AltaGas Reports Strong Earnings of $32.9 Million in Second Quarter 2008 and Increases Distribution
Wed Aug 6, 2:44 PMCALGARY, ALBERTA--(Marketwire - Aug. 6, 2008) - AltaGas Income Trust (AltaGas or the Trust) (TSX: ALA-UN.TO) today announced net income of $32.9 million ($0.49 per unit - basic) for the three months ended June 30, 2008, compared to $21.1 million ($0.37 per unit - basic) for the same period of 2007. Excluding the unrealized after-tax loss related to risk management contracts of $1.6 million and the after-tax charge related to project development costs of $1.9 million recorded in second quarter 2008, net income was $36.4 million ($0.54 per unit - basic). In second quarter of 2007, AltaGas reported a non-cash charge related to the tax on income trusts of $6.5 million. Excluding this non-cash tax charge, net income for the three months ended June 30, 2007 was $27.6 million ($0.48 per unit).
Net income for the six months ended June 30, 2008 was $70.5 million ($1.06 per unit - basic) compared to $45.6 million ($0.80 per unit - basic) for the same period in 2007. Excluding the unrealized after-tax loss related to risk management contracts of $1.3 million and the after-tax charges related to project development costs recorded in the first half of 2008, net income was $73.7 million ($1.11 per unit - basic). Excluding the non-cash tax charge reported in second quarter 2007, net income for the six months ended June 30, 2007 was $52.1 million ($0.92 per unit). AltaGas also 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) payable on September 15, 2008 to unitholders of record on August 25, 2008. This is AltaGas' fifth distribution increase since converting to a trust in May 2004, which together represent a 20 percent increase. AltaGas' total distributions declared in the second quarter of 2008 were $0.525 per unit. "Our second quarter results and distribution increase reflect the strong performance of our energy infrastructure business. The gas and power businesses reported solid results, delivering value to our investors," said David Cornhill, Chairman and CEO of AltaGas. "Looking ahead to the rest of 2008, we are continuing on track to deliver our estimated mid-to-high single digit growth in earnings per unit." Despite turnarounds and operational downtime during the quarter, AltaGas' gas business performed well, primarily due to the Taylor acquisition. The Trust's effective commodity hedging and risk mitigation strategies continue to contribute to its solid earnings, complemented by strong Alberta power prices and fractionation (frac) spreads. AltaGas continues to lock in power and frac spread hedges to take advantage of favourable rates. This strategy worked well for the power business, which reported strong results due to higher hedge and spot prices. AltaGas continues to grow its business by pursuing growth through acquisition and development, as well as increasing the profitability of existing assets. On July 31, 2008, the Trust announced a significant step in moving its renewable energy strategy forward with the addition of both wind and run-of-river hydroelectric development projects. The acquisitions will add approximately 325 MW of run-of-river development projects located in northwest British Columbia and more than 600 MW of wind development projects, located throughout Western Canada and the Western United States. The acquisitions bring AltaGas' total renewable energy capacity under construction and development to approximately 1,900 MW. "These opportunities help to strategically balance AltaGas as a gas and power infrastructure builder and operator, and demonstrate our commitment to ensuring long-term, sustainable returns in the power business through a portfolio of renewable energy assets," said Mr. Cornhill. Net income in second quarter 2008 was positively impacted by the addition of new gas infrastructure assets primarily in the E&T segment higher frac spreads and higher average prices received on the sale of power. These increases were partially offset by the impact of turnarounds and lower throughput at some of the facilities, higher costs related to the power purchase arrangements, higher environmental compliance and transmission costs in the power business, the unrealized loss on the fair value of risk management contracts and a charge related to project development costs as a project's commodity price exposures could not be aligned with the Trust's low-risk business model and commodity risk strategy. Net income was also impacted by higher interest expense and lower income taxes. FINANCIAL HIGHLIGHTS (1) - Earnings before interest, taxes, depreciation and amortization were $53.8 million ($0.80 per unit) for second quarter compared to $43.1 million ($0.75 per unit) in the same quarter in 2007. - Cash from operations was $79.1 million ($1.17 per unit) for second quarter 2008 compared to $46.6 million ($0.81 per unit) for the same period in 2007. - Funds from operations were $50.6 million ($0.75 per unit) for second quarter 2008 compared to $39.2 million ($0.69 per unit) for the same period in 2007. - Total debt at June 30, 2008 was $504.3 million, compared to $639.8 million at March 31, 2008 and $220.7 million at December 31, 2007. The Trust's debt-to-total capitalization ratio at June 30, 2008 was 36.4 percent, versus 45.1 percent at March 31, 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 second quarter Management's Discussion and Analysis. IN THE SECOND QUARTER ALTAGAS: - Announced plans to spend approximately $55 million on projects to increase volumes and boost efficiency at its Harmattan Complex. When the projects are completed in fourth quarter 2008, processing volumes at the Complex are expected to increase by 30 to 40 Mmcf/d and it will increase AltaGas' ethane extraction volumes by 1,800 to 2,400 Bbls/d. - Filed a prospectus supplement to the Short Form Base Shelf prospectus dated August 8, 2007. The supplement establishes AltaGas' medium-term note (MTN) program and prepares AltaGas to access the Canadian MTN market. - Successfully completed an equity offering of 3,825,000 Trust units at a price of $26.20 per Trust unit. The underwriters exercised their over allotment option in full, acquiring an additional 573,750 Trust units at a price of $26.20 per Trust unit. The total offering of 4,397,750 Trust units represented gross proceeds of $115 million. The net proceeds of $110.1 million from this issue were used to repay bank indebtedness. - Appointed Hugh A. Fergusson, B.A., LLB, ICD.D to the Board of Directors. Mr. Fergusson is a board member for Provident Energy Trust, Canexus Income Trust and the Alberta Electric System Operator. Mr. Fergusson was also a board member of Taylor NGL Limited Partnership from 2005 to 2008. SUBSEQUENT TO THE SECOND QUARTER: - AltaGas entered into an agreement to acquire NovaGreenPower Inc. (NovaGreen), a wholly-owned subsidiary of NovaGold Resources Inc. (NovaGold), for $35 million on closing. AltaGas will pay an additional $5 million to NovaGold on completion of certain conditions subsequent. NovaGreen is developing the Forrest Kerr run-of-river hydroelectric project, which is expected to have a capacity of 195 MW, in Northwest B.C. 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 agreed with GreenWing Energy Management Ltd. (GreenWing) to acquire GreenWing's 45 percent interest in GreenWing Energy Development Limited Partnership (GEDLP) for $12.3 million. As a result, the Trust will own 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. This acquisition is expected to close on August 15, 2008. - 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 NGL Limited Partnership, which AltaGas acquired on January 10, 2008, and the Trust's earnings and funds from operations, which have outperformed S&P's expectations. AltaGas will hold a teleconference today at 2:00 p.m. Mountain time (4:00 p.m. Eastern) to discuss the second 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/080608/index.php?page. Shortly after the conclusion of the call, a replay will be available by dialing (416) 695-5800 or 1-800-408-3053. The passcode is 3265966. The replay expires at midnight (Eastern) on August 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 six months ended June 30, 2008 compared to the three and six months ended June 30, 2007. This MD&A dated August 6, 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 six months ended June 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 derived from operating income earned from partnership interests held by AltaGas Holding Limited Partnership No. 1 (AltaGas LP #1), from interest earned on loans to the operating subsidiaries and from dividends or returns of capital from equity interests held within the Trust structure. AltaGas General Partner Inc., through its Board of Directors, the members of which are elected by the Trust at the direction of the holders of the units, has been delegated by the trustee of the Trust to manage or supervise the business and affairs of the Trust. AltaGas Ltd. provides all management, administrative and operating services to the Trust and its subsidiaries.
CONSOLIDATED FINANCIAL RESULTS Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2008 2007 2008 2007
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Revenue 487.1 341.8 931.5 769.8
Unrealized gains (losses) on risk
management (2.9) 0.4 (2.3) 0.5
Net revenue(1) 117.3 80.1 228.0 159.4
EBITDA(1) 53.8 43.1 117.4 84.3
EBITDA before unrealized gains
(losses) on risk management(1) 56.7 42.7 119.7 83.8
Operating income(1) 37.0 31.2 84.6 60.3
Net income 32.9 21.1 70.5 45.6
Net income before tax-adjusted
unrealized gains (losses) on risk
management(1) 34.5 21.1 71.8 46.1
Net income before tax(1) 30.7 28.2 71.3 54.1
Total assets 2,069.2 1,179.6 2,069.2 1,179.6
Total long-term liabilities 784.6 375.0 784.6 375.0
Net additions to capital assets 17.2 (19.2) 671.2 (14.0)
Distributions declared(2) 35.7 29.2 70.3 58.2
Cash flows
Cash from operations 79.1 46.6 117.3 92.7
Funds from operations(1) 50.6 39.2 107.0 77.4
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Three Months Ended Six Months Ended
June 30 June 30
($ per unit) 2008 2007 2008 2007
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EBITDA(1) 0.80 0.75 1.77 1.48
EBITDA before unrealized gains (losses)
on risk management(1) 0.84 0.75 1.81 1.47
Net income - basic 0.49 0.37 1.06 0.80
Net income - diluted 0.49 0.37 1.06 0.80
Net income before tax-adjusted
unrealized gains (losses) on risk
management(1) 0.51 0.37 1.08 0.81
Net income before tax(1) 0.46 0.49 1.08 0.95
Distributions declared(2) 0.525 0.51 1.05 1.02
Cash flows
Cash from operations 1.17 0.81 1.77 1.63
Funds from operations(1) 0.75 0.69 1.62 1.36
Units outstanding - basic (millions)
During the period(3) 67.4 57.2 66.2 56.9
End of period 70.9 57.5 70.9 57.5
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(1) Non-GAAP financial measure. See discussion in Non-GAAP Financial
Measures section of this MD&A.
(2) Distributions declared of $0.175 per unit per month commencing in August
2007. From January 2007 to July 2007 distributions of $0.17 per unit per
month were declared.
(3) Weighted average.
CONSOLIDATED FINANCIAL REVIEW Three Months Ended June 30 Net income for the three months ended June 30, 2008 was $32.9 million ($0.49 per unit - basic) compared to $21.1 million ($0.37 per unit - basic) for the same period in 2007. Excluding the after-tax loss of $1.6 million related to risk management contracts and the after-tax charge of $1.9 million related to costs incurred on development projects, net income for the three months ended June 30, 2008 was $36.4 million ($0.54 per unit - basic). Excluding the specified investment flow-through (SIFT) tax of $6.5 million reported in second quarter 2007, net income for the three months ended June 30, 2007 was $27.6 million ($0.48 per unit - basic). Operating income from the gas business was $23.7 million in second quarter 2007 compared to $16.9 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 and higher frac spreads and rates, which were partially offset by lower throughput in some of the Field Gathering and Processing (FG&P) operating areas. During the second quarter results were impacted by the turnarounds at the Harmattan and Rainbow Lake facilities. The Harmattan Complex is on a three-year turnaround cycle while the Rainbow Lake facility is on a four-year cycle. Results were also impacted by the unscheduled plant shutdowns at the Princess and Clear Hills facilities. In the power business, operating income was $29.4 million in second quarter 2008 compared to $20.6 million in second quarter 2007. Operating income increased due to a higher average price received on the sale of power, higher contribution from the peaking plants and a deferral account settlement from the Alberta Electric System Operator (AESO), partially offset by higher costs related to the power purchase arrangements (PPAs), higher environmental compliance costs and higher transmission costs. Operating loss in the corporate segment increased primarily due to the unrealized loss in the fair value of risk management contracts, higher operating and administrative costs and charges related to project development costs where commodity price exposures could not be aligned with the Trust's low-risk business model and commodity risk strategy. On a consolidated basis, net revenue for the quarter ended June 30, 2008 was $117.3 million compared to $80.1 million in the same quarter of 2007. In the gas business, net revenue increased due to additional extraction, processing and transmission facilities, higher frac spreads and higher rates and other revenues in FG&P. These increases were partially offset by lower throughput at some of the FG&P facilities, the sale of assets in mid-2007 and lower fixed-price gas and transport sales 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 contribution from the peaking plants and a deferral account settlement from the AESO, partially offset by higher costs related to the PPAs, environmental compliance costs and transmission costs. In addition, an unrealized loss on the fair value of risk management contracts decreased net revenue. Operating and administrative expense for second quarter 2008 was $63.4 million up from $37.0 million in the same quarter of 2007. The increase was primarily due to new and expanded facilities and turnaround costs in the gas business, increased costs to support the growth of the Trust and project development costs expensed in the quarter. Project costs were expensed as a project's commodity exposures could not be aligned with the Trust's low-risk business model and commodity risk strategy. Amortization expense for second quarter 2008 was $16.8 million compared to $11.9 million in the same quarter last year. The increase was due to the Taylor acquisition, partially offset by the sale of assets in mid-2007. Interest expense for second quarter 2008 was $6.3 million compared to $3.0 million in the same quarter of 2007. The increase was due to higher average debt balances of $615.9 million compared to $240.0 million for the same period in 2007 partially offset by a lower interest rate. The average borrowing rate was 4.6 percent in second quarter 2008 compared to 5.3 percent for second quarter 2007. In second quarter 2008 the Trust reported an income tax recovery of $2.2 million compared to an income tax expense of $7.1 million in the same quarter last year. The decrease was primarily due to the $6.5 million non-cash charge in 2007 for the SIFT tax that resulted from tax legislation substantively enacted on June 12, 2007, $1.8 million from the tax impact on unrealized losses related to risk management contracts and a decrease of $1.1 million due to lower income subject to tax. Six Months Ended June 30 Net income for the six months ended June 30, 2008 was $70.5 million ($1.06 per unit - basic) compared to $45.6 million ($0.80 per unit - basic) in the same period last year. Excluding the impact of $1.3 million after-tax loss on risk management contracts and the after-tax charge of $1.9 million recorded in the second quarter related to costs incurred on project development projects, net income was $73.7 million ($1.11 per unit - basic). Excluding the SIFT tax of $6.5 million reported in second quarter 2007, net income for the six months ended June 30, 2007 was $52.1 million ($0.92 per unit - basic). Operating income from the gas business was $52.6 million in the first half of 2008 compared to $30.1 million in the same period 2007. In the power business, operating income was $55.3 million in the first half of 2008 compared to $42.7 million in the same period 2007. In the first half of 2008 operating income from the gas and power businesses were 48 percent and 52 percent respectively of total operating income compared to 41 percent and 59 percent respectively for the first half of 2007. The improved balance between the gas and power businesses for the first half of 2008 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 and higher frac spreads and rates, which were partially offset by lower throughput in some of the FG&P operating areas. During the first half of 2008 results were impacted by the turnarounds at the Harmattan and Rainbow Lake facilities. Results were also impacted by the unscheduled plant shutdowns at the Princess and Clear Hills facilities. 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 and a deferral account settlement from the AESO, partially offset by higher costs related to the PPAs, higher environmental compliance costs and higher transmission costs. Operating loss in the corporate segment increased primarily due to the unrealized loss in the fair value of risk management contracts, charges related to project development costs, lower investment income and higher operating and administrative costs. Consolidated net revenue for the six months ended June 30, 2008 was $228.0 million compared to $159.4 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 and higher rates and other revenues in FG&P. These increases were partially offset by lower throughput at some of the FG&P facilities, the sale of assets in mid-2007 and lower fixed-price gas and transport sales 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 and a deferral account settlement from the AESO partially offset by higher costs related to the PPAs, environmental compliance costs and transmission costs. In addition, an unrealized loss on the fair value of risk management contracts decreased net revenue. Operating and administrative expense for the six months ended June 30, 2008 was $110.6 million compared to $75.1 million in the same period last year. The increase was due to additional costs related to new facilities, turnaround costs, higher compensation and administrative costs and project development costs expensed in second quarter 2008. Amortization expense for the six months ended June 30, 2008 was $32.8 million compared to $24.0 million in the same period last year. The increase was primarily due to new and expanded facilities in the gas business, partially offset due to the disposition of assets in second quarter 2007. Interest expense for the six months ended June 30, 2008 was $13.3 million compared to $6.1 million in the same period last year. The increase was primarily due to a higher average debt balance of $596.6 million compared to $248.1 million in first half of 2007, partially offset by slightly lower borrowing rates. The average borrowing rate for the first half of 2008 was 4.9 percent compared to 5.2 percent in the same period in 2007. Income tax expense for the first half of 2008 was $0.8 million compared to $8.5 million in the same period in 2007. The decrease was primarily due to the $6.5 million non-cash charge recorded in second quarter 2007 for the SIFT tax and $1.7 million tax impact on unrealized losses related to risk management contracts partially offset by $0.5 million increase due to higher income subject to tax. CAPITAL OUTLOOK In second quarter 2008 AltaGas increased its capital expenditures estimate to approximately $225 million from $150 million estimated in first quarter 2008. The estimate for 2009 remains unchanged at $250 million. The expenditures are expected to be split approximately 45 percent gas and 55 percent power in both years. These estimates are based on projects that are in various stages of development. Forrest Kerr and Other Hydroelectric Projects AltaGas acquired NovaGreenPower Inc. (NovaGreen) for $35 million with an additional $5 million on completion of certain conditions. NovaGreen was developing the Forrest Kerr run-of-river hydroelectric project, which is expected to have capacity of 195 MW in Northwest B.C. NovaGreen was 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. GreenWing Energy Development Limited Partnership The Trust has entered into an agreement with GreenWing Energy Management Ltd. (GreenWing) to acquire GreenWing's 45 percent interest in GreenWing Energy Development Limited Partnership (GEDLP) for $12.3 million. As a result, the Trust will own 100 percent of GEDLP. The acquisition is expected to close on August 15, 2008. The acquisition of the remainder of GEDLP results in AltaGas holding 640 MW of mature wind development projects and approximately 800 MW of early development wind projects in Western Canada and the Western United States. Bear Mountain Wind Park Construction of the 100 MW wind farm near Dawson Creek, British Columbia is on time and on budget. Foundations to support turbine construction are 15 percent complete. Sarnia Airport Storage Pool Project AltaGas owns a 50 percent interest in the Sarnia storage project, with the other 50 percent being owned by Market Hub Partners Canada L.P., a Spectra Energy Corp. partnership. The project is expected to provide more than 5 Bcf of working capacity and deliverability of approximately 52 Mmcf/d and will include three new wells, a compressor plant and approximately 18 kilometres of pipeline. The Ontario Energy Board has approved the gas storage area; authority to inject gas into, store gas in, and remove gas from the storage pool; and the building of 18 kilometres of natural gas pipeline and the associated surface facilities within the proposed Sarnia Airport Pool. Construction is expected to begin in August 2008. The project is expected to be in operation by mid-2009. AltaGas' share of the project is expected to cost approximately $25 million. Run-of-River Hydroelectric Plants Under Development Prior to the acquisition of NovaGreen, AltaGas has under development a number of run-of-river hydroelectric projects with approximate capacity of 70 MW of renewable energy. The projects are at various stages of development. The 14-MW Rainy River project located near Gibson, B.C. is in the advanced development stage and will be bid into B.C. Hydro's Clean Power Call in November 2008. Rainy River could be operational as early as 2010. The Log Creek and Kookipi Creek projects are each 10-MW run-of-river hydroelectric facilities in the final stages of permitting and licensing. Both facilities have 40-year electricity purchase agreements with B.C. Hydro with expected in service dates of 2010. The total estimated capital cost of these three projects is estimated to be $120 to $130 million and is not included in the capital expenditure estimates disclosed above. Three other projects are in earlier stages of development. The run-of-river projects under development are subject to various regulatory and environmental approvals. Ethylene Delivery System Upgrade AltaGas is investing approximately $12.5 million to upgrade its Ethylene Delivery System (EDS) pipeline. The upgrade involves replacing approximately 12 km of existing 12-inch diameter pipeline with greater wall thickness pipe to meet regulatory requirements associated with an increase in residential population density in the vicinity of the pipeline. AltaGas will receive a fixed, transport-or-pay fee and will have full recovery of actual costs incurred in operating the upgrade under cost-of-service arrangements similar to existing arrangements for the EDS. The upgrade will be constructed during the fall of 2008 and is expected to be tied-in to the existing system by the end of the year with minimal downtime required for the existing pipeline to tie-in the upgrade. The above disclosed projects are second quarter updates. For information on all outstanding AltaGas projects, please see the 2007 Annual Report and the first quarter 2008 report. All projects in the 2007 Annual Report and first quarter 2008 report which are not discussed here are on track for timing of completion and on budget. NON-GAAP FINANCIAL MEASURES This MD&A contains references to certain financial measures that do not have a standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP) and may not be comparable to similar measures presented by other entities. The non-GAAP measures and their reconciliation to GAAP financial measures are shown below. All of the measures have been calculated consistently with previous disclosures. References to net revenue, operating income, EBITDA, EBITDA before unrealized gains (losses) on risk management, net income before tax-adjusted unrealized gains (losses) on risk management, net income before tax and funds from operations throughout this document have the meanings as set out in this section.
Net Revenue Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2008 2007 2008 2007
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Net revenue 117.3 80.1 228.0 159.4
Add: Cost of sales 369.8 261.7 703.5 610.4
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Revenue (GAAP financial measure) 487.1 341.8 931.5 769.8
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Net revenue, which is revenue less the cost of commodities purchased for sale and shrinkage, is a better reflection of performance than revenue, as changes in the market price of natural gas and power affect both revenue and cost of sales.
Operating Income Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2008 2007 2008 2007
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Operating income 37.0 31.2 84.6 60.3
Add (deduct): Interest expense (6.3) (3.0) (13.3) (6.2)
Income tax recovery (expense) 2.2 (7.1) (0.8) (8.5)
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Net income (GAAP financial measure) 32.9 21.1 70.5 45.6
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Operating income is a measure of the Trust's profitability from its principal business activities prior to how these activities are financed or how the results are taxed. 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.
EBITDA Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2008 2007 2008 2007
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EBITDA 53.8 43.1 117.4 84.3
Add (deduct): Amortization (16.8) (11.9) (32.8) (24.0)
Interest expense (6.3) (3.0) (13.3) (6.2)
Income tax recovery (expense) 2.2 (7.1) (0.8) (8.5)
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Net income (GAAP financial measure) 32.9 21.1 70.5 45.6
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EBITDA is a measure of the Trust's operating profitability. EBITDA provides an indication of the results generated by the Trust's principal business activities prior to accounting for how these activities are financed, assets are amortized or how the results are taxed. EBITDA is calculated from the Consolidated Statements of Income and Accumulated Earnings and is defined as net revenue less operating and administrative expenses. EBITDA Before Unrealized Gains Three Months Ended Six Months Ended (Losses) on Risk Management June 30 June 30 ($ millions) 2008 2007 2008 2007 ---------------------------------------------------------------------------- EBITDA before unrealized gains (losses) on risk management 56.7 42.7 119.7 83.8 Add (deduct): Unrealized gains (losses) on risk management (2.9) 0.4 (2.3) 0.5 Amortization (16.8) (11.9) (32.8) (24.0) Interest expense (6.3) (3.0) (13.3) (6.2) Income tax recovery (expense) 2.2 (7.1) (0.8) (8.5) ---------------------------------------------------------------------------- Net income (GAAP financial measure) 32.9 21.1 70.5 45.6 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------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.
Net Income Before Tax-Adjusted Unrealized Gains (Losses) Three Months Ended Six Months Ended on Risk Management June 30 June 30 ($ millions) 2008 2007 2008 2007 ---------------------------------------------------------------------------- Net income before tax-adjusted unrealized gains (losses) on risk management 34.5 21.1 71.8 46.1 Add (deduct): Unrealized gains (losses) on risk management (2.9) 0.4 (2.3) 0.5 Income tax recovery (expense) on risk management 1.3 (0.4) 1.0 (1.0) ---------------------------------------------------------------------------- Net income (GAAP financial measure) 32.9 21.1 70.5 45.6 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------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.
Net Income Before Tax Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2008 2007 2008 2007
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Net income before tax 30.7 28.2 71.3 54.1
Add (deduct): Income tax recovery
(expense) 2.2 (7.1) (0.8) (8.5)
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Net income (GAAP financial measure) 32.9 21.1 70.5 45.6
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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.
Funds from Operations Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2008 2007 2008 2007
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Funds from operations 50.6 39.2 107.0 77.4
Add (deduct): Net change in non-cash
working capital 28.6 7.4 10.5 15.4
Asset retirement obligations settled (0.1) - (0.2) (0.1)
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Cash from operations (GAAP financial
measure) 79.1 46.6 117.3 92.7
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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.
RESULTS OF OPERATIONS BY SEGMENT
Operating Income Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2008 2007 2008 2007
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Extraction and Transmission 18.8 8.8 43.6 17.3
Field Gathering and Processing 5.8 6.4 10.1 10.6
Energy Services (0.9) 1.7 (1.1) 2.2
Power Generation 29.4 20.6 55.3 42.7
Corporate (16.1) (6.3) (23.3) (12.5)
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37.0 31.2 84.6 60.3
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EXTRACTION AND TRANSMISSION The Extraction and Transmission (E&T) segment consists of interests in six ethane and NGL extraction plants, five natural gas and three NGL transmission systems. As a result of the Taylor acquisition in January 2008, AltaGas added interests in the Younger Extraction Plant in British Columbia, acquired the Harmattan Complex, the Ethane 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.
Financial Results Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2008 2007 2008 2007
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Revenue 111.2 33.6 220.2 71.0
Net revenue 44.1 15.3 89.7 31.1
Operating and administrative expense 18.4 4.5 33.0 9.8
Amortization expense 6.9 2.0 13.1 4.0
Operating income 18.8 8.8 43.6 17.3
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Operating Statistics Three Months Ended Six Months Ended
June 30 June 30
2008 2007 2008 2007
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Extraction inlet gas processed
(Mmcf/d)(1) 759 417 814 443
Extraction ethane volumes (Bbls/d)(1) 23,796 12,982 26,085 14,305
Extraction NGL volumes (Bbls/d)(1) 11,539 6,840 12,481 6,909
Total extraction volumes (Bbls/d)(1) 35,335 19,822 38,566 21,214
Frac spread - realized ($/Bbl)(1)(3) $ 27.61 $ 17.77 $ 26.88 $ 14.56
Transmission volumes (Mmcf/d)(1)(2) 390 407 388 408
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(1) Average for the period.
(2) Excludes natural gas liquids pipeline volumes.
(3) 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.
Three Months Ended June 30 In second quarter 2008 operating income in the E&T segment accounted for approximately 35 percent of operating income from the operating segments compared to 23 percent in second quarter 2007. Operating income in second quarter 2008 was $18.8 million, more than double the $8.8 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. Operating income also increased due to higher frac spreads in second quarter 2008 compared to the same period in 2007. A major scheduled turnaround occurred in the second quarter at the Harmattan Complex which cost approximately $4.0 million in operating expense and lost revenue. Turnarounds of this nature are scheduled every three years. Average ethane and NGL volumes in the extraction business increased 78 percent in second 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 plant. Natural gas volumes transported in the transmission business during the second 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 second quarter 2008 almost tripled to $44.1 million, up from $15.3 million in the same period in 2007. Net revenue increased by approximately $28.0 million primarily as a result of the extraction and transmission assets acquired with Taylor or approximately 97 percent of this increase. Net revenue also increased by approximately $1.0 million due to higher frac spreads in second quarter 2008 compared to the same period in 2007. Operating and administrative expense in second quarter 2008 was $18.4 million compared to $4.5 million for the same period in 2007. The increase was mainly due to the costs incurred to operate the new facilities acquired in January 2008. Costs in second quarter included approximately $2.5 million related to the turnaround at Harmattan. Amortization expense in second quarter 2008 was $6.9 million compared to $2.0 million for the same period in 2007. The increase was due to the Taylor acquisition. Six Months Ended June 30 Operating income in the E&T segment for the first half of 2008 was $43.6 million compared to $17.3 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. Operating income also increased due to higher frac spreads and was partially offset by lower volumes processed through the Edmonton extraction plant. In the first half 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 plant. Transmission volumes decreased slightly in the first half of 2008 due to lower volumes on the Suffield system. Net revenue was $89.7 million in the first half of 2008, compared to $31.1 million for the same period in 2007. Net revenue increased by $53.7 million primarily as a result of the extraction and transmission assets acquired with Taylor. Net revenue also increased by approximately $4.0 million due to higher frac spreads and $0.8 million due to higher volumes of NGLs exposed to frac spread in the first half of 2008 compared to the same period in 2007. Operating and administrative expense in the E&T segment for the first half of 2008 was $33.0 million compared to $9.8 million for the same period in 2007. The increase was mainly due to the costs incurred to operate the new facilities acquired in first quarter 2008. Operating and administrative costs in the first half of 2008 included approximately $2.5 million related to the Harmattan turnaround. Amortization expense for the first half of 2008 was $13.1 million compared to $4.0 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 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 processing capacity, 23,500 Bbls/d of NGL production 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 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 and lower operating costs. Approximately 12 percent (5,000 Bbls/d) of total extraction volumes produced are sold at market price and approximately 60 percent of those volumes have been hedged at over $23/Bbl for the remainder of 2008. Approximately 60 percent of exposed volumes has been hedged at over $27/Bbl for 2009, and approximately 15 percent of 2010 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 indicates that frac spreads remain strong for the remainder of 2008 between $25 and $30/Bbl. On July 24, 2008 a fire occurred at the Harmattan Complex. The fire occurred in a natural gas-fired heater and was contained to the heater. Operations were resumed on July 28, 2008 with some extraction functions temporarily limited. The Trust expects the Complex to be fully operational by mid-to-late August and is currently processing approximately 140 Mmcf/d in shallow-cut mode, similar to levels prior to the incident. The financial impact of the incident is expected to be approximately $0.75 million due to the insurance deductible as well as lost revenue, which is currently not expected to be material given the expected timing of the return to service of the facility. Also in third quarter 2008 planned turnarounds for a total of 48 days at three facilities are expected to cost approximately $1.8 million in direct costs and lost operating income. In the transmission business, the addition of the EDS and JFP pipelines in January 2008 and full year results from the Cold Lake expansion are also expected to contribute to increased earnings compared to 2007. AltaGas expects to pursue other projects similar to the Cold Lake expansion, which may further enhance returns in the segment. An arrangement to utilize capacity on a previously unused lateral of the EDS began contributing to earnings beginning second quarter 2008. FIELD GATHERING AND PROCESSING The Field Gathering and Processing segment includes natural gas gathering pipelines and processing facilities. In January 2008 AltaGas added three interconnected processing facilities, Retlaw, Enchant and Turin and related gathering systems (RET) as a result of the Taylor acquisition with processing capacity of 150 Mmcf/d.
Financial Results Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2008 2007 2008 2007
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Revenue 43.6 36.8 78.0 70.0
Net revenue 40.6 34.9 72.2 66.5
Operating and administrative expense 27.8 22.0 48.2 42.9
Amortization expense 7.0 6.5 13.9 13.0
Operating income 5.8 6.4 10.1 10.6
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Operating Statistics Three Months Ended Six Months Ended
June 30 June 30
2008 2007 2008 2007
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Capacity (Mmcf/d)(1) 1,178 1,021 1,178 1,021
Throughput (gross Mmcf/d)(2) 554 534 549 543
Capacity utilization (%)(2) 47 52 47 53
Average working interest (%)(1) 90 92 90 92
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(1) As at the end of the reporting period.
(2) Average for the period.
Three Months Ended June 30 Operating income in the FG&P segment for second quarter 2008 was $5.8 million compared to $6.4 million for the same quarter of 2007. Operating income decreased due to natural declines and lower producer activity, a scheduled turnaround at Rainbow Lake and unplanned downtime at Clear Hills and Princess. The decreases were partially offset by new facilities and higher rates and other facility services revenues. Processing capacity increased by 157 Mmcf/d 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. The increase was partially offset by 13 Mmcf/d reduction as a result of the sale of the Ikhil Joint Venture and the redeployment of the Del Bonita assets in 2007. Utilization reported in second quarter 2008 was 47 percent compared to 52 percent reported in second quarter 2007 primarily due to lower throughput as a result of natural declines as well as planned and unplanned downtime. Throughput in second quarter 2008 averaged 554 Mmcf/d compared to 534 Mmcf/d in first half of 2007. The 4 percent increase was primarily due to the acquisition of new plants, partially offset by natural declines, lower producer activity, unscheduled plant shutdowns at the Princess and Clear Hills (10 Mmcf/d) facilities and the scheduled turnaround at the Rainbow Lake facility (6 Mmcf/d). Net revenue for the FG&P segment was $40.6 million in second quarter 2008 compared to $34.9 million for the same period in 2007. Net revenue increased due to $5.0 million from new facilities and $3.8 million from rate increases, the recovery of turnaround costs at Rainbow Lake and higher other facility service revenues. These increases were partially offset by $2.2 million as a result of lower volumes due to operational downtime, natural declines and lower producer activity and $0.9 million due to the sale of the Ikhil Joint Venture in July 2007. Operating and administrative expense in second quarter 2008 was $27.8 million compared to $22.0 million for the same quarter in 2007. The increase was primarily due to $3.5 million from the facility turnaround at the Rainbow Lake facility and $2.1 million due to the addition of new facilities. Approximately three quarters of turnaround costs were recoverable. Amortization expense for the FG&P segment in second quarter 2008 was $7.0 million compared to $6.5 million for the same period in 2007. The increase was due to additional facilities partially offset by lower amortization due to the sale of the one-third interest in the Ikhil Joint Venture. Six Months Ended June 30 The operating income was $10.1 million for the first half of 2008 compared to $10.6 million for the same period in 2007. The decrease was due to lower throughput, as well as the sale of the Ikhil Joint Venture. The decreases were partially offset by the contribution from new facilities, higher rates and other facility service revenues. Throughput in the first half of 2008 averaged 549 Mmcf/d compared to 543 Mmcf/d in second quarter 2007. The increase was primarily due to the acquisition of new plants partially offset by natural declines, lower producer activity, unscheduled plant shutdowns at the Princess and Clear Hills (10 Mmcf/d) facilities and the scheduled turnaround at the Rainbow Lake facility (3 Mmcf/d). Net revenue in the FG&P segment for the first half of 2008 was $72.2 million compared to $66.5 million for the same period in 2007. The increase was due to $8.7 million in new facilities, $4.0 million related to increased rates and higher other facility service revenues. These increases were partially offset by $4.8 million in natural declines, lower producer activity and operational downtime, as well as $2.2 million from the sale of the Ikhil Joint Venture. Operating and administrative expense in the FG&P segment in the first half of 2008 was $48.2 million compared to $42.9 million for the same period in 2007. The increase was mainly attributable to $3.5 million in facility turnarounds and $4.3 million for new facilities. These increases were partially offset by $1.6 million due to continuing efforts on cost controls and $1.0 million related to the sale of the Ikhil Joint Venture. Approximately three quarters or $2.6 million of the turnaround costs were recoverable. Amortization expense in the FG&P segment in the first half of 2008 was $13.9 million compared to $13.0 million in the same period in 2007. The increase was due to new facilities and capital expenditures, partially offset by the sale of the Ikhil Joint Venture. 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, optimization of facilities and a continued focus on increasing throughput and operating and administrative expense cost control. AltaGas is working with customers to optimize underutilized assets. The underutilized Sedgewick facility has been connected to the fully utilized Killam and Iron Creek facilities to allow gas to be diverted to Sedgewick and allow increased combined processing for the three facilities. This project is completed with results expected to be realized in the last half of 2008. AltaGas continues to expect to increase its gas gathering and processing infrastructure in 2008 through acquisition and development of new facilities as producers reallocate capital from processing to their core activity of exploration and production. Well licences have increased slightly in second quarter 2008 versus second quarter 2007. The increases occurred generally over all of AltaGas' operating areas. Increased drilling activity and producer activity in CBM areas, northwest Alberta and northeast British Columbia are also expected to provide opportunities for expansions, acquisitions and development of gas gathering and processing infrastructure. Included in the Trust's estimate of capital expenditures of $225 million is $40 million to grow and optimize gathering and processing infrastructure in 2008, including gathering systems, capacity expansions and enhancements to its sour gas processing facilities, including the expansion at the Pouce Coupe facility which is in the regulatory approval stage. ENERGY SERVICES The Energy Services segment consists of two main businesses: an energy management business providing energy consulting and supply management services and arranging gas and power contracts for non-residential end-users; and a gas services business buying and reselling natural gas, transportation and storage. The segment included a small portfolio of oil and natural gas production assets which were sold effective May 31, 2007.
Financial Results Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2008 2007 2008 2007
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Revenue 294.9 248.6 561.0 584.2
Net revenue 3.0 6.9 6.4 13.0
Operating and administrative expense 3.4 4.2 6.5 8.6
Amortization expense 0.5 1.0 1.0 2.2
Operating income (0.9) 1.7 (1.1) 2.2
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Operating Statistics Three Months Ended Six Months Ended
June 30 June 30
2008 2007 2008 2007
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Energy management service
contracts(1) 1,514 1,442 1,514 1,442
Average volumes transacted (GJ/d)(2) 303,212 356,380 313,985 381,826
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(1) Active energy management service contracts at the end of the reporting
period.
(2) Average for the period. Includes volumes marketed directly, volumes
transacted on behalf of other operating segments, and volumes sold in
gas exchange transactions.
Three Months Ended June 30 The operating loss in the Energy Services segment in second quarter 2008 was $0.9 million compared to operating income of $1.7 million for the same quarter in 2007. Operating income decreased as a result of a $1.6 million gain due to the sale of the oil and natural gas assets reported in second quarter 2007 and $1.3 million in lower fixed-price gas and transport sales. These decreases were partially offset by $0.3 million in lower operating and administrative expenses. Net revenue in second quarter 2008 was $3.0 million compared to $6.9 million for the same period in 2007. Gas services net revenue decreased $2.5 million reflecting the sale of the oil and natural gas assets in second quarter 2007 and $1.4 million due to lower fixed-price gas and transport sales and lower volumes. Six Months Ended June 30 Operating loss in the Energy Services segment was $1.1 million for the first half of 2008 compared to operating income of $2.2 million for the same period in 2007. The decrease was due to the gain reported on the sale of oil and natural gas 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 lower operating and administrative expenses. Net revenue was $6.4 million in the first half of 2008 compared to $13.0 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 $2.5 million due to lower fixed-price gas and transport sales and declining volumes. Energy Services Outlook AltaGas expects results in the Energy Services segment in 2008 to be slightly lower than 2007 results, excluding the gain on sale of the oil and gas production assets in 2007. However, the recent acquisition of Taylor is expected to provide increased integration opportunities to enhance unitholder value due to the increased geographic footprint and energy infrastructure. The Energy Services segment is an important element in increasing the value of assets in AltaGas' other segments. Energy Services works with the other segments to optimize AltaGas' assets and in this capacity is expected to contribute to earnings growth across the segments. POWER GENERATION The Power Generation segment comprises 378 MW of total power generation capacity in Alberta through a 50 percent ownership interest in the Sundance B power purchase arrangements and a capital lease for 25 MW of gas-fired power peaking capacity. Construction is complete for additional gas-fired peaking plants at Bantry and is nearing completion at the Parkland gas processing facilities. Together, these sites will provide an additional 14.4 MW of peaking power capacity, all of which will be on-line in the third quarter, increasing the Trust's peaking capacity by 58 percent and total power generation capacity to 392.4 MW. The segment also includes a 25 percent interest in a 7-MW run-of-river hydroelectric generation facility in British Columbia acquired in January 2008 with the Taylor acquisition.
Financial Results Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2008 2007 2008 2007
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Revenue 58.1 40.7 109.7 85.0
Net revenue 31.9 22.9 60.3 47.4
Operating and administrative expense 0.5 0.4 1.2 1.0
Amortization expense 2.0 1.9 3.8 3.7
Operating income 29.4 20.6 55.3 42.7
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Operating Statistics Three Months Ended Six Months Ended
June 30 June 30
2008 2007 2008 2007
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Volume of power sold (GWh) 648 650 1,308 1,315
Average price received on the sale of
power ($/MWh)(1) 89.46 62.62 83.80 64.61
Alberta Power Pool average spot price
($/MWh)(1) 107.56 49.97 92.13 56.79
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(1) Average for the period.
Three Months Ended June 30 Operating income in the Power Generation segment in second quarter 2008 was $29.4 million compared to $20.6 million for the same quarter in 2007. Operating income increased primarily as a result of a higher average price received on the sale of power and higher contributions from gas-fired peaking plants. These increases were partially offset by higher PPA costs, higher environmental compliance costs and higher transmission costs. In second quarter 2008, a contract which required AltaGas to sell power during a force majeure outage event at another generation facility in Alberta was triggered whereby AltaGas was required to sell 50 MW from Sundance B for a fixed price that is above AltaGas' average hedge price but well below spot prices seen in the quarter; the outage ended at the end of May 2008. Net revenue in second quarter 2008 was $31.9 million compared to $22.9 million for the same period in 2007. Net revenue increased by $9.6 million due to higher hedge prices and hedged volumes, $5.5 million due to higher average spot power prices, $1.8 million from the AESO deferral account settlement and $1.6 million due to higher contributions from gas-fired peaking plants. The increases were partially offset by $5.9 million in higher PPA costs due to an unfavourable 30-day rolling average power price (RAPP), $1.4 million incurred to comply with Alberta's Specified Gas Emitters Regulation (SGER) and $2.6 million as a result of higher transmission costs. Operating and administrative expense was $0.5 million in second quarter 2008 compared to $0.4 million for the same period in 2007. Amortization expense of $2.0 million in second quarter 2008 was similar with the same period in 2007. Six Months Ended June 30 Operating income for the first half of 2008 in the Power Generation segment was $55.3 million compared to $42.7 million for the same period in 2007. The increase was primarily due to higher prices received on hedged volumes, higher power prices on spot sales and higher contributions from peaking plants partially offset by higher PPA costs, higher transmission costs and higher costs to comply with Alberta's SGER. Net revenue for the first half of 2008 was $60.3 million compared to $47.4 million for the same period in 2007. The increase included $22.6 million due to higher hedge prices and higher spot prices, $2.4 million in higher contributions from the gas-fired peaking plants and $1.8 million from an AESO deferral account settlement. These increases were partially offset by $8.1 million higher PPA costs due to unfavourable RAPP, $3.5 million as a result of higher transmission costs and $2.5 million of costs incurred to comply with Alberta's SGER. Operating and administrative expense of $1.2 million in the first half of 2008 was higher than the $1.0 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. These services have not materially impacted operating income, however it has resulted in slightly lower costs of sales offset by higher operating expenses. Amortization expense of $3.8 million in the first half 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 $76/MWh in 2008 compared to $66/MWh in 2007. Approximately two-thirds of the power available from the Sundance B PPAs has been hedged and the remainder is exposed to the spot price of power in Alberta. The forward market for Alberta power prices, as published in daily broker reports, indicates that prices will remain relatively strong, in the $80/MWh range 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. New gas-fired peaking generation facilities totalling 14.4 MW have been installed at the Bantry FG&P location and are being completed at the Parkland FG&P location. The facilities are integrated into ongoing operations and both sites will be operational in third quarter 2008. Installation of the generating capacity is estimated to cost approximately $12 million and is expected to be accretive to net income and cash flow once operational. CORPORATE The Corporate segment includes the cost of providing corporate services and general corporate overhead, investments in public and private entities and the effects of changes in the value of risk management assets and liabilities. Management makes operating decisions and assesses performance of its operating segments based on realized results and key financial metrics such as return on equity, and return on capital without the impact of the volatility in commodity prices and foreign exchange rates. Management monitors the impact of mark-to-market accounting as part of the consolidated entity as risk is managed on a portfolio basis. Consequently, the impact of mark-to-market accounting on net income is reported and monitored in the Corporate segment.
Financial Results Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2008 2007 2008 2007
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Revenue 0.1 0.7 1.5 2.7
Unrealized gains (losses) on risk
management (2.9) 0.4 (2.3) 0.5
Net revenue (2.8) 1.1 (0.8) 3.2
Operating and administrative expense 12.9 6.9 21.5 14.6
Amortization expense 0.4 0.5 1.0 1.1
Operating loss (16.1) (6.3) (23.3) (12.5)
Operating loss before unrealized gains
(losses) on risk management (13.2) (6.7) (21.0) (13.0)
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Three Months Ended June 30 The operating loss for second quarter 2008 was $16.1 million compared to $6.3 million for the same period in 2007. The increased loss was due to unrealized losses on risk management contracts, a charge related to costs incurred on development projects, higher operating and administrative costs and lower investment income from Taylor which is now reported in the operating segments. Net revenue was a negative $2.8 million for the second quarter in 2008 compared to $1.1 million in second quarter 2007. Net revenue decreased by $3.9 million primarily due to unrealized losses on risk management contracts and lower investment income. AltaGas no longer reports Taylor investment income in the Corporate segment. Operating and administrative expense for second quarter 2008 was $12.9 million compared to $6.9 million for the same period last year. The increase was attributable to a $3.4 million higher compensation and administrative costs due to the acquisition of Taylor as well as general escalating costs to support the growth of the Trust and a $2.6 million charge related to project development costs. Costs were expensed as a project's commodity exposures could not be aligned with the Trusts low-risk business model and commodity risk strategy. Amortization expense was $0.4 million for second quarter 2008 compared to $0.5 million for the same quarter in 2007. Six Months Ended June 30 The operating loss for the first half of 2008 was $23.3 million compared to $12.5 million for the same period in 2007. The increased loss was due to unrealized losses on risk management contracts, a charge related to costs incurred on development projects, higher operating and administration costs and lower investment income from Taylor which is now reported in the operating segments. Net revenue was a negative $0.8 million in first half 2008 compared to $3.2 million for the same period in 2007. The decrease was due to unrealized losses of $2.3 million related to risk management contracts and lower investment income. Operating and administrative expense was $21.5 million in the first half of 2008 compared to $14.6 million for the same period in 2007. The increase was due to the Taylor acquisition as well as general escalating costs to support the growth of the Trust ($4.3 million) and $2.6 million charge related to project development costs. Amortization expense for 2008 was consistent with 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. To date 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 second quarter 2008 AltaGas acquired capital assets, long-term investments and other assets of $25.9 million compared to $22.8 million in second quarter 2007. In second quarter 2008, the Trust also disposed of excess capital equipment in the FG&P segment, reducing net invested capital by $8.7 million. Year-to-date June 30, 2008, AltaGas acquired capital assets, long-term investments and other assets of $679.9 million compared to $29.8 million in the first half of 2007. During the first half of 2008, the sale of excess equipment 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 $56.9 million.
Net Invested Capital - Investment Type (1) Three Months Ended
June 30, 2008
Field
Extraction Gathering
and and Energy Power
($ millions) Transmission Processing Services Generation Corporate Total
----------------------------------------------------------------------------
Invested
capital:
Capital assets 9.7 16.4 0.6 (1.0) 0.2 25.9
Long-term
investments and
other assets - - - - - -
----------------------------------------------------------------------------
9.7 16.4 0.6 (1.0) 0.2 25.9
Disposals:
Capital assets - (8.7) - - - (8.7)
----------------------------------------------------------------------------
Net invested
capital 9.7 7.7 0.6 (1.0) 0.2 17.2
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Certain growth capital expenditures have been reclassed between
segments.
Net Invested Capital - Investment Type Six Months Ended
June 30, 2008
Field
Extraction Gathering
and and Energy Power
($ millions) Transmission Processing Services Generation Corporate Total
----------------------------------------------------------------------------
Invested
capital:
Capital assets 572.1 44.9 1.7 59.1 2.1 679.9
Long-term
investments and
other assets - - - - - -
----------------------------------------------------------------------------
572.1 44.9 1.7 59.1 2.1 679.9
Disposals:
Capital assets - (8.7) - - - (8.7)
Long-term
investments and
other assets - - - - (48.2) (48.2)
----------------------------------------------------------------------------
Net invested
capital 572.1 36.2 1.7 59.1 (46.1) 623.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Invested Capital - Investment Type Three Months Ended
June 30, 2007
Field
Extraction Gathering
and and Energy Power
($ millions) Transmission Processing Services Generation Corporate Total
----------------------------------------------------------------------------
Invested
capital:
Capital assets 1.7 5.0 0.1 3.9 0.4 11.1
Long-term
investments and
other assets - - - 0.3 11.4 11.7
----------------------------------------------------------------------------
1.7 5.0 0.1 4.2 11.8 22.8
Disposals:
Capital assets - (0.1) (30.2) - - (30.3)
----------------------------------------------------------------------------
Net invested
capital 1.7 4.9 (30.1) 4.2 11.8 (7.5)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Invested Capital - Investment Type Six Months Ended
June 30, 2007
Field
Extraction Gathering
and and Energy Power
($ millions) Transmission Processing Services Generation Corporate Total
----------------------------------------------------------------------------
Invested
capital:
Capital assets 4.1 8.2 0.6 3.9 1.0 17.8
Long-term
investments and
other assets - - - 0.5 11.5 12.0
----------------------------------------------------------------------------
4.1 8.2 0.6 4.4 12.5 29.8
Disposals:
Capital assets (0.3) (1.3) (30.2) - - (31.8)
Long-term
investments and
other assets - - - - - -
----------------------------------------------------------------------------
Net invested
capital 3.8 6.9 (29.6) 4.4 12.5 (2.0)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Trust categorizes its invested capital into maintenance, growth and administration. Maintenance capital expenditures were $3.4 million in second quarter 2008 compared to $2.1 million in the same period in 2007. Growth capital of $20.9 million was incurred in second quarter 2008 (second quarter 2007 - $8.1 million) which was comprised of the Bear Mountain Wind project, various extraction, transmission and field gathering and processing projects, hydroelectric power projects under development, installation of the new peaking equipment in the Power Generation segment and the development of projects in the Energy Services segment. The growth capital has been financed through increased long-term debt as well as a Trust unit issuance. Maintenance capital expenditures were $4.5 million in the first half of 2008 compared to $3.3 million for the same period in 2007. Growth capital of $671.8 million was expended in the first half of 2008 (2007 - $12.7 million) which was largely comprised of $592.0 million for the Taylor acquisition, $39.8 million for the Bear Mountain Wind project, $10.4 million for extraction and transmission facilities, $18.4 million for gathering and processing facilities, $4.9 million for hydroelectric power projects under development in British Columbia, $4.4 million on the installation of the new peaking equipment in the Power Generation segment and $1.6 million for the development of projects in the Energy Services segment. Administrative capital expenditures of $3.6 million in the first half of 2008 were significantly lower than the $13.8 million recorded in the same period in 2007. The $12.9 million of the increase in administrative capital reported in the six months ended June 30, 2007 related primarily to the change in accounting for the Trust's investment in Taylor from the equity to the cost method. The growth capital has been financed through increased long-term debt as well as a Trust unit issuance.
Invested Capital - Use (1) Three Months Ended
June 30, 2008
Field
Extraction Gathering
and and Energy Power
($ millions) Transmission Processing Services Generation Corporate Total
----------------------------------------------------------------------------
Invested
capital:
Maintenance 1.4 2.0 - - - 3.4
Growth 8.3 13.0 0.6 (1.0) - 20.9
Administrative - 1.4 - - 0.2 1.6
----------------------------------------------------------------------------
Invested
capital 9.7 16.4 0.6 (1.0) 0.2 25.9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Certain growth capital expenditures have been reclassed between
segments.
Invested Capital - Use Six Months Ended
June 30, 2008
Field
Extraction Gathering
and and Energy Power
($ millions) Transmission Processing Services Generation Corporate Total
----------------------------------------------------------------------------
Invested
capital:
Maintenance 5.2 (0.7) - - - 4.5
Growth 566.9 44.0 1.7 59.1 0.1 671.8
Administrative - 1.6 - - 2.0 3.6
----------------------------------------------------------------------------
Invested
capital 572.1 44.9 1.7 59.1 2.1 679.9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Invested Capital - Use Three Months Ended
June 30, 2007
Field
Extraction Gathering
and and Energy Power
($ millions) Transmission Processing Services Generation Corporate Total
----------------------------------------------------------------------------
Invested
capital:
Maintenance 0.5 1.6 - - - 2.1
Growth 1.2 3.1 0.1 4.2 (0.5) 8.1
Administrative - 0.3 - - 12.3 12.6
----------------------------------------------------------------------------
Invested
capital 1.7 5.0 0.1 4.2 11.8 22.8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Invested Capital - Use Six Months Ended
June 30, 2007
Field
Extraction Gathering
and and Energy Power
($ millions) Transmission Processing Services Generation Corporate Total
----------------------------------------------------------------------------
Invested
capital:
Maintenance 0.7 2.6 - - - 3.3
Growth 3.4 5.2 0.1 4.4 (0.4) 12.7
Administrative - 0.4 0.5 - 12.9 13.8
----------------------------------------------------------------------------
Invested capital 4.1 8.2 0.6 4.4 12.5 29.8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FINANCIAL INSTRUMENTS The Trust is exposed to market risk and potential loss from changes in the value of financial instruments. AltaGas enters into financial derivative contracts to manage exposure to fluctuations in commodity prices, interest rates and foreign exchange rates, particularly in the Power Generation and E&T segments and with respect to interest rates on debt. During the three-month period ended June 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 $0.00/MWh to $999.99/MWh in second quarter 2008. The average spot price was $107.56/MWh for the second quarter 2008 and $92.13/MWh for the six months ended June 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 $89.46/MWh in the second quarter 2008 and $83.80/MWh for the six months ended June 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 June 30, 2008, the Trust had NGL frac spread agreements for 2,800 Bbls/d at an approximate average price of $23/Bbl for the July 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 frac spread was $30/Bbl for the second quarter 2008 and $29.50/Bbl for the six months ended June 30, 2008. The average frac spread received was $27.61/Bbl and $26.88/Bbl in the three and six months ended June 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 June 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 84 percent of AltaGas' debt. - Foreign exchange forward contracts: Foreign exchange exposure created by transacting commercial arrangements in foreign currency is managed through the use of foreign exchange forward contracts where a fixed rate is locked in against a floating rate. The 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 to the extent that 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 reasonably expect any currently known trend or uncertainty to affect the Trust's ability to access its historical sources of cash, except that cash from operations may be impacted by the proposed tax on the taxable component of the Trust's distributions effective in the 2011 taxation year.
Cash Flows Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
Cash from operations 79.1 46.6 117.3 92.7
Investing activities (24.6) (16.1) (330.5) (27.0)
Financing activities (51.3) (40.6) 213.5 (66.6)
----------------------------------------------------------------------------
Change in cash 3.2 (10.1) 0.3 (0.9)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash from Operations Cash from operations reported on the Consolidated Statements of Cash Flows increased by 70 percent to $79.1 million in second quarter 2008 from $46.6 million in the same period 2007. Cash from operations increased due to higher earnings and an increase in net change in working capital. (See Non-GAAP Financial Measures section of this MD&A for description of funds from operations.) Working Capital June 30 June 30 ($ millions) 2008 2007 ---------------------------------------------------------------------------- Current assets 380.5 264.7 Current liabilities 402.0 268.8 ---------------------------------------------------------------------------- Working capital (21.5) (4.1) Current ratio 0.95 0.98 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------Working capital was a negative $21.5 million at the end of second quarter 2008 compared to a negative $4.1 million at June 30, 2007. The working capital ratio was 0.95 for the end of second quarter 2008 and 0.98 for the same quarter in 2007. Investing Activities Cash used for investing activities in second quarter 2008 was $24.6 million compared to $16.1 million in the same period in 2007. The increase in cash used for investing activities was due to acquisition of capital assets, partially offset by a decrease in notes receivable and disposal of excess equipment. A description of the acquisitions and investments related to long-term assets is in the Invested Capital section of this MD&A. 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 used for financing activities in second quarter 2008 was $51.3 million compared to $40.6 million in the same period in 2007. The increase was primarily due to $134.1 million of repayments in short-term debt, revolving debt and long-term debt and higher distributions paid. The increase was partially offset by net proceeds of $117.7 million from the issuance of trust units. Capital Resources The use of debt or equity funding is based on AltaGas' capital structure determined by considering the norms and risks associated with each of its business segments. At June 30, 2008 AltaGas had total debt outstanding of $504.3 million, up from $220.7 million as at December 31, 2007. At June 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 totaling $750.0 million. At June 30, 2008 the Trust had drawn bank debt of $277.0 million and letters of credit outstanding of $65.8 million. In second quarter 2008, the Trust issued 4,398,750 Trust units via public offering at a price of $26.20 per unit resulting in net proceeds of $110.1 million. Proceeds were primarily used to repay bank indebtedness. The Trust acquired convertible debentures through the Taylor acquisition of a face value of $22.1 million. During second quarter 2008, $2.1 million were converted into Trust units. The fair value of the outstanding convertible debentures at June 30, 2008 was $18.4 million, which had a face value of $16.9 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 June 30, 2008 was 36.4 percent, up from 27.4 percent at December 31, 2007 and down from 45.1 percent at end of first quarter 2008. The Trust's earnings interest coverage for the rolling 12 months ended June 30, 2008 was 7.39 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 $16.0 million of natural gas to, and incurred transportation costs of $0.1 million charged by, Utility Group in second 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 second quarter 2008 (second quarter 2007 - $21,171) which is the exchange value of the property agreed to by both parties. The lease expires at the end of 2008.
SUMMARY OF CONSOLIDATED RESULTS FOR THE EIGHT MOST RECENT QUARTERS
($ millions) Q2-08 Q1-08 Q4-07 Q3-07 Q2-07 Q1-07 Q4-06 Q3-06
----------------------------------------------------------------------------
Net revenue(1) 117.3 110.7 76.4 88.2 80.1 79.3 84.6 82.5
Operating income(1) 37.0 47.6 28.9 37.5 31.2 29.0 32.0 33.7
Net income 32.9 37.6 31.8 31.4 21.1 24.6 27.3 28.8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ per unit) Q2-08 Q1-08 Q4-07 Q3-07 Q2-07 Q1-07 Q4-06 Q3-06
----------------------------------------------------------------------------
Net income
Basic 0.49 0.58 0.55 0.54 0.37 0.43 0.49 0.52
Diluted 0.49 0.57 0.55 0.54 0.37 0.43 0.49 0.52
Distributions
declared(2) 0.525 0.525 0.525 0.52 0.51 0.51 0.51 0.505
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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.
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, specified investment flow-through tax (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 were for units issued. Results in first quarter 2008 increased as a result of the Taylor acquisition. SUBSEQUENT EVENTS 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, which is expected to have capacity of 195 MW in Northwest B.C. NovaGreen was 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. Acquisition of 45 Percent Interest In GreenWing Energy Development Limited Partnership AltaGas entered into an agreement with GreenWing Energy Management Ltd. (GreenWing) to acquire GreenWing's 45 percent interest in GreenWing Energy Development Limited Partnership (GEDLP) for $12.3 million. As a result, the Trust will own 100 percent of GEDLP. The acquisition is expected to close on August 15, 2008. Improved Standards & Poor's Outlook 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 rating. 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 July 31, 2008 the Trust had 68.9 million trust units and 2.2 million exchangeable units outstanding and a market capitalization of $1.7 billion based on a closing trading price on July 31, 2008 of $24.41 per trust unit. At July 31, 2008 there were 1.6 million options outstanding and 401,284 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 June 30, 2008 the Trust declared distributions of $35.7 million and had cash from operations of 79.1 million (same period 2007 - $29.2 million and $46.6 million respectively) which was more than sufficient to fund all distributions to unitholders. In the six months ended June 30, 2008 the Trust declared distributions of $70.3 million and had cash from operations of $117.3 million (same period 2007 - $58.2 million and $92.7 million respectively) which was more than sufficient to fund all distributions to unitholders. AltaGas has a target payout ratio of 65 to 75 percent of funds from operations. 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 ($2.10 per unit annualized) payable on September 15, 2008 to unitholders of record on August 25, 2008. This is AltaGas' fifth distribution increase since converting to a trust in May 2004, which together represent a 20 percent increase since inception. The following table summarizes AltaGas' distribution declaration history since 2006:
Distributions
($ per unit) 2008 2007 2006
----------------------------------------------------------------------------
First quarter 0.525 0.510 0.485
Second quarter 0.525 0.510 0.495
Third quarter - 0.520 0.505
Fourth quarter - 0.525 0.510
Distribution of shares(1) - 0.076 -
----------------------------------------------------------------------------
1.050 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.
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. AltaGas is currently assessing the impact of IFRS financial statements which cannot be reasonably estimated at this time. The Trust is in the process of securing resources to complete the project and providing training to employees affected by the change in accounting standards. 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 six months ended June 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 six months ended June 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 six months ended June 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 second quarter 2008 there were no material changes to the Trust's internal controls over financial reporting.
Consolidated Balance Sheets
(unaudited)
June 30 December 31
($ thousands) 2008 2007
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 12,785 $ 12,451
Accounts receivable 223,979 191,879
Inventory 130 130
Customer deposits 24,015 24,369
Risk management (note 11) 111,741 66,811
Other current assets 7,897 9,714
----------------------------------------------------------------------------
380,547 305,354
Capital assets (note 6) 1,320,241 682,322
Energy arrangements, contracts and
relationships (note 7) 174,855 95,716
Goodwill 124,576 18,260
Risk management (note 11) 46,759 33,640
Long-term investments and other assets 22,186 64,509
----------------------------------------------------------------------------
$ 2,069,164 $ 1,199,801
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LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities $ 210,593 $ 177,802
Distributions payable to unitholders