CALGARY, ALBERTA--(Marketwire - Aug. 6, 2008) - AltaGas Income Trust (AltaGas or the Trust) (TSX:ALA.UN) 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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities $ 210,593 $ 177,802
Distributions payable to unitholders 12,414 10,167
Short-term debt 2,298 3,551
Current portion of long-term debt (note 8) 1,350 1,234
Customer deposits 24,015 24,369
Deferred revenue 2,777 1,718
Risk management (note 11) 129,599 60,848
Other current liabilities 18,909 9,321
----------------------------------------------------------------------------
401,955 289,010
Long-term debt (note 8) 483,791 215,949
Asset retirement obligations 35,485 18,811
Future income taxes 193,241 58,229
Risk management (note 11) 49,292 30,166
Convertible debentures (note 9) 16,880 -
Other long-term liabilities 5,910 2,948
----------------------------------------------------------------------------
1,186,554 615,113
Unitholders' equity (notes 12 and 13) 882,610 584,688
----------------------------------------------------------------------------
$ 2,069,164 $ 1,199,801
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the Consolidated Financial Statements.
Consolidated Statements of Income and Accumulated Earnings
(unaudited)
Three months ended Six months ended
($ thousands except per unit amounts) June 30 June 30
2008 2007 2008 2007
----------------------------------------------------------------------------
REVENUE
Operating $489,832 $340,634 $932,294 $766,676
Unrealized gain (loss) on risk
management (2,896) 413 (2,268) 475
Other 149 731 1,510 2,692
----------------------------------------------------------------------------
487,085 341,778 931,536 769,843
----------------------------------------------------------------------------
EXPENSES
Cost of sales 369,800 261,682 703,503 610,455
Operating and administrative 63,447 37,014 110,594 75,075
Amortization:
Capital assets 14,448 9,951 27,965 20,239
Energy arrangements, contracts
and relationships 2,376 1,903 4,860 3,807
----------------------------------------------------------------------------
450,071 310,550 846,922 709,576
----------------------------------------------------------------------------
Interest expense
Short-term debt 389 88 1,173 148
Long-term debt 5,929 2,960 12,144 5,976
----------------------------------------------------------------------------
Income before income taxes 30,696 28,180 71,297 54,143
Income tax expense (recovery) (2,215) 7,127 807 8,510
----------------------------------------------------------------------------
Net income 32,911 21,053 70,490 45,633
Accumulated earnings,
beginning of period 547,991 426,198 510,412 401,618
----------------------------------------------------------------------------
Accumulated earnings,
end of period $580,902 $447,251 $580,902 $447,251
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income per unit (note 15)
Basic $ 0.49 $ 0.37 $ 1.06 $ 0.80
Diluted $ 0.49 $ 0.37 $ 1.06 $ 0.80
Weighted average number of units
outstanding (thousands) (notes 13
and 15)
Basic 67,382 57,199 66,223 56,931
Diluted 68,302 57,235 67,157 56,966
See accompanying notes to the Consolidated Financial Statements.
Consolidated Statements of Comprehensive Income
and Accumulated Other Comprehensive Income
(unaudited)
Three months ended Six months ended
June 30 June 30
($ thousands) 2008 2007 2008 2007
----------------------------------------------------------------------------
Net income $ 32,911 $ 21,053 $ 70,490 $ 45,633
Other comprehensive income, net of tax
Unrealized net gain (loss) on
available for sale financial assets - 10,383 (17,873) 10,399
Unrealized net loss on derivatives
designated as cash flow hedges (11,480) (4,570) (14,866) (4,086)
Reclassification to net income of
net gain (loss) on derivatives
designated as cash flow hedges
pertaining to prior periods 477 (3,170) (2,423) (3,389)
----------------------------------------------------------------------------
(11,003) 2,643 (35,162) 2,924
----------------------------------------------------------------------------
Comprehensive income $ 21,908 $ 23,696 $ 35,328 $ 48,557
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated other comprehensive
income (loss), beginning of period $ 3,010 $ (2,353) $ 27,169 -
Adjustment resulting from adoption
of new financial instrument
accounting standards - - - (2,634)
Other comprehensive income (loss),
net of tax (11,003) 2,643 (35,162) 2,924
----------------------------------------------------------------------------
Accumulated other comprehensive
income (loss), end of period $ (7,993) $ 290 $ (7,993) $ 290
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the Consolidated Financial Statements.
Consolidated Statements of Cash Flows
(unaudited)
Three months ended Six months ended
June 30 June 30
($ thousands) 2008 2007 2008 2007
----------------------------------------------------------------------------
Cash from operations
Net income $ 32,911 $ 21,053 $ 70,490 $ 45,633
Items not involving cash:
Amortization 16,824 11,854 32,825 24,046
Accretion of asset retirement
obligations 498 424 955 850
Unit-based compensation 95 157 195 331
Future income tax expense
(recovery) (2,413) 7,127 590 8,510
Gain (loss) on sale of assets (311) (1,490) (318) (1,563)
Equity income (loss) (36) (317) (581) (1,693)
Distributions from equity
investments 61 503 137 1,258
Unrealized (gain) loss on risk
management 2,896 (413) 2,268 (475)
Other 115 300 395 547
Asset retirement obligations
settled (161) (20) (217) (140)
Net change in non-cash working
capital (note 16) 28,644 7,397 10,597 15,396
----------------------------------------------------------------------------
79,123 46,575 117,336 92,700
----------------------------------------------------------------------------
Investing activities
Decrease (increase) in customer
deposits (6,022) (6,287) 354 (6,183)
Decrease in note receivable 5,500 - 5,500 -
Acquisition of capital assets (32,545) (9,875) (84,233) (20,888)
Disposition of capital assets 8,843 90 8,843 507
Acquisition of long-term
investments and other assets (399) (420) (261,005) (799)
Disposition of long-term
investments and other assets - 375 - 375
----------------------------------------------------------------------------
(24,623) (16,117) (330,541) (26,988)
----------------------------------------------------------------------------
Financing activities
Increase (decrease) in short-term
debt (7,260) (5,655) (1,252) 1,845
Net issuance (repayment) of
revolving long-term debt (126,130) (19,894) 153,666 (137,113)
Issuance of long-term debt - - - 100,000
Repayment of long-term debt (733) - (733) -
Distributions to unitholders (34,868) (28,959) (68,066) (57,810)
Net proceeds from issuance of units 117,713 13,979 125,424 26,449
Net proceeds from issuance of
warrants (note 12) - - 4,500 -
----------------------------------------------------------------------------
(51,278) (40,529) 213,539 (66,629)
----------------------------------------------------------------------------
Change in cash and cash equivalents 3,222 (10,071) 334 (917)
Cash and cash equivalents, beginning
of period 9,563 22,380 12,451 13,226
----------------------------------------------------------------------------
Cash and cash equivalents, end of
period $ 12,785 $ 12,309 $ 12,785 $ 12,309
----------------------------------------------------------------------------
See accompanying notes to the Consolidated Financial Statements.
Selected Notes to the Consolidated Financial Statements
(unaudited)
(Tabular amounts in thousands of dollars unless otherwise indicated.)
1. BASIS OF PRESENTATION
The interim Consolidated Financial Statements of AltaGas Income Trust (AltaGas or the Trust) include the accounts of the Trust and all of its wholly owned subsidiaries, and its proportionate interests in various partnerships and joint ventures.
The interim Consolidated Financial Statements have been prepared by management in accordance with Canadian generally accepted accounting principles (GAAP). The accounting policies applied are consistent with those outlined in the Trust's annual Consolidated Financial Statements for the year ended December 31, 2007, except as described below in Notes 2 and 3. These interim Consolidated Financial Statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2007 audited Consolidated Financial Statements included in the Trust's Annual Report.
2. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to conform to the current financial presentation.
3. CHANGES IN ACCOUNTING POLICIES
Changes For 2008
Effective January 1, 2008 the Trust adopted the new CICA Handbook accounting requirements for Section 1535 "Capital Disclosures", Section 3031 "Inventories", Section 3862 "Financial Instruments - Disclosures" and Section 3863 "Financial Instruments - Presentation". In accordance with the transitional provisions for these new standards, these policies were adopted prospectively without restatement of prior periods.
Capital Disclosures
CICA Handbook Section 1535 "Capital Disclosures" requires the disclosure of qualitative and quantitative information about the Trust's objectives, policies and processes for managing capital, which have been provided in note 9.
Inventories
Inventory consists of materials and supplies and natural gas liquids (NGL) product held for sale. All inventory is valued at the lower of cost and net realizable value. Cost is assigned using a weighted average cost formula.
Financial Instruments
CICA Handbook Section 3862 "Financial Instruments - Disclosure" and Section 3863 "Financial Instruments - Presentation" replace Section 3861 "Financial Instruments - Disclosure and Presentation" effective January 1, 2008 for the Trust. Section 3862 requires the disclosure of information to allow users to evaluate the significance of the financial instruments on the entity's financial position and performance and the nature and extent of risks arising from financial instruments and how the entity manages those risks. Section 3863 deals with the classification of financial instruments, related interest, dividends, losses and gains, and the circumstances in which financial assets and financial liabilities are offset. The additional information to comply with these standards is disclosed in note 10.
Future Accounting Changes
Section 3064 "Goodwill and Intangible Assets"
Effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2008, the new CICA Handbook Section 3064 will replace Section 3062 "Goodwill and Other Intangible Assets" and Section 3450 "Research and Development Costs". This section establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets including internally generated intangible assets. This new section is effective for the Trust beginning January 1, 2009.
International Financial Reporting Standards (IFRS)
In 2006 the Accounting Standards Board announced a new strategic plan for the convergence of Canadian GAAP with IFRS beginning 2011. 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.
4. UPDATE TO SUMMARY OF ACCOUNTING POLICIES
As a result of the acquisition of Taylor NGL Limited Partnership (Taylor) and AltaGas' issuance of warrants, the Trust has updated the following significant accounting policies.
Energy Arrangements, Contracts, Relationships and Amortization
Energy arrangements, contracts and relationships are recorded at cost, which was fair value at the time of purchase, and are amortized on a straight-line basis over their term or estimated useful life:
Sundance B Power Purchase Arrangements (PPAs) 19 years Natural gas and power marketing contracts 18 - 49 months Energy services relationships 15 years Extraction and transmission contracts (E&T) 10 - 30 years
AltaGas owns 50 percent of two Sundance B PPAs through its interest in the ASTC Power Partnership (ASTC). ASTC is committed to purchase all of the power from the two 353-megawatt (MW) capacity Sundance B generating units. The investment in the PPAs and the corresponding revenue and expenses thereunder are recorded on a proportionate basis. The Sundance B PPAs required a capital outlay to acquire. The Trust is obligated to make payments to the owners of the underlying generating units over the remaining terms of the PPAs to December 31, 2020. Such amounts are recorded as cost of sales as incurred. Revenue from the sale of the committed power is recorded when delivered.
The natural gas and power marketing contracts are the rights and obligations to buy and sell fixed volumes of natural gas and power at contracted prices. Revenue and expenses are recorded when product is delivered.
Energy services relationships were purchased along with substantially all of the assets and liabilities of iQ2 Power Corp., AltaGas Energy Limited Partnership, ECNG Canada Ltd. and Energistics Group Inc., and are recorded at fair value and amortized on a straight-line basis commencing with the expiration of the related short-term marketing contracts over the 15-year expected useful life of the relationships.
The E&T contracts were acquired through the acquisition of Taylor and are recorded at fair value and amortized on a straight-line basis over the average expected life of the contracts.
Per Unit Information
Basic net income per unit is calculated on the basis of the weighted average number of trust and exchangeable units outstanding during the period. Diluted net income per unit is calculated as if the proceeds obtained upon exercise of options were used to purchase units at the average market price during the period plus the trust units issuable on conversion of outstanding convertible debentures and warrants. Diluted net income is increased by the interest on the convertible debentures and decreased by the accretion on the convertible debentures.
Convertible Debentures
Convertible debentures are recorded at fair value upon acquisition, less the amount attributed to the conversion feature, which is included as part of unitholders' equity. The difference between the fair value and the principal amount is charged to income on an effective yield basis.
Warrants
Warrants are recorded at fair value, deemed to be the gross proceeds upon issue, and are included as part of unitholders' equity.
5. BUSINESS ACQUISITION
On January 10, 2008 AltaGas Holding Limited Partnership No. 1 (AltaGas LP #1) acquired all of the outstanding limited partnership units of Taylor (other than the Taylor units already owned by AltaGas and its affiliates). Taylor participated in the energy business through ownership of natural gas liquids extraction plants, natural gas processing assets and two natural gas liquids pipelines. It also had an interest in a 7-MW run-of-river hydroelectric generation plant.
AltaGas offered Taylor unitholders $11.20 in cash or 0.42 units of AltaGas per unit of Taylor, subject to maximum aggregate limits of $245.0 million in cash and 8.0 million Trust units, including up to approximately 1.9 million exchangeable units. Prior to closing the acquisition, $27.9 million of Taylor convertible debentures were redeemed, increasing Taylor units outstanding by 2.7 million. The aggregate purchase price was $598.7 million, including $256.3 million of cash and 7.7 million Trust units (including 0.2 million exchangeable units) valued at $198.9 million for all the outstanding units not previously owned by AltaGas, assumed debt and convertible debentures of $132.5 million and approximately $11 million in transaction costs. The value of the Trust units issued was determined based on the weighted average market price between two days preceding and two days subsequent to November 11, 2007, the date the offer had been agreed upon and announced.
The following table summarizes the total consideration and the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition. Any final adjustments may significantly change the allocation of the purchase price and could affect the fair value assigned to assets and liabilities. The preliminary allocation of the purchase price is as follows:
Total consideration for 100% of Taylor
Cost of 8.9% investment in Taylor originally owned
by AltaGas $ 24,672
Purchase price for the remaining 91.1% of Taylor
units
Cash consideration 256,281
Units 198,861
Estimated transaction costs 11,000
Equity portion of Taylor convertible debentures 2,127 468,269
----------------------------------------------------------------------------
Total consideration $ 492,941
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Purchase price allocation for 100% of Taylor
Assets acquired
Current assets 30,585
Capital assets 592,030
Energy service arrangements, contracts and
relationships 84,000
Goodwill 106,316
Long-term investments and other assets 4,640 817,571
----------------------------------------------------------------------------
Less liabilities assumed
Current liabilities 27,550
Long-term debt 110,423
Convertible debentures 22,171
Asset retirement obligations 14,350
Future income taxes 144,616
Future employee obligations 2,542
Risk management 2,978 324,630
----------------------------------------------------------------------------
$ 492,941
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Until the date of acquisition, AltaGas accounted for its investment in Taylor using the cost method. As a result, the investment in Taylor was designated as available for sale and was measured at fair value with the changes in fair value recorded in other comprehensive income (OCI). As of January 10, 2008 Taylor has been included in AltaGas' Consolidated Financial Statements.
AltaGas drew on its available credit facility to finance the cash consideration of $256.3 million for the Taylor acquisition.
6. CAPITAL ASSETS
June 30
2008
----------------------------------------------------------------------------
Accumulated Net book
Cost amortization value
----------------------------------------------------------------------------
Extraction and Transmission
Extraction and transmission assets $ 827,947 $ (57,711) $ 770,236
Field Gathering and Processing
Field gathering and processing
assets 604,594 (161,663) 442,931
Other assets 5,945 (2,651) 3,294
Energy Services
Energy services assets 9,909 (1,076) 8,833
Other assets 1,310 (260) 1,050
Power Generation
Capital lease (note 8) 13,798 (5,306) 8,492
Power generation assets 75,935 - 75,935
Corporate
Other assets 22,836 (13,366) 9,470
----------------------------------------------------------------------------
$ 1,562,274 $ (242,033) $ 1,320,241
----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31
2007
----------------------------------------------------------------------------
Accumulated Net book
Cost amortization value
----------------------------------------------------------------------------
Extraction and Transmission
Extraction and transmission assets $ 255,810 $ (46,078) $ 209,732
Field Gathering and Processing
Field gathering and processing
assets 569,944 (148,297) 421,647
Other assets 4,416 (2,161) 2,255
Energy Services
Energy services assets 9,693 (896) 8,797
Other assets 2,018 (156) 1,862
Power Generation
Capital lease (note 8) 13,798 (4,596) 9,202
Power generation assets 22,013 - 22,013
Corporate
Other assets 19,230 (12,416) 6,814
----------------------------------------------------------------------------
$ 896,922 $ (214,600) $ 682,322
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest capitalized on long-term capital construction projects for the six months ended June 30, 2008 was $1.1 million (December 31, 2007 - $0.8 million). At June 30, 2008 the Trust had spent approximately $113.4 million (December 31, 2007 - $42.6 million) on capital projects under construction that were not yet subject to amortization.
In January 2008 the Trust completed the acquisition of Taylor (note 4) which resulted in the increase to the extraction and transmission and field gathering and processing assets.
7. ENERGY ARRANGEMENTS, CONTRACTS AND RELATIONSHIPS
June 30
2008
----------------------------------------------------------------------------
Accumulated Net book
Cost amortization value
----------------------------------------------------------------------------
Energy Services and E&T
arrangements and contracts $ 199,070 $ (41,881) $ 157,189
Energy services relationships 20,892 (3,226) 17,666
----------------------------------------------------------------------------
$ 219,962 $ (45,107) $ 174,855
----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31
2007
----------------------------------------------------------------------------
Accumulated Net book
Cost amortization value
----------------------------------------------------------------------------
Energy Services and E&T
arrangements and contracts $ 115,071 $ (37,717) $ 77,354
Energy services relationships 20,892 (2,530) 18,362
----------------------------------------------------------------------------
$ 135,963 $ (40,247) $ 95,716
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The amortization of the energy services relationships began in 2006 upon expiration of the corresponding short-term marketing contracts.
In January 2008 the Trust completed the acquisition of Taylor (note 4) which resulted in the majority of additions since December 31, 2007.
8. LONG-TERM DEBT
June 30 December 31
2008 2007
----------------------------------------------------------------------------
Operating loans $ 277,000 $ 8,000
Medium-term notes 200,000 200,000
Capital lease obligations 9,432 10,034
Other long-term debt 1,407 -
Unamortized deferred financing (2,698) (851)
----------------------------------------------------------------------------
485,141 217,183
Less current portion 1,350 1,234
----------------------------------------------------------------------------
$ 483,791 $ 215,949
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating Loans
At June 30, 2008 the Trust held a $375.0 million (December 31, 2007 - $300.0 million) unsecured extendible revolving three-year credit facility with a syndicate of Canadian chartered banks. Borrowings on the facility can be by way of prime loans, U.S. base rate loans, LIBOR loans, bankers' acceptances or documentary credits. Borrowings on the facility have fees and interest at rates relevant to the nature of the draw. On September 30, 2007 AltaGas negotiated the extension of the maturity date of this facility to September 30, 2010.
On March 31, 2008 the Trust negotiated a new $250.0 million unsecured 18-month credit facility with a syndicate of Canadian chartered banks. Borrowings on the facility can be by way of prime loans, U.S. base rate loans, LIBOR loans or bankers' acceptances. Borrowings on the facility bear fees and interest rates relevant to the nature of the draw and the facility matures on September 28, 2009.
At June 30, 2008 the Trust had drawn $277.0 million (December 31, 2007 - $8.0 million) against the facilities. The prime lending rate at June 30, 2008 was 4.75 percent (December 31, 2007 - 6.0 percent). The average rate on the Trust's bankers' acceptances at June 30, 2008 was 4.0 percent (December 31, 2007 - 5.2 percent).
Medium-Term Notes
On August 30, 2005 $100.0 million of 4.41 percent senior unsecured MTNs were issued. The notes mature on September 1, 2010, with interest payable semi-annually.
On January 19, 2007 AltaGas issued a further $100.0 million of senior unsecured MTNs. The notes carry a coupon rate of 5.07 percent and mature on January 19, 2012. The net proceeds were used to pay down existing bank indebtedness and for general corporate purposes.
Letter of Credit Facility
At June 30, 2008 the Trust held a $75.0 million (December 31, 2007 - $75.0 million) unsecured three-year extendible revolving-term letter of credit facility with a Canadian chartered bank maturing on September 30, 2010. AltaGas may borrow up to $25.0 million by way of prime loans, U.S. base rate loans, LIBOR loans or bankers' acceptances on the letter of credit facility. Borrowings on the facility bear fees and interest at rates relevant to the nature of the draw made. At June 30, 2008 the Trust had letters of credit of $63.0 million (December 31, 2007 - $61.7 million) outstanding against the extendible revolving-term letter of credit facility.
9. CONVERTIBLE DEBENTURES
On January 10, 2008 AltaGas assumed a principal amount of $22.1 million of 5.85 percent convertible debentures through the acquisition of Taylor. The debentures mature on September 10, 2010, with interest payable semi-annually on September 10 and March 10 of each year. Prior to maturity, the debentures may be converted into trust units at the option of the holder at a conversion price of $24.64 per trust unit.
The Trust may redeem the convertible debentures after September 10, 2008 and prior to September 10, 2009 in whole or in part at a price equal to their principal amount plus accrued and unpaid interest, if any, provided the current market price of the trust units on the date notice is given is not less than 125 percent of the conversion price, subject to adjustment in certain events. After September 10, 2009 and prior to the convertible debentures' maturity, the Trust may redeem the convertible debentures at a price equal to their principal amount plus accrued and unpaid interest, if any. The Trust can elect to pay interest on the debentures by issuing trust units.
---------------------------------------------------------------------------- Balance, December 31, 2007 $ - Fair value of convertible debentures (note 5) 22,171 Accretion (9) Conversion to Trust units (1,128) Redeemed for cash (4,154) ---------------------------------------------------------------------------- Balance, June 30, 2008 $ 16,880 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------
10. CAPITAL DISCLOSURE
The Trust's objective for managing capital is to maintain its investment-grade credit rating and allow the Trust to maximize the profitability of its existing assets and grow its energy infrastructure to create long-term value and enhance returns for its investors. The Trust considers Unitholders' Equity (including Accumulated Other Comprehensive Income), short-term and long-term debt (including current portion) less cash and cash equivalents to be part of its capital structure. The Trust's overall strategy remained unchanged from 2007.
The use of debt or equity funding is based on AltaGas' capital structure, which is determined by considering the norms and risks associated with each of its business segments. AltaGas' target debt-to-total-capitalization ratio is 40 to 45 percent. The Trust's debt-to-total capitalization ratio as at June 30, 2008 was 36.4 percent (December 31, 2007 - 27.4 percent).
All of the borrowing facilities have financial tests and other covenants customary for the types of facilities which must be met at each quarter-end. AltaGas has been in compliance with these covenants each quarter since the issuance of the facilities.
11. FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT
In the course of normal operations the Trust purchases and sells natural gas, natural gas liquids and power commodities and issues short and long-term debt. The Trust uses derivative instruments to reduce exposure to fluctuations in commodity prices, interest rates and foreign currency exchange rates that arise from these activities. The Trust does not make use of derivative instruments for speculative purposes.
Fair Values of Financial Instruments
At June 30, 2008 all derivatives, other than those that meet the expected purchase, sale or usage requirements exception, were carried on the balance sheet at fair value. The fair value of power, natural gas and NGL derivatives was calculated using estimated forward prices from published sources for the relevant period. The calculation of fair value of the interest rate and foreign exchange derivatives used quoted market rates.
The fair value of long-term debt has been estimated based on discounted future interest and principal payments using estimated interest rates. The fair value of the convertible debentures was estimated using a Black Scholes model.
The carrying amount and fair values of the Trust's financial assets and liabilities were as follows:
Summary of Fair Values
June 30 December 31
2008 2007
Carrying Fair Carrying Fair
($ thousands) amount value amount value
----------------------------------------------------------------------------
Financial assets
Held for trading
Cash and cash equivalents(1) 12,785 12,785 12,451 12,451
Risk management - derivatives(2) 136,616 136,616 83,200 83,200
Cash flow hedges
Risk management(2) 21,884 21,884 17,251 17,251
Loans and receivables
Accounts receivable and other
assets(1) (3) 222,520 222,520 194,936 194,936
Customer deposits(1) 24,015 24,015 24,369 24,369
Available for sale
Long-term investments and other
assets - - 44,746 44,746
----------------------------------------------------------------------------
$ 417,820 $ 417,820 $ 376,953 $ 376,953
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Financial liabilities
Held for trading
Risk management - derivatives(2) 145,432 145,432 86,799 86,799
Cash flow hedges
Risk management(2) 33,459 33,459 4,215 4,215
Other financial liabilities
Accounts payable and other
liabilities(1) (4) 225,133 225,133 185,943 185,943
Customer deposits(1) 24,015 24,015 24,369 24,369
Short-term debt 2,298 2,298 3,663 3,663
Long-term debt(5) 487,839 482,679 218,033 208,036
Convertible debentures 16,880 18,384 - -
----------------------------------------------------------------------------
$ 935,056 $ 931,400 $ 523,022 $ 513,025
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Due to the nature and/or short maturity of these financial instruments
the carrying amount approximates the fair value.
(2) Fair value is equal to the carrying value for derivatives and hedged
items.
(3) Excludes income and sales tax of $9,356 (December 31, 2007 - $6,656).
(4) Excludes income and sales tax and deferred revenue of $4,369
(December 31, 2007 - $1,180).
(5) Includes current portion of long-term debt and excludes deferred
financing of $2,698 (December 31, 2007 - $850).
Summary of Unrealized Gain (Loss) on Risk Management
Three months ended Six months ended
June 30 June 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Natural gas 472 618 828 910
Natural gas liquids (4,553) - (1,601) -
Power 74 (60) 71 (65)
Heat rate - - (188) -
Interest rate swaps 1,276 1 (657) 1
Foreign exchange (165) (146) (721) (371)
----------------------------------------------------------------------------
Total (2,896) 413 (2,268) 475
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Market Risk on Financial Instruments
The Trust is exposed to market risk and potential loss from changes in the values of financial instruments. AltaGas enters into financial derivative contracts to manage exposure to fluctuations in commodity prices, interest rates and foreign exchange rates.
Commodity Price Risk Management
Natural Gas
The Trust purchases and sells natural gas to its customers. The fixed-price and market-price contracts for both the purchase and sale of natural gas extend to 2012.
The Trust had the following contracts outstanding:
As at June 30, 2008 Notional volume (GJ)
-------------------------
Derivative Fixed price Period
Instruments (per GJ) (months) Sales Purchases Fair value
----------------------------------------------------------------------------
Commodity
forward $ 2.16 to $10.37 1 - 49 86,055,360 - $ (126,364)
Commodity
forward $ 2.16 to $10.37 1 - 49 - 86,055,360 $ 124,171
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at December 31, 2007 Notional volume (GJ)
-------------------------
Derivative Fixed price Period
Instruments (per GJ) (months) Sales Purchases Fair value
----------------------------------------------------------------------------
Commodity
forward $ 2.16 to $10.37 1 - 55 105,375,003 - $ (17,775)
Commodity
forward $ 2.16 to $10.37 1 - 55 - 105,375,003 $ 14,754
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In second quarter 2008 the Trust recognized an unrealized gain of $0.5 million (June 30, 2007 - $0.6 million) from the Trust's natural gas risk management activities.
Natural Gas Liquids
The Trust entered into a series of swaps to lock in a portion of the volumes exposed to NGL frac spread.
The Trust had the following contracts outstanding:
As at June 30, 2008 Notional volume
--------------------------
Period
Product Fixed price (months) Sales Purchases Fair Value
----------------------------------------------------------------------------
Propane $1.2825 to $1.7200 36,901,368
US/gallon 1 - 30 gallons - $ (15,184)
Normal
butane $1.4950 to $2.1000 11,552,592
US/gallon 1 - 30 gallons - (6,594)
WTI $83.20 to $125.35 155,504
US/Bbl 1 - 30 Bbls - (5,768)
Natural
gas $6.54 to $9.95
/GJ 1 - 30 - 4,399,328 GJ $ 17,697
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at December 31, 2007 Notional volume
--------------------------
Period
Product Fixed price (months) Sales Purchases Fair Value
----------------------------------------------------------------------------
Propane $1.2825 to $1.4725 9,677,178
US/gallon 1 - 12 gallons - $ (1,156)
Normal
butane $1.4950 to $1.7000 2,612,064
US/gallon 1 - 12 gallons - (685)
WTI $83.20 to $89.10 27,489
US/Bbl 1 - 12 Bbls - (143)
Natural
gas $6.455 to $6.550/GJ 1 - 12 - 1,382,591 GJ $ 159
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In second quarter 2008 the Trust recognized an unrealized loss of $4.6 million (June 30, 2007 - nil) from the Trust's NGL risk management activities.
Power
Under the power purchase arrangements AltaGas has an obligation to buy power at agreed terms and prices to December 31, 2020. The Trust sells the power to the Alberta Electric System Operator at market prices and uses swaps and collars to fix the prices over time on a portion of the volumes. AltaGas' strategy is to lock in margins to provide predictable earnings. Certain contracts met the expected purchase, sale or usage requirements exception and have not been included in risk management assets or liabilities. At June 30, 2008 the Trust had no intention to terminate any contracts prior to maturity.
The Trust had no contracts outstanding at June 30, 2008.
As at December 31, 2007 Notional volume (MWh)
-------------------------
Derivative Fixed price Period
Instruments (per MWh) (months) Sales Purchases Fair Value
----------------------------------------------------------------------------
Commodity
forward $ 79.00 to $80.60 1 - 3 2,160 - $ (28)
Commodity
forward $ 63.25 to $68.00 1 - 3 - 2,160 $ 31
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Trust's power risk management activities from financial contracts not included in the hedging program had an unrealized gain of $0.1 million in second quarter 2008 (June 30, 2007 - loss of $0.1 million).
The Trust had the following commodity swaps and collars outstanding:
As at June 30, 2008 Notional volume (MWh)
-------------------------
Derivative Fixed price Period
Instruments (per MWh) (months) Sales Purchases Fair Value
----------------------------------------------------------------------------
Swaps and
collars $ 65.00 to $88.00 1 to 18 1,657,224 - $ (13,765)
Swaps and
collars $ 56.50 1 to 114 - 265,368 $ 7,026
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at December 31, 2007 Notional volume (MWh)
-------------------------
Derivative Fixed price Period
Instruments (per MWh) (months) Sales Purchases Fair Value
----------------------------------------------------------------------------
Swaps and
collars $ 65.00 to $88.00 1 to 24 1,626,624 - $ 10,932
Swaps and
collars $ 56.50 1 to 120 - 263,016 $ 3,339
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Trust had no heat rate hedges outstanding at June 30, 2008.
The Trust had the following heat rate hedges outstanding as at December 31, 2007:
Notional volume
As at December 31, 2007 (GJ or MWh)
----------------------
Derivative Fixed price Period
Instruments (per GJ or MWh) (months) Sales Purchases Fair value
----------------------------------------------------------------------------
Natural gas
(per GJ) $ 6.08 to $6.17 1 - 79,050 $ 17,968
Power
(per MWh) $ 89.00 to $138.00 1 6,510 - $ 170,019
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In second quarter 2008 the Trust recognized no unrealized gain or loss (June 30, 2007 - $0.2 million) from heat rate hedging activities.
Interest Rate Risk Management
To hedge against the effect of future interest rate movements, the Trust enters into interest rate swap agreements to fix the interest rate on a portion of its bankers' acceptances issued under credit facilities. The interest rate swaps have an average remaining term of 6 to 21 months and a weighted average interest rate of 3.75 percent. The Trust's target is to have approximately 70 to 75 percent of its debt at fixed interest rates.
At June 30, 2008 the Trust's interest rate risk management activities resulted in an unrealized gain of $1.3 million (June 30, 2007 - nil) and fair market value position of $0.5 million.
Foreign Exchange Risk Management
To manage the risk of fluctuating cash flows due to variations in foreign exchange rates, the Trust enters into foreign exchange forward contracts. At June 30, 2008 the Trust's foreign exchange risk management activities had an unrealized loss of $0.2 million (June 30, 2007 - $0.1 million) and fair market value position of $1.0 million.
Sensitivity Analysis
The following table illustrates potential effects of changes in relevant risk variables on AltaGas' net income and OCI as at June 30, 2008:
Increase Increase
or or
decrease decrease
Increase or in net in
Factor Share decrease income OCI
----------------------------------------------------------------------------
Alberta electricity prices $1/MWh - 945
Natural gas liquids frac spread(1) $1/Bbl 189 282
Interest rate swaps 25 bps 513 -
(1) Estimates the impact if condensate, propane, butane and natural gas
increased (decreased) by $1/Bbl.
Credit Risk on Financial Instruments
Credit risk results from the possibility that a counterparty to a financial instrument from which the Trust has an amount owing fails to fulfill its obligations in accordance with the terms of the contract.
AltaGas' credit policy details the parameters used to grant, measure, monitor and report on credit provided to counterparties. AltaGas minimizes counterparty risk by conducting credit reviews on counterparties in order to establish specific credit limits on clients, both prior to providing products or services and on a recurring basis. In addition, most contracts include credit mitigation clauses which allow for AltaGas to obtain financial or performance assurances from counterparties under certain circumstances. AltaGas provides an allowance for doubtful accounts in the normal course of its business.
The Trust's maximum credit exposure consists primarily of the carrying value of the non-derivative financial assets and the fair value of derivative financial assets. At June 30, 2008 AltaGas did not have a significant concentration of credit risk with any single counterparty to financial instruments.
Liquidity Risk on Financial Instruments
Liquidity risk is the risk that the Trust will not be able to meet its financial obligations as they fall due. The Trust manages this risk through its extensive budgeting and monitoring process to ensure it has sufficient cash and credit facilities to meet its obligations. The Trust's objective is to maintain its investment-grade ratings to ensure it has access to debt and equity funding as required (see note 9).
At June 30, 2008 the Trust has the following contractual maturities with respect to non-derivative financial liabilities:
Payments Due by period
------------------------
Total 2008 2009 2010 2011 Thereafter
----------------------------------------------------------------------------
Short-term debt 2,298 2,298 - - - -
Long-term
debt(1)(2) 487,839 1,350 101,316 278,409 1,508 105,256
----------------------------------------------------------------------------
Total $ 490,137 $ 3,648 $ 101,316 $ 278,409 $ 1,508 $ 105,256
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Comprised of operating loans, medium-term notes and capital lease
obligations excluding deferred financing costs (note 7).
(2) Includes current portion of long-term debt.
12. UNITHOLDERS' EQUITY
June 30 December 31
2008 2007
----------------------------------------------------------------------------
Unitholders' capital (note 13) $ 832,596 $ 505,544
Contributed surplus (note 15) 4,069 3,875
Accumulated earnings 580,902 510,412
Convertible debentures 1,160 -
Warrants 4,500 -
Accumulated dividends (41,114) (41,114)
Accumulated unitholders' distributions
declared(1) (461,415) (391,103)
Distributions of common shares of Utility Group (29,848) (29,848)
Transition adjustment resulting from adopting
new financial instruments accounting
standards (247) (247)
Accumulated other comprehensive income (7,993) 27,169
----------------------------------------------------------------------------
$ 882,610 $ 584,688
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Accumulated unitholders' distributions paid by the Trust as at June 30,
2008 were $449.0 million (as at December 31, 2007 - $380.9 million).
In 2007 the holders of trust units of the Trust and holders of exchangeable partnership units of AltaGas Holding Limited Partnership No. 1 received one common share of AltaGas Utility Group Inc. (Utility Group) for every 100 trust or exchangeable units held on August 27, 2007. As part of the distribution plan, any unitholder allocated fewer than 50 common shares of Utility Group received cash. The number of common shares of Utility Group distributed to unitholders was 577,416, which reduced unitholders equity by $4.2 million. This distribution resulted in a 27 percent reduction of the Trust's interest in Utility Group to 19.6 percent.
13. UNITHOLDERS' CAPITAL
Trust Units Issued and Outstanding Number of units Amount
----------------------------------------------------------------------------
December 31, 2007 56,057,438 $ 493,866
Units issued for cash on exercise of options 2,150 55
Units issued under DRIP(1) 676,510 15,965
Units issued for exchangeable units 25,161 253
Units issued on business acquisition 7,553,174 194,645
Units issued on conversion of convertible
debentures 45,771 2,094
Units issued on public offering (net of $5.2
million of issuance costs) 4,398,750 110,077
----------------------------------------------------------------------------
June 30, 2008 68,758,954 $ 816,955
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exchangeable Units Issued and Outstanding
----------------------------------------------------------------------------
December 31, 2007 issued by AltaGas LP #1 2,040,456 11,678
AltaGas LP #1 units redeemed for trust units (25,161) (253)
Units issued on business acquisition 163,607 4,216
----------------------------------------------------------------------------
June 30, 2008 2,178,902 15,641
----------------------------------------------------------------------------
Issued and outstanding at June 30, 2008 70,937,856 $ 832,596
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Premium Distribution(TM), Distribution Reinvestment and Optional Unit
Purchase Plan.
Three Months Ended Six Months Ended
June 30 June 30
Units Outstanding (1) 2008 2007 2008 2007
----------------------------------------------------------------------------
Number of units - basic(2) 67,382,085 57,199,103 66,223,220 56,931,021
Dilutive stock options 920,389 36,233 933,845 34,715
----------------------------------------------------------------------------
Number of units - diluted(2) 68,302,474 57,235,336 67,157,065 56,965,736
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes exchangeable units.
(2) Weighted average.
The Trust has an employee unit option plan under which both employees and directors are eligible to receive grants. At June 30, 2008, 10 percent of units outstanding were reserved for issuance under the plan. To June 30, 2008 options granted under the plan generally had a term of 10 years to expiry and vested no longer than over a four-year period.
At June 30, 2008 outstanding options were exercisable at various dates to the year 2018 (December 31, 2007 - 2017). Options outstanding under the plan have a weighted average exercise price of $25.73 (December 31, 2007 - $26.36) and a weighted average remaining term of 8.6 years (December 31, 2007 - 8.76 years). As at June 30, 2008 the unexpensed fair value of unit option compensation cost associated with future periods was $0.5 million (December 31, 2007 - $0.7 million).
The following table summarizes information about the Trust's unit options:
Options outstanding
----------------------------------------------------------------------------
Number of Exercise
options price(1)
----------------------------------------------------------------------------
Unit options outstanding, December 31, 2007 1,310,400 $ 26.36
Granted 413,750 23.99
Exercised (2,150) 17.17
Cancelled (130,750) 26.69
----------------------------------------------------------------------------
Unit options outstanding, June 30, 2008 1,591,250 $ 25.73
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Unit options exercisable, June 30, 2008 250,159 $ 23.16
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Weighted average.
A summary of the employee unit option plan as at June 30, 2008:
Options outstanding Options exercisable
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Remaining
Number Exercise contractual Number Exercise
outstanding(1) price(2) life(3) exercisable(1) price(2)
----------------------------------------------------------------------------
$5.00 - 7.00 9,000 $ 6.10 1.95 9,000 $ 6.10
$7.01 - 15.50 27,500 10.29 4.66 27,500 10.29
$15.51 - 25.08 704,000 24.21 9.11 85,992 24.23
$25.09 - 29.50 850,750 27.69 8.37 127,667 26.42
----------------------------------------------------------------------------
1,591,250 $ 25.73 8.60 250,159 $ 23.16
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) As at June 30, 2008.
(2) Weighted average.
(3) Weighted average number of years.
In 2004 AltaGas implemented a unit-based compensation plan, which awards phantom units to certain employees. The phantom units are valued on distributions declared and the trading price of the Trust's units. The units vest on a graded vesting schedule. The compensation expense recorded in second quarter 2008 in respect of this plan was $1.4 million (second quarter 2007 - $1.0 million). As at June 30, 2008 the unexpensed fair value of unit-based compensation costs associated with future periods was $13.5 million (December 31, 2007 - $14.2 million).
14. CONTRIBUTED SURPLUS
June 30 December
2008 31 2007
----------------------------------------------------------------------------
Balance, beginning of period $ 3,875 $ 3,322
Amortization of unit options 223 617
Exercise of unit options (18) (18)
Cancellation of unit options (11) (46)
----------------------------------------------------------------------------
Balance, end of period $ 4,069 $ 3,875
----------------------------------------------------------------------------
15. INCOME PER UNIT
The following table summarizes the computation of net income per unit:
Three Months Ended Six Months Ended
June 30 June 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Numerator:
Numerator for basic income per unit $ 32,911 $ 21,053 $ 70,490 $ 45,633
Numerator for diluted income per
unit $ 33,156 $ 21,053 $ 70,995 $ 45,633
----------------------------------------------------------------------------
Denominator:
Weighted-average number of units 67,382 57,199 66,223 56,931
Dilutive unit options 920 36 934 35
----------------------------------------------------------------------------
Denominator for diluted income per
unit 68,302 57,235 67,157 56,966
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Basic income per unit $ 0.49 $ 0.37 $ 1.06 $ 0.80
Diluted income per unit $ 0.49 $ 0.37 $ 1.06 $ 0.80
----------------------------------------------------------------------------
----------------------------------------------------------------------------
16. NET CHANGE IN NON-CASH WORKING CAPITAL
The net change in the following non-cash working capital items increased (decreased) cash flows from operations as follows:
Three Months Ended Six Months Ended
June 30 June 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Accounts receivable (1) $ (7,874) $ 34,605 $ 1,065 $ 66,834
Inventory 709 - - (50)
Other current assets (2) (4,655) (482) (3,683) 6,296
Accounts payable and accrued
liabilities (1) 12,577 (31,959) (874) (62,657)
Customer deposits 6,022 6,287 (354) 6,183
Deferred revenue 459 225 1,059 423
Other current liabilities 14,059 337 9,588 (5,256)
----------------------------------------------------------------------------
21,297 9,013 6,801 11,773
Add decrease (increase) in capital
costs payable 7,347 (1,616) 3,796 3,623
----------------------------------------------------------------------------
Net change in non-cash working
capital related to operations $ 28,644 $ 7,397 $ 10,597 $ 15,396
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Specific line items may not tie to net change in Balance Sheet due to
acquisition (note 3).
(2) Excludes note receivable of $5.5 million included in investing
activities.
The following cash payments have been included in the determination of
earnings:
Three Months Ended Six Months Ended
June 30 June 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Interest paid $ 7,151 $ 3,134 $ 12,393 $ 6,253
Income taxes paid $ 7 $ 15 $ 325 $ 96
----------------------------------------------------------------------------
----------------------------------------------------------------------------
17. PENSION PLANS AND RETIREE BENEFITS
During the first quarter of 2008 the Trust assumed two defined benefit pension plans with the acquisition of Taylor. These plans are in relation to the unionized employees at the Younger Extraction Plant and certain employees at the Harmattan Complex. The cost of the defined benefit plans are based on management's estimate of the future rate of return on the fair value of pension plan assets, salary escalations, mortality and other factors affecting the payment of future benefits. AltaGas adjusted the actuarial liability of these plans to follow the same assumptions used under its existing pension plans.
The net pension expense by plan for the period was as follows:
Three Months Ended Six Months Ended
June 30 June 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Defined contribution plan $ 253 $ 383 $ 774 $ 765
Defined benefit plan 174 3 399 6
Supplemental executive retirement plan 291 259 500 518
----------------------------------------------------------------------------
$ 718 $ 645 $ 1,673 $ 1,289
----------------------------------------------------------------------------
----------------------------------------------------------------------------
18. RELATED PARTY TRANSACTIONS
In the normal course of business, the Trust and its affiliates transact with related parties. These transactions are recorded at their exchange amounts and are as follows:
Three Months Ended Six Months Ended
June 30 June 30
----------------------------------------------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Fees for administration, management
and other services paid by:
Utility Group to the Trust $ 48 $ 7 $ 97 $ 15
The Trust to Utility Group $ (45) $ 127 $ 2 $ 265
Natural gas sales by the Trust to
Utility Group subsidiaries $ 16,034 $ 13,428 $ 58,206 $ 52,344
Fees for operating services paid by
Utility Group subsidiaries $ 86 $ 77 $ 154 $ 143
Transportation services provided by
Utility Group subsidiaries $ 122 $ 119 $ 242 $ 243
Office space and furniture rental
payments made by the Trust to
a corporation owned by an employee $ 22 $ 21 $ 44 $ 42
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The resulting amounts due from and to related parties are non-interest bearing and are related to transactions in the normal course of business.
Included in accounts receivable at June 30, 2008 was $2.6 million (December 31, 2007 - $13.5 million) due to the Trust from related parties. Included in accounts payable at June 30, 2008 was $1,000 (December 31, 2007 - $50,000) due from the Trust to related parties.
During third quarter 2007 AltaGas sold its 33.3335 percent interest in the Ikhil Joint Venture to Utility Group for $9.0 million to execute the divestiture of non-core production assets.
19. SEGMENTED INFORMATION
AltaGas is an integrated energy trust with a portfolio of assets and services used to move energy from the source to the end-user. The majority of the transactions among the reporting segments are recorded at the market price of the commodities and the remainder are at the exchange amount. The following describes the Trust's five reporting segments:
Extraction and - NGL processing and extraction plants and transmission
Transmission pipelines to transport natural gas and NGL;
Field Gathering
and Processing - natural gas gathering lines and processing facilities;
Energy Services - energy management and gas services for natural gas and
electricity;
Power Generation - coal-fired and gas-fired power output under power
purchase arrangements and other agreements, gas-fired
power plants as well wind and run-of-river power projects
under development; and
Corporate the costs of providing corporate services and general
corporate overhead, investments in public and private
entities, corporate assets and the effects of changes in
the fair value of risk management contracts.
The following tables show the composition by segment:
Field
Extraction Gathering
Three months ended and and Energy Gas
June 30, 2008 Transmission Processing Services Subtotal
----------------------------------------------------------------------------
Revenue $ 111,243 $ 43,621 $ 294,900 $ 449,764
Unrealized loss on
risk management - - - -
Cost of sales (67,109) (3,057) (291,911) (362,077)
Operating and
administrative (18,318) (27,819) (3,415) (49,552)
Amortization (6,869) (6,992) (523) (14,384)
Interest expense - - - -
----------------------------------------------------------------------------
Income before income
taxes 18,947 5,753 (949) 23,751
----------------------------------------------------------------------------
Net additions
(reductions) to:
Capital assets(1) $ 9,719 $ 7,714 $ 593 $ 18,026
Long-term investment
and other assets(2) - - - -
----------------------------------------------------------------------------
Goodwill $ 124,361 $ 215 - $ 124,576
Segmented assets $1,028,972 $ 557,365 $ 121,747 $ 1,708,084
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended Power Intersegment
June 30, 2008 Generation Corporate Elimination Total
----------------------------------------------------------------------------
Revenue $ 58,071 $ 149 $ (18,003) $ 489,981
Unrealized loss on
risk management - (2,896) - (2,896)
Cost of sales (26,231) - 18,508 (369,800)
Operating and
administrative (548) (12,842) (505) (63,447)
Amortization (1,895) (545) - (16,824)
Interest expense - (6,318) - (6,318)
----------------------------------------------------------------------------
Income before income
taxes 29,397 (22,452) - $ 30,696
----------------------------------------------------------------------------
Net additions
(reductions) to:
Capital assets(1) $ (957) $ 202 - $ 17,271
Long-term investment
and other assets(2) $ - $ - - $ -
----------------------------------------------------------------------------
Goodwill - - - $ 124,576
Segmented assets $ 196,561 $164,519 - $ 2,069,164
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes non-cash transactions of $6,182.
(2) Includes non-cash transactions of $648.
Field
Extraction Gathering
Six months ended and and Energy Gas
June 30, 2008 Transmission Processing Services Subtotal
----------------------------------------------------------------------------
Revenue $ 220,203 $ 77,974 $ 561,034 $ 859,211
Unrealized loss on
risk management - - - -
Cost of sales (130,521) (5,804) (554,615) (690,940)
Operating and
administrative (32,967) (48,247) (6,493) (87,707)
Amortization (13,077) (13,848) (1,050) (27,975)
Interest expense - - - -
----------------------------------------------------------------------------
Income before income
taxes 43,638 10,075 (1,124) 52,589
----------------------------------------------------------------------------
Net additions
(reductions) to:
Capital assets(1) $ 572,138 $ 36,179 $ 1,655 $ 609,972
Energy services
arrangements,
contracts and $ 66,000 - - $ 66,000
relationships
Long-term investment
and other assets(2) - - - -
----------------------------------------------------------------------------
Goodwill $ 124,361 $ 215 - $ 124,576
Segmented assets $1,028,972 $ 557,365 $ 121,747 $ 1,708,084
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six Months Ended Power Intersegment
June 30, 2008 Generation Corporate Elimination Total
----------------------------------------------------------------------------
Revenue $ 109,705 $ 1,510 $ (36,622) $ 933,804
Unrealized loss on
risk management - (2,268) - (2,268)
Cost of sales (49,434) - 36,871 (703,503)
Operating and
administrative (1,201) (21,437) (249) (110,594)
Amortization (3,733) (1,117) - (32,825)
Interest expense - (13,317) - (13,317)
----------------------------------------------------------------------------
Income before income
taxes 55,337 (36,629) - $ 71,297
----------------------------------------------------------------------------
Net additions
(reductions) to:
Capital assets(1) $ 54,296 $ 835 - $ 665,103
Energy services
arrangements,
contracts and
relationships $ 18,000 - - 84,000
Long-term investment
and other assets(2) $ 4,861 $ (46,935) - $ (42,074)
----------------------------------------------------------------------------
Goodwill - - - $ 124,576
Segmented assets $ 196,561 $ 164,519 - $2,069,164
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes non-cash transactions of $589,962 mainly due to business
acquisition.
(2) Includes non-cash transactions of $303,328 mainly due to business
acquisition.
Field
Extraction Gathering
Three Months Ended and and Energy Gas
June 30, 2007 Transmission Processing Services Subtotal
----------------------------------------------------------------------------
Revenue $ 33,652 $ 36,811 $ 248,574 $ 319,037
Unrealized gains on
risk management - - - -
Cost of sales (18,387) (1,961) (241,627) (261,975)
Operating and
administrative (4,435) (22,009) (4,327) (30,771)
Amortization (2,006) (6,459) (961) (9,426)
Interest expense - - - -
----------------------------------------------------------------------------
Income before income
taxes 8,824 6,382 1,659 16,865
----------------------------------------------------------------------------
Net additions to:
Capital assets(1) $ 1,639 $ 4,930 $ (30,104) $ (23,535)
Long-term investment
and other assets(2) - - - -
----------------------------------------------------------------------------
Goodwill $ 18,045 $ 215 - $ 18,260
Segmented assets $ 237,419 $ 508,133 $ 99,737 $ 845,289
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended Power Intersegment
June 30, 2007 Generation Corporate Elimination Total
----------------------------------------------------------------------------
Revenue $ 40,691 $ 731 $ (19,094) $ 341,365
Unrealized gains on
risk management - 413 - 413
Cost of sales (17,760) - 18,053 (261,682)
Operating and
administrative (466) (6,818) 1,041 (37,014)
Amortization (1,860) (568) - (11,854)
Interest expense - (3,048) - (3,048)
----------------------------------------------------------------------------
Income before income
taxes 20,605 (9,290) - $ 28,180
----------------------------------------------------------------------------
Net additions to:
Capital assets(1) $ 3,897 $ 454 - $ (19,184)
Long-term investment
and other assets(2) $ 324 $ 11,404 - $ 11,728
----------------------------------------------------------------------------
Goodwill - - - $ 18,260
Segmented assets $ 121,661 $ 212,611 - $1,179,561
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes non-cash transactions of $28,969.
(2) Includes non-cash transactions of $11,683.
Field
Extraction Gathering
Six Months Ended and and Energy Gas
June 30, 2007 Transmission Processing Services Subtotal
----------------------------------------------------------------------------
Revenue $ 70,973 $ 70,041 $ 584,158 $ 725,172
Unrealized gain
(loss) on risk
management - - - -
Cost of sales (39,881) (3,580) (571,167) (614,628)
Operating and
administrative (9,781) (42,902) (8,606) (61,289)
Amortization (4,007) (12,979) (2,203) (19,189)
Interest expense - - - -
----------------------------------------------------------------------------
Income before income
taxes 17,304 10,580 2,182 30,066
----------------------------------------------------------------------------
Net additions
(reductions) to:
Capital assets(1) $ 3,744 $ 6,892 $ (29,566) $ (18,930)
Long-term investment
and other assets(2) - - - -
----------------------------------------------------------------------------
Goodwill $ 18,045 $ 215 - $ 18,260
Segmented assets $ 237,419 $ 508,133 $ 99,737 $ 845,289
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six Months Ended Power Intersegment
June 30, 2007 Generation Corporate Elimination Total
----------------------------------------------------------------------------
Revenue $ 84,984 $ 2,692 $ (43,480) $ 769,368
Unrealized gain
(loss) on risk
management - 475 - 475
Cost of sales (37,593) - 41,766 (610,455)
Operating and
administrative (921) (14,579) 1,714 (75,075)
Amortization (3,721) (1,136) - (24,046)
Interest expense - (6,124) - (6,124)
----------------------------------------------------------------------------
Income before income
taxes 42,749 (18,672) - $ 54,143
----------------------------------------------------------------------------
Net additions
(reductions) to:
Capital assets(1) $ 3,897 $ 1,048 - $ (13,985)
Long-term investment
and other assets(2) $ 478 $ 11,476 - $ 11,954
----------------------------------------------------------------------------
Goodwill - - - $ 18,260
Segmented assets $ 121,661 $ 212,611 - $1,179,561
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes non-cash transactions of $29,866.
(2) Includes non-cash transactions of $11,530.
20. 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 and 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 an additional 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 $12.3 million. As a result, the Trust will own 100 percent of GEDLP. The acquisition is expected to close on August 15, 2008.
Supplementary Quarterly Financial and Operating Information
($ millions unless otherwise
indicated) Q2-08 Q1-08 Q4-07 Q3-07 Q2-07
----------------------------------------------------------------------------
FINANCIAL HIGHLIGHTS(1)
Net Revenue(2)
Extraction and Transmission 44.1 45.6 19.3 17.0 15.3
Field Gathering and
Processing 40.6 31.6 29.4 31.6 34.9
Energy Services 3.0 3.4 4.0 3.9 6.9
Power Generation 31.9 28.4 22.9 33.9 22.9
Corporate (2.8) 2.0 1.1 1.9 1.1
Intersegment Elimination 0.5 (0.3) (0.3) - (1.0)
----------------------------------------------------------------------------
117.3 110.7 76.4 88.3 80.1
----------------------------------------------------------------------------
EBITDA(2)
Extraction and Transmission 25.7 31.0 13.8 12.0 10.8
Field Gathering and
Processing 12.8 11.2 10.9 9.7 12.9
Energy Services (0.4) 0.3 0.6 0.3 2.7
Power Generation 31.4 27.7 22.3 33.4 22.5
Corporate (15.7) (6.6) (7.3) (6.3) (5.8)
----------------------------------------------------------------------------
53.8 63.6 40.3 49.1 43.1
----------------------------------------------------------------------------
Operating Income (Loss)(2)
Extraction and Transmission 18.8 24.8 11.9 9.9 8.8
Field Gathering and
Processing 5.8 4.3 4.5 3.1 6.4
Energy Services (0.9) (0.2) - (0.2) 1.7
Power Generation 29.4 25.9 20.4 31.5 20.6
Corporate (16.1) (7.2) (7.9) (6.8) (6.3)
----------------------------------------------------------------------------
37.0 47.6 28.9 37.5 31.2
----------------------------------------------------------------------------
OPERATING HIGHLIGHTS
Extraction and Transmission
Extraction inlet gas
processed (Mmcf/d)(4) 759 872 463 394 416
Extraction volumes
(Bbls/d)(4) 35,335 41,799 21,179 16,859 19,822
Transmission volumes
(Mmcf/d)(4) (5) 390 379 403 407 407
Frac spread - realized
($/Bbl)(6) 27.61 27.02 29.03 25.24 17.77
Field Gathering and
Processing
Capacity (gross Mmcf/d)(3) 1,178 1,178 1,023 1,008 1,021
Throughput (gross
Mmcf/d)(4) 554 542 511 510 534
Capacity utilization (%)(4) 47 46 50 51 52
Energy Services
Energy management service
contracts(3) 1,514 1,499 1,466 1,451 1,442
Average volumes transacted
(GJ/d)(4) 303,212 324,758 393,936 342,143 356,380
Power Generation
Volume of power sold
(GWh)(4) 648 660 673 673 650
Average price received on
sale of power ($/MWh)(4) 89.46 78.24 68.07 76.92 62.62
Alberta Power Pool average
spot price ($/MWh)(4) 107.56 76.69 61.75 92.00 49.97
----------------------------------------------------------------------------
(1) Columns may not add due to rounding.
(2) Non-GAAP financial measure.
(3) As at period end.
(4) Average for the period.
(5) Excludes natural gas liquids pipeline volumes.
(6) AltaGas reports an indicative frac spread or NGL margin, expressed in
dollars per barrel of NGL, which is derived from Edmonton postings for
propane, butane and condensate and the daily AECO natural gas price.
Other Information
DEFINITIONS
Bbls/d barrels per day
Bcf billion cubic feet
GJ gigajoule
GWh gigawatt-hour
Mcf thousand cubic feet
Mmcf/d million cubic feet per day
MW megawatt
MWh megawatt-hour
ABOUT ALTAGAS
AltaGas Income Trust is one of Canada's largest and fastest growing integrated energy infrastructure organizations. The Trust creates value by growing and optimizing gas and power infrastructure, including a focus on renewable energy sources.
AltaGas Income Trust's units are listed on the Toronto Stock Exchange under the symbol ALA.UN. The Trust is included in the S&P/TSX Composite Index, the S&P/TSX Income Trust Index and the S&P/TSX Capped Energy Trust Index.
FOR FURTHER INFORMATION PLEASE CONTACT:
Media:
AltaGas Income Trust
Adrianne Hartley
(403) 691-9873
Email: adrianne.hartley@altagas.ca
Investment Community
AltaGas Income Trust
Diane Zuber
(403) 691-7102
Email: diane.zuber@altagas.ca
AltaGas Income Trust
Investor Relations
1-877-691-7199
Email: investor.relations@altagas.ca
Website: www.altagas.ca
