' sensitivity to net income is $0.01 per unit annually with a $1/MWh change based on a 26 percent tax rate and 70 percent of PPA volumes hedged. CORPORATE The Corporate segment includes the cost of providing corporate services and general corporate overhead, investments in public and private entities and the effects of changes in the value of risk management assets and liabilities. Management makes operating decisions and assesses performance of its operating segments based on realized results and key financial metrics such as return on equity, and return on capital without the impact of the volatility in commodity prices and foreign exchange rates. Management monitors the impact of mark-to-market accounting as part of the consolidated entity as risk is managed on a portfolio basis. Consequently, the impact of mark-to-market accounting on net income is reported and monitored in the Corporate segment. /T/ Financial Results Three Months Ended Nine Months Ended September 30 September 30 ($ millions) 2008 2007 2008 2007 ---------------------------------------------------------------------------- Revenue (0.1) 0.8 1.4 3.5 Unrealized gains on risk management 3.7 1.2 1.4 1.6 Net revenue 3.6 2.0 2.8 5.1 Operating and administrative expense 8.3 8.2 29.8 22.8 Amortization expense 0.7 0.6 1.7 1.8 Operating loss (5.4) (6.8) (28.7) (19.5) Operating loss before unrealized gains on risk management (9.1) (7.9) (30.1) (21.1) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ Three Months Ended September 30 The operating loss for third quarter 2008 was $5.4 million compared to $6.8 million for the same period in 2007. The decreased loss was mainly due to unrealized gains on risk management contracts and a write-off of costs related to the deferred Noel project in 2007, partially offset by lower investment income from Taylor which is now reported in the operating segments. Net revenue was $3.6 million for the third quarter in 2008 compared to $2.0 million in third quarter 2007. Net revenue increased due to $2.5 million in higher unrealized gains on risk management contracts, partially offset by $0.8 million primarily due to lower investment income as AltaGas no longer reports Taylor investment income in the Corporate segment. Operating and administrative expense for third quarter 2008 was $8.3 million compared to $8.2 million for the same period in 2007. The increase was primarily due to the growth of the Trust, partially offset by a $1.5 million write-off of costs related to the deferred Noel project in 2007. Amortization expense was $0.7 million for third quarter 2008 compared to $0.6 for the same quarter in 2007. The increase is due to growth of AltaGas. Nine Months Ended September 30 The operating loss for the first nine months of 2008 was $28.7 million compared to $19.5 million for the same period in 2007. The increased loss was due to a write-down for project development costs in 2008, higher operating and administration costs and lower investment income from Taylor, partially offset by unrealized gains on risk management contracts and a one-time write-off of costs related to the deferred Noel project in 2007. Net revenue was $2.8 million for the first nine months of 2008 compared to $5.1 million for the same period in 2007. The decrease was due to $1.8 million lower investment income from Taylor, lower interest income and lower unrealized gain on risk management contracts. Operating and administrative expense was $29.8 million in the first nine months of 2008 compared to $22.8 million for the same period in 2007. The increase was due to the Taylor acquisition and the charge related to project development costs reported in second quarter 2008, as well as general escalating costs, partially offset by a write-off of costs related to the deferred Noel project in 2007. Amortization expense for 2008 was similar to 2007. Corporate Outlook The operating loss for 2008 is expected to be higher than in 2007 due primarily to the acquisition of Taylor and activities to support AltaGas' growth strategy. In 2007 Taylor recorded approximately $8 million in corporate costs on a normalized basis. AltaGas has identified approximately $2 million in cost savings, which is expected to be realized in 2008. The segment's revenue will decrease as AltaGas no longer reports investment income from its investment in Taylor in the Corporate segment. Revenue is also expected to decrease due to a reduction in ownership of AltaGas Utility Group Inc. (Utility Group) from 26.7 percent to 19.6 percent. 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 drivers and management is therefore unable to predict the impact of financial instruments. However, the impact of the accounting standards is expected to be relatively low as the Trust uses financial instruments to manage exposure to commodity price fluctuations and to buy and sell gas and power with locked-in margins. The Trust does not execute financial instruments for speculative purposes. INVESTED CAPITAL During third quarter 2008 AltaGas acquired capital assets, long-term investments and other assets of $99.8 million compared to $12.3 million in third quarter 2007. The increase was mainly due to the acquisition of NovaGreen and the remaining 45 percent of GEDLP. In third quarter 2008 the Trust also sold a wind power development project, reducing net invested capital by $5.2 million. Year-to-date September 30, 2008, AltaGas acquired capital assets, long-term investments and other assets totalling $779.7 million compared to $53.7 million in the nine months ended September 30, 2007 which included Taylor, NovaGreen, GEDLP and Bear Mountain. During the first nine months of 2008, the sale of excess equipment, the power development project and the reduction of the carrying value of the Trust's investment in Taylor prior to the acquisition resulted in a reduction of net invested capital of $62.1 million. /T/ Net Invested Capital - Investment Type Three Months Ended September 30, 2008 Field Extraction Gathering and and Energy Power ($ millions) Transmission Processing Services Generation Corporate Total ---------------------------------------------------------------------------- Invested capital: Capital assets 20.9 6.4 0.3 71.6 1.1 100.3 Long-term investments and other assets - - - (0.3) (0.2) (0.5) ---------------------------------------------------------------------------- 20.9 6.4 0.3 71.3 0.9 99.8 Disposals: Capital assets - - - (5.2) - (5.2) ---------------------------------------------------------------------------- Net invested capital 20.9 6.4 0.3 66.1 0.9 94.6 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Net Invested Capital - Investment Type Nine Months Ended September 30, 2008 Field Extraction Gathering and and Energy Power ($ millions) Transmission Processing Services Generation Corporate Total ---------------------------------------------------------------------------- Invested capital: Capital assets 592.5 51.9 (0.2) 125.5 4.7 774.4 Long-term investments and other assets - - - 4.9 0.4 5.3 ---------------------------------------------------------------------------- 592.5 51.9 (0.2) 130.4 5.1 779.7 Disposals: Capital assets - (8.7) - (5.2) - (13.9) Long-term investments and other assets - - - - (48.2) (48.2) ---------------------------------------------------------------------------- Net invested capital 592.5 43.2 (0.2) 125.2 (43.1) 717.6 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Net Invested Capital - Investment Type Three Months Ended September 30, 2007 Field Extraction Gathering and and Energy Power ($ millions) Transmission Processing Services Generation Corporate Total ---------------------------------------------------------------------------- Invested capital: Capital assets 0.8 5.6 8.0 5.4 0.5 20.3 Long-term investments and other assets - - - (1.0) (7.0) (8.0) ---------------------------------------------------------------------------- 0.8 5.6 8.0 4.4 (6.5) 12.3 Disposals: Capital assets (0.1) (14.3) - - - (14.4) ---------------------------------------------------------------------------- Net invested capital 0.7 (8.7) 8.0 4.4 (6.5) (2.1) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Net Invested Capital - Investment Type Nine Months Ended September 30, 2007 Field Extraction Gathering and and Energy Power ($ millions) Transmission Processing Services Generation Corporate Total ---------------------------------------------------------------------------- Invested capital: Capital assets 4.8 13.8 8.7 9.3 1.6 38.2 Long-term investments and other assets - - - (0.5) 16.0 15.5 ---------------------------------------------------------------------------- 4.8 13.8 8.7 8.8 17.6 53.7 Disposals: Capital assets (0.4) (15.6) (30.2) - - (46.2) Long-term investments and other assets - - - - - - ---------------------------------------------------------------------------- Net invested capital 4.4 (1.8) (21.5) 8.8 17.6 7.5 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ The Trust categorizes its invested capital into maintenance, growth and administration. Maintenance capital expenditures were $(1.9) million in third quarter 2008 compared to $2.1 million in the same period in 2007 due to the reclassification of asset retirement obligations previously recorded as maintenance capital. Growth capital of $100.3 million was incurred in third quarter 2008 (third quarter 2007 - $11.8 million) which included the acquisition of NovaGreen and GEDLP, construction of Bear Mountain Wind project, various extraction, transmission, and field gathering and processing projects, hydroelectric power projects under development, installation of the new power peaking equipment and the development of the Sarnia storage project. The growth capital has been financed through increased long-term debt. Administrative capital for the third quarter was $1.4 million compared to $(1.6) million in the same period of 2007. Maintenance capital expenditures were $2.5 million in the first nine months of 2008 compared to $5.4 million for the same period in 2007. Growth capital of $772.0 million was expended in the first nine months of 2008 (2007 - $24.6 million) which was largely composed of $592.0 million for the Taylor acquisition, $43.8 million for the Bear Mountain Wind project, $34.4 million for extraction and transmission facilities, $23.1 million for field gathering and processing facilities, $68.5 million for renewable power projects under development, $8.2 million on the installation of the new power peaking equipment in the Power Generation segment and $1.9 million for the development of Sarnia storage. Administrative capital expenditures of $5.2 million in the first nine months of 2008 were significantly lower than the $23.7 million recorded in the same period in 2007. The decrease was due to $12.5 million recorded in 2007 as a result of accounting for the Trust's investment in Taylor from the equity to the cost method and reclassying the investment as available for sale and $9.2 million promissory note received from the sale of oil and natural gas production assets in 2007. The growth capital has been financed through increased long-term debt. /T/ Invested Capital - Use (1) Three Months Ended September 30, 2008 Field Extraction Gathering and and Energy Power ($ millions) Transmission Processing Services Generation Corporate Total ---------------------------------------------------------------------------- Invested capital: Maintenance (3.1) 1.2 - - - (1.9) Growth 24.0 4.7 0.3 71.3 - 100.3 Administrative - 0.5 - - 0.9 1.4 ---------------------------------------------------------------------------- Invested capital 20.9 6.4 0.3 71.3 0.9 99.8 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Certain maintenance and growth capital expenditures have been reclassed between segments. Invested Capital - Use Nine Months Ended September 30, 2008 Field Extraction Gathering and and Energy Power ($ millions) Transmission Processing Services Generation Corporate Total ---------------------------------------------------------------------------- Invested capital: Maintenance 1.5 1.0 - - - 2.5 Growth 591.0 48.8 (0.3) 130.4 2.1 772.0 Administrative - 2.1 0.1 - 3.0 5.2 ---------------------------------------------------------------------------- Invested capital 592.5 51.9 (0.2) 130.4 5.1 779.7 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Invested Capital - Use Three Months Ended September 30, 2007 Field Extraction Gathering and and Energy Power ($ millions) Transmission Processing Services Generation Corporate Total ---------------------------------------------------------------------------- Invested capital: Maintenance 0.7 1.4 - - - 2.1 Growth (0.1) 3.7 8.0 4.4 (4.2) 11.8 Administrative - 0.5 - - (2.1) (1.6) ---------------------------------------------------------------------------- Invested capital 0.6 5.6 8.0 4.4 (6.3) 12.3 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Invested Capital - Use Nine Months Ended September 30, 2007 Field Extraction Gathering and and Energy Power ($ millions) Transmission Processing Services Generation Corporate Total ---------------------------------------------------------------------------- Invested capital: Maintenance 1.4 4.0 - - - 5.4 Growth 3.4 8.9 8.1 8.8 (4.6) 24.6 Administrative - 0.9 0.6 - 22.2 23.7 ---------------------------------------------------------------------------- Invested capital 4.8 13.8 8.7 8.8 17.6 53.7 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ 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 and E&T segments and with respect to interest rates on debt. During the three-month period ended September 30, 2008, the Trust had positions in the following types of derivatives: - Commodity forward contracts: The Trust executes gas, power, and other commodity forward contracts to manage its asset portfolio and lock-in margins 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. The Alberta Power Pool settles power prices on an hourly basis and prices ranged from $7.60/MWh to $999.99/MWh in third quarter 2008. The average spot price was $80.36/MWh for the third quarter 2008 and $88.21/MWh for the nine months ended September 30, 2008. AltaGas moderated the impact of this volatility on its business through the use of financial hedges on a portion of its power portfolio that management deemed optimal. The average price received for power by the Trust was $83.10/MWh in the third quarter 2008 and $83.57/MWh for the nine months ended September 30, 2008. - NGL frac spread hedges: The Trust executes fixed-for-floating frac spread swaps to manage its NGL frac spreads. The Extraction and Transmission segment's results are affected by fluctuations in frac spreads. At September 30, 2008, the Trust had NGL frac spread agreements for 2,800 Bbls/d at an approximate average price of $23/Bbl for the October to December 2008 period. The Trust has also entered into three NGL frac spread agreements for calendar year 2009 for a total of 2,800 Bbls/d and 2010 for a total of 700 Bbls/d at an average frac spread of approximately $27/Bbl. The average spot frac spread was $36.92/Bbl for the third quarter 2008 and $31.75/Bbl for the nine months ended September 30, 2008. The average frac spread received was $26.02/Bbl and $26.55/Bbl in the three and nine months ended September 30, 2008 respectively. - Interest rate forward contracts: The Trust enters into interest rate swaps where cash flows of a fixed rate are exchanged for those of a floating rate. At September 30, 2008 the Trust had interest rate swaps with varying terms to maturity of $205 million. Including AltaGas' MTNs and capital leases, the rate was fixed on 77 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 and option agreements where an option to transact foreign currency at a future date is purchased or sold. The fair value of power, natural gas and NGL derivatives was calculated using estimated forward prices from published sources for the relevant period. The calculation of fair value of the interest rate derivatives used quoted market rates. The fair value of long-term debt has been estimated based on discounted future interest and principal payments using estimated interest rates. The Trust does not speculate on commodity prices, and therefore does not engage in any commodity transactions that create incremental exposure or are based solely on expectations of future energy market price movements. Commodity transactions are used to lock in margins, optimize underlying physical assets or to reduce exposure to energy price movements. AltaGas has a risk group which reviews commodity and credit risk on a daily basis and has created and adheres to a conservative risk policy and hedging program. LIQUIDITY AND CAPITAL RESOURCES The Trust historically has used debt and equity financing when funds from operations and proceeds from the Distribution Reinvestment Plan (DRIP) were insufficient to fund capital expenditures, acquisitions and working capital changes from operating activities. Should larger investments 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 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 distributions effective in the 2011 taxation year. /T/ Cash Flows Three Months Ended Nine Months Ended September 30 September 30 ($ millions) 2008 2007 2008 2007 ---------------------------------------------------------------------------- Cash from operations 50.4 30.8 167.7 123.5 Investing activities (65.5) (8.9) (396.0) (35.9) Financing activities 23.7 (21.8) 237.2 (88.5) ---------------------------------------------------------------------------- Change in cash 8.6 0.1 8.9 (0.9) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ Cash from Operations Cash from operations reported on the Consolidated Statements of Cash Flows increased by 64 percent to $50.4 million in third quarter 2008 from $30.8 million in the same period 2007. Cash from operations increase was mainly due to higher earnings and decrease in net change in working capital. /T/ Working Capital September 30 September 30 ($ millions) 2008 2007 ---------------------------------------------------------------------------- Current assets 357.9 275.4 Current liabilities 357.5 247.8 ---------------------------------------------------------------------------- Working capital 0.4 27.6 Current ratio 1.0 1.1 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ Working capital was $0.4 million at the end of third quarter 2008 compared to $27.6 million at September 30, 2007. The working capital ratio was 1.0 for the end of third quarter 2008 and 1.1 for the same quarter in 2007. Investing Activities Cash used for investing activities in third quarter 2008 was $65.5 million compared to $8.9 million in the same period in 2007. The increase in cash used for investing activities was due to the acquisition of NovaGreen, increased ownership of GEDLP and expenditures for other assets and capital assets in 2008. Cash used for investing activities reflects the actual cash disbursed for investing activities and may not agree to the amounts in the invested capital sections of the MD&A due to the timing of the actual disbursement of funds and the fact that some acquisitions may be non-cash transactions. Financing Activities Cash from financing activities in third quarter 2008 was $23.7 million compared to cash used of $21.8 million in the same period in 2007. The increase was primarily due to $59.2 million of net increase in long-term debt and higher distributions paid, offset by proceeds from equity issuance under the DRIP. Capital Resources The use of debt or equity funding is based on AltaGas' capital structure which is determined by considering the norms and risks associated with each of its business segments. At September 30, 2008 AltaGas had total debt outstanding of $556.7 million, up from $220.7 million as at December 31, 2007. At September 30, 2008 the Trust had $200.0 million in MTNs outstanding and had access to prime loans, bankers' acceptances and letters of credit through bank lines totalling $750.0 million. At September 30, 2008 the Trust had drawn bank debt of $332.5 million and letters of credit outstanding of $63.9 million. The Trust acquired convertible debentures at a face value of $22.1 million through the Taylor acquisitions. In the nine months ended September 30, 2008, $1.8 million were converted into Trust units. The fair value of the outstanding convertible debentures at September 30, 2008 was $17.2 million, which had a face value of $16.7 million. All of the borrowing facilities have financial tests and other covenants customary for these types of facilities, which must be met at each quarter end. AltaGas has been in compliance with these covenants each quarter since the establishment of the facilities. AltaGas' target debt-to-total capitalization ratio is 40 to 45 percent. The Trust's debt-to-total capitalization ratio at September 30, 2008 was 37.5 percent, up from 27.4 percent at December 31, 2007 and up from 36.4 percent at end of second quarter 2008. The Trust's earnings interest coverage for the rolling 12 months ended September 30, 2008 was 6.7 times. On April 3, 2008 the Trust filed a prospectus supplement to the Short Form Base Shelf prospectus dated August 8, 2007. The supplement establishes AltaGas' MTN program and allows AltaGas to access the Canadian MTN market when appropriate. CONTRACTUAL OBLIGATIONS There have been no material changes to AltaGas' contractual obligations from those included in the MD&A in the Trust's 2007 Annual Report. RELATED PARTIES The Trust sold $9.0 million of natural gas to, and incurred transportation costs of $0.1 million charged by, Utility Group in third quarter 2008 as part of the Trust's normal course of business. The Trust also paid management fees of $0.1 million to, and received management fees of $0.1 million, from Utility Group for administrative services. In addition, the Trust provided $0.1 million of operating services to Utility Group. The measurement of transactions between AltaGas and Utility Group is exchange value, to which both parties have agreed. The Trust holds significant influence over Utility Group as AltaGas' Chairman and Chief Executive Officer is a director of Utility Group. The Trust pays rent under a lease for office space and equipment to 2013761 Ontario Inc., which is owned by an employee. Payments of $21,900 were made in third quarter 2008 (third quarter 2007 - $21,171) which is the exchange value of the property agreed to by both parties. The lease expires at the end of 2008. /T/ SUMMARY OF CONSOLIDATED RESULTS FOR THE EIGHT MOST RECENT QUARTERS ($ millions) Q3-08 Q2-08 Q1-08 Q4-07 Q3-07 Q2-07 Q1-07 Q4-06 ---------------------------------------------------------------------------- Net revenue(1) 122.7 117.3 110.7 76.4 88.2 80.1 79.3 84.6 Operating income(1) 50.7 37.0 47.6 28.9 37.5 31.2 29.0 32.0 Net income 53.5 32.9 37.6 31.8 31.4 21.1 24.6 27.3 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- ($ per unit) Q3-08 Q2-08 Q1-08 Q4-07 Q3-07 Q2-07 Q1-07 Q4-06 ---------------------------------------------------------------------------- Net income Basic 0.75 0.49 0.58 0.55 0.54 0.37 0.43 0.49 Diluted 0.75 0.49 0.57 0.55 0.54 0.37 0.43 0.49 Distributions declared(2) 0.535 0.525 0.525 0.525 0.52 0.51 0.51 0.51 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Non-GAAP financial measure. See Non-GAAP Financial Measures in this MD&A. (2) Excludes the special distribution issuance of one common share of Utility Group for every 100 trust units held on August 27, 2007, valued at $0.076 per unit. /T/ 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; higher frac spreads and asset dispositions. Significant items that impacted individual quarterly earnings were as follows: - In fourth quarter 2006 the Trust reported a $0.6 million goodwill impairment and deferred $0.8 million in revenue in the transmission business. - In second quarter 2007 the Trust recorded a $6.5 million future tax expense as a result of new tax legislation included in Bill C-52, SIFT, 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. - In fourth quarter 2007 a $6.1 million non-cash future income tax benefit was recorded as a result of the substantive enactment of a reduction in the federal corporate income tax rates. - In first quarter 2008 the Taylor acquisition was completed for total consideration of $455.2 million, of which $256.3 million was cash consideration and $198.9 million was for units issued. Results in first quarter 2008 increased as a result of the Taylor acquisition. - Third quarter 2008 included a $1.4 million pre-tax gain on the sale of a development power project. - In third quarter 2008, AltaGas recognized an income tax recovery of $13.8 million related to reduced future income tax liability due to lower effective tax rates resulting from the reorganization of legal entities within the Trust's structure. Improved Standard & Poor's Outlook In July 2008 Standard & Poor's (S&P) changed its outlook for the Trust from stable to positive, citing the smooth integration of Taylor assets into the AltaGas operations, AltaGas' commitment to preserving an acceptable balance sheet and the continued use of sound risk management policies applied to the power business and commodity exposures as reasons for the increased outlook. Improved Dominion Bond Rating Service Trend In September 2008 Dominion Bond Rating Service (DBRS) changed its trend for the Trust from stable to positive, citing the smooth integration of Taylor assets into the AltaGas operations, AltaGas' commitment to preserving an acceptable balance sheet and progress made in diversifying its earnings and cash flow as reasons for the increased trend. TRUST UNIT INFORMATION Under the terms of the restructuring of AltaGas into an income trust effective May 1, 2004, AltaGas Services Inc. (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 October 31, 2008 the Trust had 69.3 million trust units and 2.2 million exchangeable units outstanding and a market capitalization of $1.4 billion based on a closing trading price on October 31, 2008 of $19.25 per trust unit. At October 31, 2008 there were 1.6 million options outstanding and 489,409 options exercisable under the terms of the unit option plan. DISTRIBUTIONS AltaGas distributions are determined giving consideration to the ongoing sustainable cash flow as impacted by the consolidated net income, maintenance and growth capital and debt repayment requirements of the Trust. AltaGas has been able to sustain its distributions through cash from operations. In the three months ended September 30, 2008 the Trust declared distributions of $38.0 million compared to cash from operations of $50.4 million (same period 2007 - $30.0 million and $30.8 million respectively). In the nine months ended September 30, 2008 the Trust declared distributions of $108.3 million compared to cash from operations of $167.7 million (same period 2007 - $88.2 million and $123.5 million respectively). AltaGas has a target payout ratio of 65 to 75 percent of funds from operations. In second quarter 2008 AltaGas announced that the Board of Directors of AltaGas General Partner Inc., delegate of the Trustee, increased its monthly cash distribution to $0.18 per unit ($2.16 per unit annualized) from $0.175 per unit ($2.10 per unit annualized) commencing with September 15, 2008 distribution. This was AltaGas' fifth distribution increase since converting to a trust in May 2004, which together represent a 20 percent increase since inception. /T/ The following table summarizes AltaGas' distribution declaration history since 2006: Distributions ($ per unit) 2008 2007 2006 ---------------------------------------------------------------------------- First quarter 0.525 0.510 0.485 Second quarter 0.525 0.510 0.495 Third quarter 0.535 0.520 0.505 Fourth quarter - 0.525 0.510 Distribution of shares(1) - 0.076 - ---------------------------------------------------------------------------- 1.585 2.141 1.995 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) On September 17, 2007 one share of Utility Group was issued for every 100 trust units and exchangeable units held on August 27, 2007. /T/ CHANGES IN ACCOUNTING POLICIES 2008 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 and has been applied to the Trust beginning January 1, 2008. Section 3031 Inventories Effective for interim and annual financial statements for fiscal years beginning on or after January 1, 2008, the new CICA Handbook Section 3031 "Inventories" provides guidance on the determination of costs and its subsequent recognition as an expense, including any write-down to net realizable value. This new section is effective and has been applied to 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 replaced 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. Future Accounting Changes Section 3064 Goodwill and Intangible Assets Effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2008, the new CICA Handbook Section 3064 will replace Section 3062 "Goodwill and Other Intangible Assets" and Section 3450 "Research and Development Costs". This section establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets including internally generated intangible assets. This new section is effective for the Trust beginning January 1, 2009. The Trust does not expect any financial impact as a result of this new CICA Handbook section. International Financial Reporting Standards (IFRS) In 2006 the Accounting Standards Board announced a new strategic plan for the convergence of Canadian GAAP with IFRS beginning 2011. A high-level diagnostic has been completed assessing the areas likely to have an impact of IFRS financial statements. This impact cannot be reasonably estimated at this time. AltaGas has developed an IFRS project charter identifying a steering committee and several standard specific work groups and work streams. The steering committee is made up of members of senior management and is charged with monitoring the progress and making critical decisions related to the transition to IFRS. AltaGas has established a team that is currently performing a detailed assessment of the differences between AltaGas' current accounting standards and IFRS. SIGNIFICANT ACCOUNTING POLICIES AltaGas' significant accounting policies remain unchanged from December 31, 2007, except as disclosed in the notes to the interim Consolidated Financial Statements for the three months and nine months ended September 30, 2008. For further information regarding these policies refer to the notes to the audited Consolidated Financial Statements in AltaGas' 2007 Annual Report. CRITICAL ACCOUNTING ESTIMATES Since a determination of the value of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of the Trust's interim Consolidated Financial Statements requires the use of estimates and assumptions which have been made using careful judgment. AltaGas' significant accounting policies are described in the notes to the interim Consolidated Financial Statements for the three and nine months ended September 30, 2008 and in the notes to the 2007 audited Consolidated Financial Statements included in the Trust's 2007 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' 2007 Annual Report and the notes to the interim Consolidated Financial Statements for the three and nine months ended September 30, 2008. OFF-BALANCE-SHEET ARRANGEMENTS The Trust is not party to any contractual arrangement under which an unconsolidated entity may have any obligation under certain guarantee contracts, a retained or contingent interest in assets transferred to an unconsolidated entity or similar arrangement that serves as credit, liquidity or market risk support to that entity for such assets. The Trust has no obligation under derivative instruments, or a material variable interest in an unconsolidated entity that provides financing, liquidity, market risk or credit risk support or engages in leasing, hedging or research and development services with the Trust. DISCLOSURE CONTROLS AND PROCEDURES The Trust maintains disclosure controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under applicable securities legislation is accumulated and communicated to management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. INTERNAL CONTROLS OVER FINANCIAL REPORTING Management of the Trust is responsible for establishing and maintaining internal controls over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be designed effectively can provide only reasonable assurance with respect to financial statement preparation and presentation. During third quarter 2008 there were no material changes to the Trust's internal controls over financial reporting. Effectiveness testing of key internal controls are currently in progress in response to the amended continuous disclosure requirements under National Instrument 51-109 as issued by the Canadian Securities Administrators. /T/ Consolidated Balance Sheets (unaudited) September 30 December 31 ($ thousands) 2008 2007 ---------------------------------------------------------------------------- ASSETS Current assets Cash and cash equivalents $ 21,337 $ 12,451 Accounts receivable 198,267 191,879 Inventory 574 130 Customer deposits 24,532 24,369 Risk management (note 11) 106,399 66,811 Other current assets 6,792 9,714 ---------------------------------------------------------------------------- 357,901 305,354 Capital assets (note 6) 1,401,840 682,322 Energy arrangements, contracts and relationships (note 7) 141,404 95,716 Goodwill 148,288 18,260 Risk management (note 11) 42,415 33,640 Long-term investments and other assets 21,644 64,509 ---------------------------------------------------------------------------- $ 2,113,492 $ 1,199,801 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- LIABILITIES AND UNITHOLDERS' EQUITY Current liabilities Accounts payable and accrued liabilities $ 191,927 $ 177,802 Distributions payable to unitholders 12,841 10,167 Short-term debt 145 3,551 Current portion of long-term debt (note 8) 1,355 1,234 Customer deposits 24,532 24,369 Deferred revenue 2,777 1,718 Risk management (note 11) 103,933 60,848 Other current liabilities 20,023 9,321 ---------------------------------------------------------------------------- 357,533 289,010 Long-term debt (note 8) 538,505 215,949 Asset retirement obligations 40,532 18,811 Future income taxes 194,121 58,229 Risk management (note 11) 32,748 30,166 Convertible debentures (note 9) 16,717 - Other long-term liabilities 5,512 2,948 ---------------------------------------------------------------------------- 1,185,668 615,113 Unitholders' equity (notes 12 and 13) 927,824 584,688 ---------------------------------------------------------------------------- $ 2,113,492 $ 1,199,801 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- See accompanying notes to the Consolidated Financial Statements. Consolidated Statements of Income and Accumulated Earnings (unaudited) Three months ended Nine months ended ($ thousands except per unit September 30 September 30 amounts) 2008 2007 2008 2007 ---------------------------------------------------------------------------- REVENUE Operating $ 457,168 $ 320,165 $1,389,462 $1,086,841 Unrealized gain on risk management (note 11) 3,654 1,142 1,386 1,617 Other (120) 762 1,390 3,454 ---------------------------------------------------------------------------- 460,702 322,069 1,392,238 1,091,912 ---------------------------------------------------------------------------- EXPENSES Cost of sales 338,042 233,896 1,041,545 844,351 Operating and administrative 54,593 39,073 165,187 114,148 Amortization: Capital assets 14,835 9,747 42,800 29,986 Energy arrangements, contracts and relationships 2,552 1,903 7,412 5,710 ---------------------------------------------------------------------------- 410,022 284,619 1,256,944 994,195 ---------------------------------------------------------------------------- Interest expense Short-term debt 105 121 311 269 Long-term debt 5,921 2,734 19,032 8,710 ---------------------------------------------------------------------------- Income before income taxes 44,654 34,595 115,951 88,738 Income tax expense (recovery) Current income tax 2,177 - 2,393 - Future income tax (10,977) 3,237 (10,386) 11,747 ---------------------------------------------------------------------------- Net income 53,454 31,358 123,944 76,991 Accumulated earnings, beginning of period 580,902 447,251 510,412 401,618 ---------------------------------------------------------------------------- Accumulated earnings, end of period $ 634,356 $ 478,609 $ 634,356 $ 478,609 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Net income per unit (note 15) Basic $ 0.75 $ 0.54 $ 1.83 $ 1.35 Diluted $ 0.75 $ 0.54 $ 1.81 $ 1.35 Weighted average number of units outstanding (thousands) (notes 13 and 15) Basic 71,138 57,692 67,873 57,188 Diluted 72,042 57,744 68,794 57,227 See accompanying notes to the Consolidated Financial Statements. Consolidated Statements of Comprehensive Income and Accumulated Other Comprehensive Income (unaudited) Three months ended Nine months ended September 30 September 30 ($ thousands) 2008 2007 2008 2007 ---------------------------------------------------------------------------- Net income $ 53,454 $ 31,358 $ 123,944 $ 76,991 Other comprehensive income (loss), net of tax Unrealized net gain (loss) on available for sale financial assets - 889 (17,873) 11,288 Unrealized net gain on derivatives designated as cash flow hedges 15,689 5,688 823 1,602 Reclassification to net income of net gain on derivatives designated as cash flow hedges pertaining to prior periods 4,810 5,858 2,387 2,469 ---------------------------------------------------------------------------- 20,499 12,435 (14,663) 15,359 ---------------------------------------------------------------------------- Comprehensive income $ 73,953 $ 43,793 $ 109,281 $ 92,350 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Accumulated other comprehensive income (loss), beginning of period $ (7,993) $ 290 $ 27,169 - Adjustment resulting from adoption of new financial instrument accounting standards - - - (2,634) Other comprehensive income (loss), net of tax 20,499 12,435 (14,663) 15,359 ---------------------------------------------------------------------------- Accumulated other comprehensive income, end of period $ 12,506 $ 12,725 $ 12,506 $ 12,725 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- See accompanying notes to the Consolidated Financial Statements. Consolidated Statements of Cash Flows (unaudited) Three months ended Nine months ended September 30 September 30 ($ thousands) 2008 2007 2008 2007 ---------------------------------------------------------------------------- Cash from operations Net income $ 53,454 $ 31,358 $ 123,944 $ 76,991 Items not involving cash: Amortization 17,387 11,650 50,212 35,696 Accretion of asset retirement obligations 838 416 1,793 1,266 Unit-based compensation 105 128 300 459 Future income tax expense (recovery) (10,977) 3,237 (10,386) 11,747 (Gain) loss on sale of assets (note 19) (1,407) 1,381 (1,725) (182) Equity (income) loss 165 29 (416) (1,664) Distributions from equity investments 72 232 209 1,490 Unrealized gain on risk management (3,654) (1,142) (1,386) (1,617) Other 300 330 694 877 Asset retirement obligations settled (182) (412) (399) (552) Net change in non-cash working capital (note 16) (5,722) (16,439) 4,875 (1,043) ---------------------------------------------------------------------------- 50,379 30,768 167,715 123,468 ---------------------------------------------------------------------------- Investing activities Increase in customer deposits (517) (3,337) (163) (9,520) Decrease in note receivable 1,000 - 6,500 - Acquisition of capital assets (26,642) (16,197) (110,875) (37,085) Disposition of capital assets 6,589 9,215 15,432 9,722 Acquisition of long-term investments and other assets (45,911) (1,313) (306,916) (2,112) Disposition of long-term investments and other assets - 2,700 - 3,075 ---------------------------------------------------------------------------- (65,481) (8,932) (396,022) (35,920) ---------------------------------------------------------------------------- Financing activities Increase (decrease) in short-term debt (2,154) 1,020 (3,406) 2,865 Net issuance (repayment) of revolving long-term debt 59,226 (1,703) 212,892 (138,816) Issuance of long-term debt (207) - (207) 100,000 Repayment of long-term debt (4,636) - (5,369) - Distributions to unitholders (37,666) (29,845) (105,732) (87,655) Net proceeds from issuance of units 9,091 8,696 134,515 35,145 Net proceeds from issuance of warrants (note 12) - - 4,500 - ---------------------------------------------------------------------------- 23,654 (21,832) 237,193 (88,461) ---------------------------------------------------------------------------- Change in cash and cash equivalents 8,552 4 8,886 (913) Cash and cash equivalents, beginning of period 12,785 12,309 12,451 13,226 ---------------------------------------------------------------------------- Cash and cash equivalents, end of period $ 21,337 $ 12,313 $ 21,337 $ 12,313 ---------------------------------------------------------------------------- See accompanying notes to the Consolidated Financial Statements. /T/ Selected Notes to the Consolidated Financial Statements (unaudited) (Tabular amounts in thousands of 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. 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, 2007, except as described below in Notes 3 and 4. These interim Consolidated Financial Statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2007 audited Consolidated Financial Statements included in the Trust's Annual Report. 2. COMPARATIVE FIGURES Certain comparative figures have been reclassified to conform to the current financial presentation. 3. CHANGES IN ACCOUNTING POLICIES Changes For 2008 Effective January 1, 2008 the Trust adopted the new CICA Handbook accounting requirements for Section 1535 "Capital Disclosures", Section 3031 "Inventories", Section 3862 "Financial Instruments - Disclosures" and Section 3863 "Financial Instruments - Presentation". In accordance with the transitional provisions for these new standards, these policies were adopted prospectively without restatement of prior periods. Capital Disclosures 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, which have been provided in note 10. Inventories Inventory consists of materials and supplies and natural gas liquids (NGL) product held for sale. All inventory is valued at the lower of cost and net realizable value. Cost is assigned using a weighted average cost formula. Financial Instruments CICA Handbook Section 3862 "Financial Instruments - Disclosures" and Section 3863 "Financial Instruments - Presentation" replace Section 3861 "Financial Instruments - Disclosure and Presentation" effective January 1, 2008 for the Trust. Section 3862 requires the disclosure of information to allow users to evaluate the significance of the financial instruments on the entity's financial position and performance and the nature and extent of risks arising from financial instruments and how the entity manages those risks. Section 3863 deals with the classification of financial instruments, related interest, dividends, losses and gains, and the circumstances in which financial assets and financial liabilities are offset. The additional information to comply with these standards is disclosed in note 11. Future Accounting Changes Section 3064 "Goodwill and Intangible Assets" Effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2008, the new CICA Handbook Section 3064 will replace Section 3062 "Goodwill and Other Intangible Assets" and Section 3450 "Research and Development Costs". This section establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets including internally generated intangible assets. This new section is effective for the Trust beginning January 1, 2009. International Financial Reporting Standards (IFRS) In 2006 the Accounting Standards Board announced a new strategic plan for the convergence of Canadian GAAP with IFRS beginning 2011. A high-level diagnostic has been completed assessing the areas likely to have an impact on IFRS financial statements. This impact cannot be reasonably estimated at this time. AltaGas has developed a project charter identifying a steering committee and several standard specific work groups and work streams. The steering committee is made up of members of senior management and is charged with monitoring the progress and making critical decisions related to the transition to IFRS. AltaGas has established a team that is currently performing a detailed assessment of the differences between AltaGas' current accounting standards and IFRS. 4. UPDATE TO SUMMARY OF ACCOUNTING POLICIES As a result of the acquisition of Taylor NGL Limited Partnership (Taylor) and AltaGas' issuance of warrants, the Trust has updated the following significant accounting policies. Energy Arrangements, Contracts, Relationships and Amortization Energy arrangements, contracts and relationships are recorded at cost, which was fair value at the time of purchase, and are amortized on a straight-line basis over their term or estimated useful life: /T/ Sundance B Power Purchase Arrangements (PPAs) 19 years Natural gas and power marketing contracts 18 - 49 months Energy services relationships 15 years Extraction and transmission (E&T) contracts 10 - 20 years /T/ AltaGas owns 50 percent of two Sundance B PPAs through its interest in the ASTC Power Partnership (ASTC). ASTC is committed to purchase all of the power from the two 353-MW capacity Sundance B generating units. The investment in the PPAs and the corresponding revenue and expenses thereunder are recorded on a proportionate basis. The Sundance B PPAs required a capital outlay to acquire. The Trust is obligated to make payments to the owners of the underlying generating units over the remaining terms of the PPAs to December 31, 2020. Such amounts are recorded as cost of sales as incurred. Revenue from the sale of the committed power is recorded when delivered. The natural gas and power marketing contracts are the rights and obligations to buy and sell fixed volumes of natural gas and power at contracted prices. Revenue and expenses are recorded when product is delivered. Energy services relationships were purchased along with substantially all of the assets and liabilities of iQ2 Power Corp., AltaGas Energy Limited Partnership, ECNG Canada Ltd. and Energistics Group Inc., and are recorded at fair value and amortized on a straight-line basis commencing with the expiration of the related short-term marketing contracts over the 15-year expected useful life of the relationships. The E&T contracts were acquired through the acquisition of Taylor and are recorded at fair value and amortized on a straight-line basis over the average expected life of the contracts. Per Unit Information Basic net income per unit is calculated on the basis of the weighted average number of trust and exchangeable units outstanding during the period. Diluted net income per unit is calculated as if the proceeds obtained upon exercise of options were used to purchase units at the average market price during the period plus the trust units issuable on conversion of outstanding convertible debentures and warrants. Diluted net income is increased by the interest on the convertible debentures and decreased by the accretion on the convertible debentures. Convertible Debentures Convertible debentures are recorded at fair value upon acquisition, less the amount attributed to the conversion feature, which is included as part of unitholders' equity. The difference between the fair value and the principal amount is charged to income on an effective yield basis. Warrants Warrants are recorded at fair value, deemed to be the gross proceeds upon issue and are included as part of unitholders' equity. 5. BUSINESS ACQUISITIONS Acquisition of Taylor NGL Limited Partnership On January 10, 2008 AltaGas Holding Limited Partnership No. 1 (AltaGas LP #1) acquired all of the outstanding limited partnership units of Taylor (other than the Taylor units already owned by AltaGas and its affiliates). Taylor participated in the energy business through ownership of natural gas liquids extraction plants, natural gas processing assets and two natural gas liquids pipelines. It also had an interest in a 7-MW run-of-river hydroelectric generation plant. AltaGas offered Taylor unitholders $11.20 in cash or 0.42 units of AltaGas per unit of Taylor, subject to maximum aggregate limits of $245.0 million in cash and 8.0 million Trust units, including up to approximately 1.9 million exchangeable units. Prior to closing the acquisition, $27.9 million of Taylor convertible debentures were redeemed, increasing Taylor units outstanding by 2.7 million. The aggregate purchase price was $593.6 million, including $256.3 million of cash and 7.7 million Trust units (including 0.2 million exchangeable units) valued at $198.9 million for all the outstanding units not previously owned by AltaGas, assumed debt and convertible debentures of $132.5 million and $5.9 million in transaction costs. The value of the Trust units issued was determined based on the weighted average market price between two days preceding and two days subsequent to November 11, 2007, the date the offer had been agreed upon and announced. The following table summarizes the total consideration and the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition. Any final adjustments may significantly change the allocation of the purchase price and could affect the fair value assigned to assets and liabilities. The preliminary allocation of the purchase price is as follows: /T/ Total consideration for 100% of Taylor Cost of 8.9% investment in Taylor originally owned by AltaGas $ 23,156 Purchase price for the remaining 91.1% of Taylor units Cash consideration 256,281 Units 198,861 Estimated transaction costs 5,884 Equity portion of Taylor convertible debentures 2,127 463,153 ---------------------------------------------------------------------------- Total consideration $ 486,309 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Purchase price allocation for 100% of Taylor Assets acquired Current assets 30,584 Capital assets 592,030 Energy arrangements, contracts and relationships 53,100 Goodwill 125,680 Long-term investments and other assets 4,640 806,034 ---------------------------------------------------------------------------- Less liabilities assumed Current liabilities 27,549 Long-term debt 110,423 Convertible debentures 22,171 Asset retirement obligations 18,741 Future income taxes 135,320 Future employee obligations 2,542 Risk management 2,979 319,725 ---------------------------------------------------------------------------- $ 486,309 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ Until the date of acquisition, AltaGas accounted for its investment in Taylor using the cost method. As a result, the investment in Taylor was designated as available for sale and was measured at fair value with the changes in fair value recorded in other comprehensive income (OCI). As of January 10, 2008 Taylor has been included in AltaGas' Consolidated Financial Statements. AltaGas drew on its available credit facility to finance the cash consideration of $256.3 million for the Taylor acquisition. Acquisition of NovaGreenPower Inc. On July 31, 2008 AltaGas acquired NovaGreenPower Inc. (NovaGreen), a wholly-owned subsidiary of NovaGold Resources Inc., for $35 million on closing with an additional $5 million on completion of certain conditions. NovaGreen was developing the Forrest Kerr run-of-river hydroelectric project in Northwest B.C., which is expected to have capacity of 195 MW. NovaGreen was also pursuing three other development projects all within the same region as Forrest Kerr with an additional potential run-of-river hydroelectric capacity of approximately 130 MW. Acquisition of 45 Percent Interest in GreenWing Energy Development Limited Partnership On August 15, 2008 AltaGas acquired GreenWing Energy Management Ltd.'s 45 percent interest in GreenWing Energy Development Limited Partnership (GEDLP) for $12.3 million. As a result, the Trust now owns 100 percent of GEDLP. /T/ 6. CAPITAL ASSETS September 30 2008 ---------------------------------------------------------------------------- Accumulated Net book Cost amortization value ---------------------------------------------------------------------------- Extraction and Transmission Extraction and transmission assets $ 852,096 $ (64,372) $ 787,724 Field Gathering and Processing Field gathering and processing assets 608,445 (168,453) 439,992 Other assets 6,459 (2,944) 3,515 Energy Services Energy services assets 10,610 (1,128) 9,482 Other assets 917 (417) 500 Power Generation Capital lease (note 8) 13,798 (5,633) 8,165 Power generation assets 142,386 - 142,386 Corporate Other assets 24,001 (13,925) 10,076 ---------------------------------------------------------------------------- $ 1,658,712 $ (256,872) $ 1,401,840 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- December 31 2007 ---------------------------------------------------------------------------- Accumulated Net book Cost amortization value ---------------------------------------------------------------------------- Extraction and Transmission Extraction and transmission assets $ 255,810 $ (46,078) $ 209,732 Field Gathering and Processing Field gathering and processing assets 569,944 (148,297) 421,647 Other assets 4,416 (2,161) 2,255 Energy Services Energy services assets 9,693 (896) 8,797 Other assets 2,018 (156) 1,862 Power Generation Capital lease (note 8) 13,798 (4,596) 9,202 Power generation assets 22,013 - 22,013 Corporate Other assets 19,230 (12,416) 6,814 ---------------------------------------------------------------------------- $ 896,922 $ (214,600) $ 682,322 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ Interest capitalized on long-term capital construction projects for the nine months ended September 30, 2008 was $2.0 million (December 31, 2007 - $0.8 million). At September 30, 2008 the Trust had spent approximately $145.1 million (December 31, 2007 - $42.6 million) on capital projects under construction that were not yet subject to amortization. In January 2008 the Trust completed the acquisition of Taylor (note 5), which resulted in the increase to the extraction and transmission and field gathering and processing assets. /T/ 7. ENERGY ARRANGEMENTS, CONTRACTS AND RELATIONSHIPS September 30 2008 ---------------------------------------------------------------------------- Accumulated Net book Cost amortization value ---------------------------------------------------------------------------- Energy services and E&T arrangements and contracts $ 168,171 $ (44,085) $ 124,086 Energy services relationships 20,892 (3,574) 17,318 ---------------------------------------------------------------------------- $ 189,063 $ (47,659) $ 141,404 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- December 31 2007 ---------------------------------------------------------------------------- Accumulated Net book Cost amortization value ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Energy services and E&T arrangements and contracts $ 115,071 $ (37,717) $ 77,354 Energy services relationships 20,892 (2,530) 18,362 ---------------------------------------------------------------------------- $ 135,963 $ (40,247) $ 95,716 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- The amortization of the energy services relationships began in 2006 upon expiration of the corresponding short-term marketing contracts. In January 2008 the Trust completed the acquisition of Taylor (note 5), which resulted in the majority of additions since December 31, 2007. 8. LONG-TERM DEBT September 30 December 31 2008 2007 ---------------------------------------------------------------------------- Operating loans $ 332,500 $ 8,000 Medium-term notes 200,000 200,000 Capital lease obligations 9,119 10,034 Other long-term debt 1,344 - Unamortized deferred financing (3,103) (851) ---------------------------------------------------------------------------- 539,860 217,183 Less current portion 1,355 1,234 ---------------------------------------------------------------------------- $ 538,505 $ 215,949 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ Operating Loans At September 30, 2008 the Trust held a $375.0 million (December 31, 2007 - $300.0 million) unsecured extendible revolving three-year credit facility with a syndicate of Canadian chartered banks. Borrowings on the facility can be by way of prime loans, U.S. base rate loans, LIBOR loans, bankers' acceptances or documentary credits. Borrowings on the facility have fees and interest at rates relevant to the nature of the draw. On September 30, 2007 AltaGas negotiated the extension of the maturity date of this facility to September 30, 2010. On March 31, 2008 the Trust negotiated a new $250.0 million unsecured 18-month credit facility with a syndicate of Canadian chartered banks. Borrowings on the facility can be by way of prime loans, U.S. base rate loans, LIBOR loans or bankers' acceptances. Borrowings on the facility bear fees and interest rates relevant to the nature of the draw and the facility matures on September 28, 2009. At September 30, 2008 the Trust had drawn $332.5 million (December 31, 2007 - $8.0 million) against the facilities. The prime lending rate at September 30, 2008 was 4.75 percent (December 31, 2007 - 6.0 percent). The average rate on the Trust's bankers' acceptances at September 30, 2008 was 4.2 percent (December 31, 2007 - 5.2 percent). Medium-Term Notes On August 30, 2005 $100.0 million of 4.41 percent senior unsecured medium-term notes (MTNs) were issued. The notes mature on September 1, 2010, with interest payable semi-annually. On January 19, 2007 AltaGas issued a further $100.0 million of senior unsecured MTNs. The notes carry a coupon rate of 5.07 percent and mature on January 19, 2012. Letter of Credit Facility At September 30, 2008 the Trust held a $75.0 million (December 31, 2007 - $75.0 million) unsecured three-year extendible revolving-term letter of credit facility with a Canadian chartered bank maturing on September 30, 2010. AltaGas may borrow up to $25.0 million by way of prime loans, U.S. base rate loans, LIBOR loans or bankers' acceptances on the letter of credit facility. Borrowings on the facility bear fees and interest at rates relevant to the nature of the draw made. At September 30, 2008 the Trust had letters of credit of $61.1 million (December 31, 2007 - $61.7 million) outstanding against the extendible revolving-term letter of credit facility. 9. CONVERTIBLE DEBENTURES On January 10, 2008 AltaGas assumed a principal amount of $22.1 million of 5.85 percent convertible debentures through the acquisition of Taylor. The debentures mature on September 10, 2010, with interest payable semi-annually on September 10 and March 10 of each year. Prior to maturity, the debentures may be converted into trust units at the option of the holder at a conversion price of $24.64 per trust unit. The Trust may redeem the convertible debentures after September 10, 2008 and prior to September 10, 2009 in whole or in part at a price equal to their principal amount plus accrued and unpaid interest, if any, provided the current market price of the trust units on the date notice is given is not less than 125 percent of the conversion price, subject to adjustment in certain events. After September 10, 2009 and prior to the convertible debentures' maturity, the Trust may redeem the convertible debentures at a price equal to their principal amount plus accrued and unpaid interest, if any. The Trust can elect to pay interest on the debentures by issuing trust units. /T/ ---------------------------------------------------------------------------- Balance, December 31, 2007 $ - Fair value of convertible debentures (note 5) 22,171 Accretion (13) Conversion to Trust units (1,287) Redeemed for cash (4,154) ---------------------------------------------------------------------------- Balance, September 30, 2008 $ 16,717 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ 10. CAPITAL DISCLOSURE The Trust's objective for managing capital is to maintain its investment-grade credit ratings and allow the Trust to maximize the profitability of its existing assets and grow its energy infrastructure to create long-term value and enhance returns for its investors. The Trust considers Unitholders' Equity (including Accumulated Other Comprehensive Income), short-term and long-term debt (including current portion) less cash and cash equivalents to be part of its capital structure. The Trust's overall strategy remains unchanged from 2007. The use of debt or equity funding is based on AltaGas' capital structure, which is determined by considering the norms and risks associated with each of its business segments. AltaGas' target debt-to-total-capitalization ratio is 40 to 45 percent. The Trust's debt-to-total capitalization ratio as at September 30, 2008 was 37.5 percent (December 31, 2007 - 27.4 percent). All of the borrowing facilities have financial tests and other covenants customary for the types of facilities which must be met at each quarter-end. AltaGas has been in compliance with these covenants each quarter since the issuance of the facilities. 11. 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. Fair Values of Financial Instruments At September 30, 2008 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, natural gas and NGL derivatives was calculated using estimated forward prices from published sources for the relevant period. The calculation of fair value of the interest rate and foreign exchange derivatives used quoted market rates. The fair value of long-term debt has been estimated based on discounted future interest and principal payments using estimated interest rates. The fair value of the convertible debentures was estimated using a Black Scholes model. The carrying amount and fair values of the Trust's financial assets and liabilities were as follows: /T/ Summary of Fair Values September 30 December 31 2008 2007 Carrying Carrying ($ thousands) amount Fair value amount Fair value ---------------------------------------------------------------------------- Financial assets Held for trading Cash and cash equivalents(1) $ 21,337 $ 21,337 $ 12,451 $ 12,451 Risk management - derivatives(2) 121,134 121,134 83,200 83,200 Cash flow hedges Risk management(2) 27,680 27,680 17,251 17,251 Loans and receivables Accounts receivable and other assets(1) (3) 196,757 196,757 194,936 194,936 Customer deposits(1) 24,532 24,532 24,369 24,369 Available for sale Long-term investments and other assets - - 44,746 44,746 ---------------------------------------------------------------------------- $ 391,440 $ 391,440 $ 376,953 $ 376,953 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Financial liabilities Held for trading Risk management - derivatives(2) $ 126,327 $ 126,327 $ 86,799 $ 86,799 Cash flow hedges Risk management(2) 10,355 10,355 4,215 4,215 Other financial liabilities Accounts payable and other liabilities(1) (4) 206,661 206,661 185,943 185,943 Customer deposits(1) 24,532 24,532 24,369 24,369 Short-term debt 145 145 3,551 3,551 Long-term debt(5) 542,963 534,970 218,033 208,036 Convertible debentures 16,717 17,239 - - ---------------------------------------------------------------------------- $ 927,700 $ 920,229 $ 522,910 $ 512,913 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Due to the nature and/or short maturity of these financial instruments the carrying amount approximates the fair value. (2) Fair value is equal to the carrying value for derivatives and hedged items. (3) Excludes income and sales tax of $8,301 (December 31, 2007 - $6,656). (4) Excludes income and sales tax and deferred revenue of $5,288 (December 31, 2007 - $1,180). (5) Includes current portion of long-term debt and excludes deferred financing costs of $3,103 (December 31, 2007 - $850). Summary of Unrealized Gain (Loss) on Risk Management Three months ended Nine months ended September 30 September 30 ($ thousands) 2008 2007 2008 2007 ---------------------------------------------------------------------------- Natural gas $ 3,982 $ 625 $ 4,810 $ 1,535 Natural gas liquids 5,630 227 4,029 227 Power (431) 28 (360) (37) Heat rate - - (188) - Interest rate swaps (972) 311 (1,629) 312 Foreign exchange (4,555) (49) (5,276) (420) ---------------------------------------------------------------------------- Total $ 3,654 $ 1,142 $ 1,386 $ 1,617 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ Market Risk on Financial Instruments The Trust is exposed to market risk and potential loss from changes in the values of financial instruments. AltaGas enters into financial derivative contracts to manage exposure to fluctuations in commodity prices, interest rates and foreign exchange rates. 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 2013. The Trust had the following contracts outstanding: /T/ As at September 30, 2008 Notional volume (GJ) ---------------------- Derivative Fixed price Period Instruments (per GJ) (months) Sales Purchases Fair value ---------------------------------------------------------------------------- Commodity forward $2.22 to $10.37 1 - 61 93,763,915 - $ 579 Commodity forward $2.22 to $10.37 1 - 61 - 93,763,915 $ 1,209 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- As at December 31, 2007 Notional volume (GJ) ---------------------- Derivative Fixed price Period Instruments (per GJ) (months) Sales Purchases Fair value ---------------------------------------------------------------------------- Commodity forward $2.16 to $10.37 1 - 55 105,375,003 - $ (17,775) Commodity forward $2.16 to $10.37 1 - 55 - 105,375,003 $ 14,754 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ In third quarter 2008 the Trust recognized an unrealized gain of $4.0 million (September 30, 2007 - $0.6 million) from the Trust's natural gas risk management activities. Natural Gas Liquids The Trust entered into a series of swaps to lock in a portion of the volumes exposed to NGL frac spread. The Trust had the following contracts outstanding: /T/ As at September 30, 2008 Notional volume ----------------- Period Product Fixed price (months) Sales Purchases Fair value ---------------------------------------------------------------------------- Propane $1.2825 to $1.8000 42,079,884 US/gallon 1 - 27 gallons - $ 7,876 Butane $1.4950 to $2.3000 US/gallon 13,369,896 1 - 27 gallons - $ 5,026 WTI $83.20 to $144.65 165,252 US/Bbl 1 - 27 Bbls - $ 1,413 Natural gas $6.54 to $9.95/GJ 1 - 27 - 5,745,064GJ $ (7,918) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- As at December 31, 2007 Notional volume ----------------- Period Product Fixed price (months) Sales Purchases Fair value ---------------------------------------------------------------------------- Propane $1.2825 to $1.4725 9,677,178 US/gallon 1 - 12 gallons - $ (1,156) Butane $1.4950 to $1.7000 2,612,064 US/gallon 1 - 12 gallons - $ (685) WTI $83.20 to $89.10 US/Bbl 1 - 12 27,489 Bbls - $ (143) Natural gas $6.455 to $6.550/GJ 1 - 12 - 1,382,591GJ $ 159 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ In third quarter 2008 the Trust recognized an unrealized gain of $5.6 million (September 30, 2007 - $0.2 million) from the Trust's NGL risk management activities. Power Under the power purchase arrangements AltaGas has an obligation to buy power at agreed terms and prices to December 31, 2020. The Trust sells the power to the Alberta Electric System Operator at market prices and uses swaps and collars to fix the prices over time on a portion of the volumes. AltaGas' strategy is to lock in margins to provide predictable earnings. Certain contracts met the expected purchase, sale or usage requirements exception and have not been included in risk management assets or liabilities. At September 30, 2008 the Trust had no intention to terminate any contracts prior to maturity. /T/ The Trust had no commodity forward contracts outstanding at September 30, 2008. As at December 31, 2007 Notional volume (MWh) ---------------------- Derivative Fixed price Period Instruments (per MWh) (months) Sales Purchases Fair value ---------------------------------------------------------------------------- Commodity forward $ 79.00 to $80.60 1 - 3 2,160 - $ (28) Commodity forward $ 63.25 to $68.00 1 - 3 - 2,160 $ 31 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- The Trust had the following commodity swaps and collars outstanding: As at September 30, 2008 Notional volume (MWh) ---------------------- Derivative Fixed price Period Instruments (per MWh) (months) Sales Purchases Fair value ---------------------------------------------------------------------------- Swaps and collars $ 60.50 to $88.00 1 to 27 1,850,928 - $ 5,787 Swaps and collars $ 56.50 to $77.00 1 to 113 - 266,364 $ 5,260 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- As at December 31, 2007 Notional volume (MWh) ---------------------- Derivative Fixed price Period Instruments (per MWh) (months) Sales Purchases Fair value ---------------------------------------------------------------------------- Swaps and collars $ 65.00 to $88.00 1 to 24 1,626,624 - $ 10,932 Swaps and collars $ 56.50 1 to 120 - 263,016 $ 3,339 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- The Trust's power risk management activities from financial contracts not included in the hedging program had an unrealized loss of $0.4 million in third quarter 2008 (September 30, 2007 - $28,018). The Trust had no heat rate hedges outstanding at September 30, 2008. As at December 31, 2007 Notional volume (GJ or MWh) ----------------------------------- Derivative Fixed price Period Instruments (per GJ or MWh) (months) Sales Purchases Fair value ---------------------------------------------------------------------------- Natural gas (per GJ) $ 6.08 to $6.17 1 - 79,050 $ 17,968 Power (per MWh) $ 89.00 to $138.00 1 6,510 - $ 170,019 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ In third quarter 2008 the Trust recognized no unrealized gain or loss (September 30, 2007 - nil) from heat rate hedging activities. 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. The Trust's target is to have approximately 70 to 75 percent of its debt at fixed interest rates. /T/ The Trust had the following interest rate swaps outstanding: As at Weighted September 30, average Period 2008 interest rate (months) Notional quantity Fair value ---------------------------------------------------------------------------- Swaps 3.746% 3 to 18 $ 205,000 $ (1,546) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- As at Weighted December 31, average Period 2007 interest rate (months) Notional quantity Fair value ---------------------------------------------------------------------------- Swaps 3.56% 2 to 15 $ 25,000 $ 165 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ At September 30, 2008 the Trust's interest rate risk management activities resulted in an unrealized loss of $1.0 million (September 30, 2007 - $0.3 million). 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 forwards, swaps and options. /T/ The Trust had the following contracts outstanding: As at September 30, Period 2008 Fixed price (months) Notional quantity Fair value ---------------------------------------------------------------------------- Swaps (USD)(1) $ 0.9268 to $1.0262 1 to 27 $ 92,920 $ (4,984) Forwards and options (Euro) $ 1.470 - $1.5350 8 to 12 EUR 59,700 $ (637) ---------------------------------------------------------------------------- (1) Related to NGL frac spread contracts. As at December 31, Period 2007 Fixed price (months) Notional quantity Fair value ---------------------------------------------------------------------------- Swaps (USD)(1) $ 0.9268 to $1.0882 1 to 12 $ 14,968 $ (670) Forwards and options (Euro) $ 1.42 to $1.4436 1 to 3 EUR 11,900 326 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Related to NGL frac spread contracts. /T/ At September 30, 2008 the Trust's foreign exchange risk management activities had an unrealized loss of $4.6 million (September 30, 2007 - $(48,803)). Bond Forward The Trust anticipates issuing a five-year $100 million medium-term note before the end of 2008. To hedge against the risk of rising interest rates, the Trust entered into bond forward contracts with two Canadian chartered banks in August 2008, to lock in a 5-year Government of Canada bond yield of approximately 3.13 percent. At September 30, 2008 the bond forward hedge had a fair market value position of $66,975. Sensitivity Analysis The sensitivity analysis is estimated based on the notional volumes of each commodity, interest rate swap and foreign exchange contract outstanding, taking into consideration future income tax impact. The following table illustrates potential effects of changes in relevant risk variables on AltaGas' net income and OCI for contracts in place at September 30, 2008: /T/ Increase or Increase decrease or Increase or in net decrease Factor Share decrease(1) income in OCI ---------------------------------------------------------------------------- Alberta electricity prices $2/MWh 2 2,296 Natural gas $ 1/GJ 4,412 - Natural gas liquids frac spread: Propane $5/Bbl 499 3,069 Butane $5/Bbl 193 940 WTI $5/Bbl 83 505 Natural gas $ 1/GJ 47 4,036 Interest rate swaps 25 bps 513 - Bond forward 25 bps - 250 Foreign exchange 1% 848 212 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Estimated increase or decrease to forward prices or curves. /T/ Credit Risk on Financial Instruments Credit risk results from the possibility that a counterparty to a financial instrument from which the Trust has an amount owing fails to fulfill its obligations in accordance with the terms of the contract. AltaGas' credit policy details the parameters used to grant, measure, monitor and report on credit provided to counterparties. AltaGas minimizes counterparty risk by conducting credit reviews on counterparties in order to establish specific credit limits on clients, both prior to providing products or services and on a recurring basis. In addition, most contracts include credit mitigation clauses which allow AltaGas to obtain financial or performance assurances from counterparties under certain circumstances. AltaGas provides an allowance for doubtful accounts in the normal course of its business. The Trust's maximum credit exposure consists primarily of the carrying value of the non-derivative financial assets and the fair value of derivative financial assets. At September 30, 2008 AltaGas did not have a significant concentration of credit risk with any single counterparty to financial instruments. Liquidity Risk on Financial Instruments Liquidity risk is the risk that the Trust will not be able to meet its financial obligations as they fall due. The Trust manages this risk through its extensive budgeting and monitoring process to ensure it has sufficient cash and credit facilities to meet its obligations. The Trust's objective is to maintain its investment-grade ratings to ensure it has access to debt and equity funding as required (see note 10). /T/ At September 30, 2008 the Trust had the following contractual maturities with respect to non-derivative financial liabilities: Payments Due by period Total 2008 2009 2010 2011 Thereafter ---------------------------------------------------------------------------- Short-term debt 145 145 - - - - Long-term debt(1)(2) 542,963 381 101,316 333,909 1,508 105,849 Convertible debentures 16,717 - - 16,717 - - ---------------------------------------------------------------------------- Total $ 559,825 $ 526 $ 101,316 $ 350,626 $ 1,508 $ 105,849 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Comprising operating loans, medium-term notes and capital lease obligations excluding deferred financing costs (note 8). (2) Includes current portion of long-term debt. 12. UNITHOLDERS' EQUITY September 30 December 31 2008 2007 ---------------------------------------------------------------------------- Unitholders' capital (note 13) $ 841,403 $ 505,544 Contributed surplus (note 14) 4,174 3,875 Accumulated earnings 634,356 510,412 Convertible debentures 1,603 - Warrants 4,500 - Accumulated dividends (41,114) (41,114) Accumulated unitholders' distributions declared(1) (499,509) (391,103) Distributions of common shares of Utility Group (29,848) (29,848) Transition adjustment resulting from adopting new financial instruments accounting standards (247) (247) Accumulated other comprehensive income 12,506 27,169 ---------------------------------------------------------------------------- $ 927,824 $ 584,688 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Accumulated unitholders' distributions paid by the Trust as at September 30, 2008 were $486.7 million (as at December 31, 2007 -$380.9 million). /T/ In 2007 the holders of trust units of the Trust and holders of exchangeable partnership units of AltaGas Holding Limited Partnership No. 1 received one common share of AltaGas Utility Group Inc. (Utility Group) for every 100 trust or exchangeable units held on August 27, 2007. As part of the distribution plan, any unitholder allocated fewer than 50 common shares of Utility Group received cash. The number of common shares of Utility Group distributed to unitholders was 577,416, which reduced unitholders equity by $4.2 million. This distribution resulted in a 27 percent reduction of the Trust's interest in Utility Group to 19.6 percent. /T/ 13. UNITHOLDERS' CAPITAL Trust Units Issued and Outstanding Number of units Amount ---------------------------------------------------------------------------- December 31, 2007 56,057,438 $ 493,866 Units issued for cash on exercise of options 2,150 55 Units issued under DRIP(1) 1,071,689 25,056 Units issued for exchangeable units 26,751 292 Units issued on business acquisition 7,553,174 194,645 Units issued on conversion of convertible debentures 52,222 1,810 Units issued on public offering (net of $5.2 million of issuance costs) 4,398,750 110,077 ---------------------------------------------------------------------------- September 30, 2008 69,162,174 $ 825,801 ---------------------------------------------------------------------------- Exchangeable Units Issued and Outstanding Number of units Amount ---------------------------------------------------------------------------- December 31, 2007 issued by AltaGas LP #1 2,040,456 $ 11,678 AltaGas LP #1 units redeemed for trust units (26,751) (292) Units issued on business acquisition 163,607 4,216 ---------------------------------------------------------------------------- September 30, 2008 2,177,312 15,602 ---------------------------------------------------------------------------- Issued and outstanding at September 30, 2008 71,339,486 $ 841,403 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Distribution Reinvestment and Optional Unit Purchase Plan. Three Months Ended Nine Months Ended September 30 September 30 Weighted Average Units Outstanding (1) 2008 2007 2008 2007 ---------------------------------------------------------------------------- Number of units - basic 71,137,882 57,692,359 67,873,398 57,187,589 Dilutive stock options 904,070 52,025 920,614 39,537 ---------------------------------------------------------------------------- Number of units - diluted 72,041,952 57,744,384 68,794,012 57,227,126 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Includes exchangeable units. /T/ The Trust has an employee unit option plan under which both employees and directors are eligible to receive grants. At September 30, 2008, 10 percent of units outstanding were reserved for issuance under the plan. To September 30, 2008 options granted under the plan generally had a term of 10 years to expiry and vested no longer than over a four-year period. At September 30, 2008 outstanding options were exercisable at various dates to the year 2018 (December 31, 2007 - 2017). Options outstanding under the plan have a weighted average exercise price of $25.69 (December 31, 2007 - $26.36) and a weighted average remaining term of 8.4 years (December 31, 2007 - 8.76 years). As at September 30, 2008 the unexpensed fair value of unit option compensation cost associated with future periods was $0.5 million (December 31, 2007 - $0.7 million). /T/ The following table summarizes information about the Trust's unit options: Options outstanding ---------------------------------------------------------------------------- Number of Exercise options price(1) ---------------------------------------------------------------------------- Unit options outstanding, December 31, 2007 1,310,400 $ 26.36 Granted 478,250 24.06 Exercised (2,150) 17.17 Cancelled (166,500) 26.41 ---------------------------------------------------------------------------- Unit options outstanding, September 30, 2008 1,620,000 $ 25.69 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Unit options exercisable, September 30, 2008 489,409 $ 23.24 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Weighted average. A summary of the employee unit option plan as at September 30, 2008: Options outstanding Options exercisable ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Remaining Number Exercise contractual Number Exercise outstanding(1) price(2) life(3) exercisable(1) price(2) ---------------------------------------------------------------------------- $5.00 - 7.00 9,000 $ 6.10 1.70 9,000 $ 6.10 $7.01 - 15.50 27,500 10.29 4.41 27,500 10.29 $15.51 - 25.08 731,500 24.21 8.92 437,075 24.33 $25.09 - 29.50 852,000 27.66 8.15 15,834 25.57 ---------------------------------------------------------------------------- 1,620,000 $ 25.69 8.40 489,409 $ 23.24 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) As at September 30, 2008. (2) Weighted average. (3) Weighted average number of years. /T/ In 2004 AltaGas implemented a unit-based compensation plan, which awards phantom units to certain employees. The phantom units are valued on distributions declared and the trading price of the Trust's units. The units vest on a graded vesting schedule. The compensation expense recorded in third quarter 2008 in respect of this plan was $1.7 million (third quarter 2007 - $1.1 million). As at September 30, 2008 the unexpensed fair value of unit-based compensation costs associated with future periods was $15.8 million (December 31, 2007 - $14.2 million). /T/ 14. CONTRIBUTED SURPLUS September 30 December 31 2008 2007 ---------------------------------------------------------------------------- Balance, beginning of period $ 3,875 $ 3,322 Amortization of unit options 332 617 Exercise of unit options (18) (18) Cancellation of unit options (15) (46) ---------------------------------------------------------------------------- Balance, end of period $ 4,174 $ 3,875 ---------------------------------------------------------------------------- 15. INCOME PER UNIT The following table summarizes the computation of net income per unit: Three Months Ended Nine Months Ended September 30 September 30 2008 2007 2008 2007 ---------------------------------------------------------------------------- Numerator: Numerator for basic income per unit $ 53,454 $ 31,358 $ 123,944 $ 76,991 Numerator for diluted income per unit $ 53,700 $ 31,358 $ 124,695 $ 76,991 ---------------------------------------------------------------------------- Denominator: Weighted-average number of units 71,138 57,692 67,873 57,188 Dilutive unit options 904 52 921 40 ---------------------------------------------------------------------------- Denominator for diluted income per unit 72,042 57,744 68,794 57,228 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Basic income per unit $ 0.75 $ 0.54 $ 1.83 $ 1.35 Diluted income per unit $ 0.75 $ 0.54 $ 1.81 $ 1.35 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 16. NET CHANGE IN NON-CASH WORKING CAPITAL The net change in the following non-cash working capital items increased (decreased) cash flows from operations as follows: Three Months Ended Nine Months Ended September 30 September 30 2008 2007 2008 2007 ---------------------------------------------------------------------------- Accounts receivable(1) $ 24,747 $ (4,862) $ 20,313 $ 61,972 Inventory (444) - (444) (50) Other current assets(2) 1,105 (1,742) 2,922 4,554 Accounts payable and accrued liabilities(1) (19,290) (13,712) (20,163) (76,369) Customer deposits 517 3,337 163 9,520 Deferred revenue - 272 1,059 695 Other current liabilities 1,114 1,933 10,702 (3,323) ---------------------------------------------------------------------------- 7,749 (14,774) 14,552 (3,001) Add decrease (increase) in capital costs payable (13,471) (1,665) (9,677) 1,958 ---------------------------------------------------------------------------- Net change in non-cash working capital related to operations $ (5,722) $(16,439) $ 4,875 $ (1,043) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Specific line items may not tie to net change in Balance Sheet due to acquisition (note 3). (2) Excludes note receivable of $6.5 million included in investing activities. The following cash payments have been included in the determination of earnings: Three Months Ended Nine Months Ended September 30 September 30 2008 2007 2008 2007 ---------------------------------------------------------------------------- Interest paid $ 5,698 $ 2,846 $ 18,091 $ 9,099 Income taxes paid $ 90 $ 85 $ 415 $ 181 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ 17. PENSION PLANS AND RETIREE BENEFITS During the first quarter of 2008 the Trust assumed two defined benefit pension plans with the acquisition of Taylor. These plans are in relation to the unionized employees at the Younger Extraction Plant and certain employees at the Harmattan Complex. The cost of the defined benefit plans are based on management's estimate of the future rate of return on the fair value of pension plan assets, salary escalations, mortality and other factors affecting the payment of future benefits. AltaGas adjusted the actuarial liability of these plans to follow the same assumptions used under its existing pension plans. The net pension expense by plan for the period was as follows: /T/ Three Months Ended Nine Months Ended September 30 September 30 2008 2007 2008 2007 ---------------------------------------------------------------------------- Defined contribution plan $ 567 $ 386 $ 1,341 $ 1,148 Defined benefit plan 120 (17) 519 (11) Supplemental executive retirement plan 428 282 928 800 ---------------------------------------------------------------------------- $ 1,115 $ 651 $ 2,788 $ 1,937 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ 18. 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: /T/ Three Months Ended Nine Months Ended September 30 September 30 2008 2007 2008 2007 ---------------------------------------------------------------------------- Fees for administration, management and other services paid by: Utility Group to the Trust $ 51 $ 8 $ 148 $ 23 The Trust to Utility Group $ 1 $ 129 $ 3 $ 394 Natural gas sales by the Trust to Utility Group subsidiaries $ 9,036 $ 5,309 $ 67,242 $ 57,653 Fees for operating services paid by Utility Group subsidiaries $ 44 $ 163 $ 198 $ 306 Transportation services provided by Utility Group subsidiaries $ 125 $ 119 $ 367 $ 362 Office space and furniture rental payments made by the Trust to a corporation owned by an employee $ 22 $ 21 $ 66 $ 63 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ The resulting amounts due from and to related parties are non-interest bearing and are related to transactions in the normal course of business. Included in accounts receivable at September 30, 2008 was $4.7 million (December 31, 2007 - $13.5 million) due to the Trust from related parties. Included in accounts payable at September 30, 2008 was $1,000 (December 31, 2007 - $50,000) due from the Trust to related parties. During third quarter 2007 AltaGas sold its 33.3335 percent interest in the Ikhil Joint Venture to Utility Group for $9.0 million to execute the divestiture of non-core production assets. 19. GAIN ON SALE OF ASSETS During third quarter 2008 AltaGas sold a power project that was under development for $6.6 million. The sale of assets resulted in a pre-tax gain of $1.4 million. 20. SEGMENTED INFORMATION AltaGas is an integrated energy trust with a portfolio of assets and services used to move energy from the source to the end-user. The majority of the transactions among the reporting segments are recorded at the market price of the commodities and the remainder are at the exchange amount. The following describes the Trust's five reporting segments: /T/ Extraction and - NGL processing and extraction plants and transmission Transmission pipelines to transport natural gas and NGL; Field Gathering and Processing - natural gas gathering lines and processing facilities; Energy Services - energy management and gas services for natural gas and electricity; Power Generation - coal-fired and gas-fired power output under power purchase arrangements and other agreements, gas-fired power plants as well wind and run-of-river power projects under development; and Corporate the costs of providing corporate services and general corporate overhead, investments in public and private entities, corporate assets and the effects of changes in the fair value of risk management contracts. The following tables show the composition by segment: Field Extraction Gathering Three Months Ended and and Energy Gas September 30, 2008 Transmission Processing Services Subtotal ---------------------------------------------------------------------------- Revenue $ 111,828 $ 41,329 $ 263,825 $ 416,982 Unrealized loss on risk management - - - - Cost of sales (68,009) (3,208) (259,414) (330,631) Operating and administrative (18,405) (23,868) (3,015) (45,288) Amortization (7,445) (7,089) (524) (15,058) Interest expense - - - - ---------------------------------------------------------------------------- Income before income taxes $ 17,969 $ 7,164 $ 872 $ 26,005 ---------------------------------------------------------------------------- Net additions (reductions) to: Capital assets(1) $ 20,274 $ 6,994 $ 313 $ 27,581 Energy services arrangements, contracts and relationships $ (12,900) - - - Long-term investment and other assets(2) - - - - ---------------------------------------------------------------------------- Goodwill $ 143,725 $ 215 - $ 143,940 Segmented assets $1,494,945 $ 104,158 $ 56,098 $1,655,201 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Three Months Ended Power Intersegment September 30, 2008 Generation Corporate Elimination Total ---------------------------------------------------------------------------- Revenue $ 55,637 $ (120) $ (15,451) $ 457,048 Unrealized loss on risk management - 3,654 - 3,654 Cost of sales (22,787) - 15,376 (338,042) Operating and administrative (1,035) (8,345) 75 (54,593) Amortization (1,776) (553) - (17,387) Interest expense - (6,026) - (6,026) ---------------------------------------------------------------------------- Income before income taxes $ 30,039 $ (11,390) - $ 44,654 ---------------------------------------------------------------------------- Net additions (reductions) to: Capital assets(1) $ 66,339 $ 1,166 - $ 95,086 Energy services arrangements, contracts and relationships $ (18,000) - - $ (30,900) Long-term investment and other assets(2) $ (292) $ (250) - $ (542) ---------------------------------------------------------------------------- Goodwill 4,348 - - $ 148,288 Segmented assets $ 326,968 $ 131,323 - $2,113,492 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Includes non-cash transactions of $75,032. (2) Includes non-cash transactions of $45,369. Field Extraction Gathering Nine Months Ended and and Energy Gas September 30, 2008 Transmission Processing Services Subtotal ---------------------------------------------------------------------------- Revenue $ 332,031 $ 119,303 $ 824,859 $ 1,276,193 Unrealized loss on risk management - - - - Cost of sales (198,530) (9,012) (814,029) (1,021,571) Operating and administrative (51,372) (72,115) (9,508) (132,995) Amortization (20,523) (20,937) (1,574) (43,034) Interest expense - - - - ---------------------------------------------------------------------------- Income before income taxes $ 61,606 $ 17,239 $ (252)$ 78,593 ---------------------------------------------------------------------------- Net additions (reductions) to: Capital assets(1) $ 592,412 $ 43,173 $ (179)$ 635,406 Energy service arrangements, contracts and relationships $ 53,100 - - $ 53,100 Long-term investment and other assets(2) - - - - ---------------------------------------------------------------------------- Goodwill $ 143,725 $ 215 - $ 143,940 Segmented assets $1,494,945 $ 104,158 $ 56,098 $ 1,655,201 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Nine Months Ended Power Intersegment September 30, 2008 Generation Corporate Elimination Total ---------------------------------------------------------------------------- Revenue $ 165,342 $ 1,390 $ (52,073) $1,390,852 Unrealized loss on risk management - 1,386 - 1,386 Cost of sales (72,221) - 52,247 (1,041,545) Operating and administrative (2,236) (29,782) (174) (165,187) Amortization (5,508) (1,670) - (50,212) Interest expense - (19,343) - (19,343) ---------------------------------------------------------------------------- Income before income taxes $ 85,377 $ (48,019) - $ 115,951 ---------------------------------------------------------------------------- Net additions (reductions) to: Capital assets(1) $ 120,260 $ 4,771 - $ 760,437 Energy service arrangements, contracts and relationships - - - $ 53,100 Long-term investment and other assets(2) $ 4,942 $ (47,808) - $ (42,866) ---------------------------------------------------------------------------- Goodwill $ 4,348 - - $ 148,288 Segmented assets $ 326,968 $ 131,323 - $2,113,492 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Includes non-cash transactions of $664,944. (2) Includes non-cash transactions of $264,050. Field Extraction Gathering Three Months Ended and and Energy Gas September 30, 2007 Transmission Processing Services Subtotal ---------------------------------------------------------------------------- Revenue $ 32,671 $ 33,381 $ 211,114 $ 277,166 Unrealized gains on risk management - - - - Cost of sales (15,675) (1,831) (207,240) (224,746) Operating and administrative (5,043) (21,870) (3,531) (30,444) Amortization (2,044) (6,562) (552) (9,158) Interest expense - - - - ---------------------------------------------------------------------------- Income before income taxes $ 9,909 $ 3,118 $ (209) $ 12,818 ---------------------------------------------------------------------------- Net additions to: Capital assets(1) $ 669 $ (8,731) $ 8,052 $ (10) Long-term investment and other assets(2) - - - - ---------------------------------------------------------------------------- Goodwill $ 18,045 $ 215 - $ 18,260 Segmented assets $253,509 $ 488,888 $ 119,983 $ 862,380 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Three Months Ended Power Intersegment September 30, 2007 Generation Corporate Elimination Total ---------------------------------------------------------------------------- Revenue $ 51,736 $ 762 $ (8,737) $ 320,927 Unrealized gains on risk management - 1,142 - 1,142 Cost of sales $ (17,829) - 8,679 (233,896) Operating and administrative (511) (8,176) 58 (39,073) Amortization (1,873) (619) - (11,650) Interest expense - (2,855) - (2,855) ---------------------------------------------------------------------------- Income before income taxes $ 31,523 $ (9,746) - $ 34,595 ---------------------------------------------------------------------------- Net additions to: Capital assets(1) $ 5,412 $ 535 - $ 5,937 Long-term investment and other assets(2) $ (1,007)$ (7,027) - $ (8,034) ---------------------------------------------------------------------------- Goodwill - - - $ 18,260 Segmented assets $ 117,189 $ 182,907 - $1,162,476 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Includes non-cash transactions of $1,045. (2) Includes non-cash transactions of $9,421. Field Extraction Gathering Nine Months Ended and and Energy Gas September 30, 2007 Transmission Processing Services Subtotal ---------------------------------------------------------------------------- Revenue $ 103,644 $ 103,420 $ 795,274 $ 1,002,338 Unrealized gain (loss) on risk management - - - - Cost of sales (55,556) (5,411) (778,407) (839,374) Operating and administrative (14,824) (64,772) (12,137) (91,733) Amortization (6,051) (19,541) (2,755) (28,347) Interest expense - - - - ---------------------------------------------------------------------------- Income before income taxes $ 27,213 $ 13,696 $ 1,975 $ 42,884 ---------------------------------------------------------------------------- Net additions (reductions) to: Capital assets(1) $ 4,413 $ (1,839) $(21,514) $(18,940) Long-term investment and other assets(2) - - - - ---------------------------------------------------------------------------- Goodwill $ 18,045 $ 215 - $ 18,260 Segmented assets $253,509 $ 488,888 $119,983 $862,380 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Nine Months Ended Power Intersegment September 30, 2007 Generation Corporate Elimination Total ---------------------------------------------------------------------------- Revenue $ 136,720 $ 3,454 $ (52,217) $1,090,295 Unrealized gain (loss) on risk management - 1,617 - 1,617 Cost of sales (55,422) - 50,445 (844,351) Operating and administrative (1,432) (22,755) 1,772 (114,148) Amortization (5,594) (1,755) - (35,696) Interest expense - (8,979) - (8,979) ---------------------------------------------------------------------------- Income before income taxes $ 74,272 $ (28,418) - $ 88,738 ---------------------------------------------------------------------------- Net additions (reductions) to: Capital assets(1) $ 9,308 $ 1,583 - $ (8,049) Long-term investment and other assets(2) $ (529) $ 16,008 - $ 15,479 ---------------------------------------------------------------------------- Goodwill - - - $ 18,260 Segmented assets $ 117,189 $ 182,907 - $1,162,476 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Includes non-cash transactions of $35,412. (2) Includes non-cash transactions of $14,516. Supplementary Quarterly Financial and Operating Information ($ millions unless otherwise indicated) Q3-08 Q2-08 Q1-08 Q4-07 Q3-07 ---------------------------------------------------------------------------- FINANCIAL HIGHLIGHTS(1) Net Revenue(2) Extraction and Transmission 43.8 44.1 45.6 19.3 17.0 Field Gathering and Processing 38.1 40.6 31.6 29.4 31.6 Energy Services 4.4 3.0 3.4 4.0 3.9 Power Generation 32.8 31.9 28.4 22.9 33.9 Corporate 3.6 (2.8) 2.0 1.1 1.9 Intersegment Elimination - 0.5 (0.3) (0.3) - ---------------------------------------------------------------------------- 122.7 117.3 110.7 76.4 88.3 ---------------------------------------------------------------------------- EBITDA(2) Extraction and Transmission 25.4 25.7 31.0 13.8 12.0 Field Gathering and Processing 14.2 12.8 11.2 10.9 9.7 Energy Services 1.4 (0.4) 0.3 0.6 0.3 Power Generation 31.8 31.4 27.7 22.3 33.4 Corporate (4.7) (15.7) (6.6) (7.3) (6.3) ---------------------------------------------------------------------------- 68.1 53.8 63.6 40.3 49.1 ---------------------------------------------------------------------------- Operating Income (Loss)(2) Extraction and Transmission 18.0 18.8 24.8 11.9 9.9 Field Gathering and Processing 7.2 5.8 4.3 4.5 3.1 Energy Services 0.8 (0.9) (0.2) - (0.2) Power Generation 30.1 29.4 25.9 20.4 31.5 Corporate (5.4) (16.1) (7.2) (7.9) (6.8) ---------------------------------------------------------------------------- 50.7 37.0 47.6 28.9 37.5 ---------------------------------------------------------------------------- OPERATING HIGHLIGHTS Extraction and Transmission Extraction inlet gas processed (Mmcf/d)(4) 781 759 872 463 394 Extraction volumes (Bbls/d)(4) 35,591 35,335 41,799 21,179 16,859 Transmission volumes (Mmcf/d)(4)(5) 381 390 379 403 407 Frac spread - realized ($/Bbl)(4)(6) 26.02 27.61 27.02 29.03 25.24 Frac spread - average spot price ($/Bbl)(4)(6) 36.92 30.32 28.92 29.03 26.41 Field Gathering and Processing Capacity (gross Mmcf/d)(3) 1,178 1,178 1,178 1,023 1,008 Throughput (gross Mmcf/d)(4) 545 554 542 511 510 Capacity utilization (%)(4) 46 47 46 50 51 Energy Services Energy management service contracts(3) 1,572 1,514 1,499 1,466 1,451 Average volumes transacted (GJ/d)(4) 298,608 303,212 324,758 393,936 342,143 Power Generation Volume of power sold (GWh)(4) 651 648 660 673 673 Average price received on sale of power ($/MWh)(4) 83.10 89.46 78.24 68.07 76.92 Alberta Power Pool average spot price ($/MWh)(4) 80.36 107.56 76.69 61.75 92.00 ---------------------------------------------------------------------------- (1) Columns may not add due to rounding. (2) Non-GAAP financial measure. (3) As at period end. (4) Average for the period. (5) Excludes natural gas liquids pipeline volumes. (6) AltaGas reports an indicative frac spread or NGL margin, expressed in dollars per barrel of NGL, which is derived from Edmonton postings for propane, butane and condensate and the daily AECO natural gas price. Other Information DEFINITIONS Bbls/d barrels per day Bcf billion cubic feet GJ gigajoule GWh gigawatt-hour Mcf thousand cubic feet Mmcf/d million cubic feet per day MW megawatt MWh megawatt-hour /T/ ABOUT ALTAGAS AltaGas Income Trust is one of Canada's largest and fastest growing integrated energy infrastructure organizations. The Trust creates value by growing and optimizing gas and power infrastructure, including a focus on renewable energy sources. AltaGas Income Trust's units are listed on the Toronto Stock Exchange under the symbol ALA.UN. The Trust is included in the S&P/TSX Composite Index, the S&P/TSX Income Trust Index and the S&P/TSX Capped Energy Trust Index.
