Exhibit 99.3
Q1 2010
ALGONQUIN POWER & UTILITIES CORP.
MANAGEMENT’S DISCUSSION & ANALYSIS
Management’s Discussion and Analysis
(All figures are in thousands of Canadian dollars, except per share and convertible debenture values or where otherwise noted)
Management of Algonquin Power & Utilities Corp. (“APUC”), the corporation continuing the business of the Algonquin Power Co. (“Algonquin”), formerly Algonquin Power Income Fund, has prepared the following discussion and analysis to provide information to assist its shareholders’ understanding of the financial results for the three months ended March 31, 2010. This Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with APUC’s unaudited consolidated interim financial statements for the quarter ended March 31, 2010 and 2009 and the notes thereto as well as APUC’s audited consolidated financial statements and APUC’s MD&A for the year ended December 31, 2009. This material is available on SEDAR atwww.sedar.com and on the APUC website atwww.AlgonquinPowerandUtilities.com. Additional information about APUC, including the most recent Annual Information Form (“AIF”) can be found on SEDAR atwww.sedar.com.
This MD&A is based on information available to management as of April 30, 2010.
Caution concerning forward looking statements and non-GAAP Measures
Certain statements included herein contain forward-looking information within the meaning of certain securities laws. These statements reflect the views of APUC with respect to future events, based upon assumptions relating to, among others, the performance of APUC’s assets and the business, interest and exchange rates, commodity market prices, and the financial and regulatory climate in which it operates. These forward looking statements include, among others, statements with respect to the expected performance of APUC, its future plans and its dividends to shareholders. Statements containing expressions such as “outlook”, “believes”, “anticipates”, “continues”, “could”, “expect”, “may”, “will”, “project”, “estimates”, “intend”, “plan” and similar expressions generally constitute forward-looking statements.
Since forward-looking statements relate to future events and conditions, by their very nature they require APUC to make assumptions and involve inherent risks and uncertainties. APUC cautions that although it believes its assumptions are reasonable in the circumstances, these risks and uncertainties give rise to the possibility that our actual results may differ materially from the expectations set out in the forward-looking statements. Material risk factors include the continued volatility of world financial markets; the impact of movements in exchange rates and interest rates; the effects of changes in environmental and other laws and regulatory policy applicable to the energy and utilities sectors; decisions taken by regulators on monetary policy; and the state of the Canadian and the United States (“U.S.”) economies and accompanying business climate. APUC cautions that this list is not exhaustive, and other factors could adversely affect results. Given these risks, undue reliance should not be placed on these forward-looking statements, which apply only as of their dates. APUC reviews material forward-looking information it has presented, at a minimum, on a quarterly basis. Although APUC believes that the assumptions inherent in these forward-looking statements are reasonable, undue reliance should not be placed on these statements, which apply only as of these dates. APUC is not obligated to nor does it intend to update or revise any forward-looking statements, whether as a result of new information, future developments or otherwise, except as required by law.
The terms “adjusted net earnings” and “adjusted earnings before interest, taxes, depreciation and amortization” (“Adjusted EBITDA”) are used throughout this MD&A. The terms “adjusted net earnings” and Adjusted EBITDA are not recognized measures under Canadian generally accepted accounting principles (“GAAP”). There is no standardized measure of “adjusted net earnings” and Adjusted EBITDA, consequently APUC’s method of calculating these measures may differ from methods used by other companies and therefore may not be comparable to similar measures presented by other companies. A calculation and analysis of “adjusted net earnings” and Adjusted EBITDA can be found throughout this MD&A.
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Overview
APUC is a corporation incorporated under the Canada Business Corporations Act. APUC owns and operates a diversified portfolio of renewable energy and utility businesses through its subsidiary entities. APUC conducts its business primarily through two businesses:
Algonquin Power Co. (“APCo”) generates electrical energy through a diverse portfolio of clean, renewable power generation and thermal power generation facilities across North America. As at March 31, 2010, APCo owns 44 hydroelectric facilities operating in Ontario, Québec, Newfoundland, Alberta, New York State, New Hampshire, Vermont and New Jersey with a combined generating capacity of 175 MW. APCo also owns a 99 MW wind farm in Manitoba. The renewable energy facilities are generally facilities operating under long term power purchase agreements with major utilities and have an average remaining contract life of 16 years. APCo’s 14 thermal energy facilities operate under power purchase agreements (“PPAs”) and have an average remaining contract life of 7 years with a combined generating capacity of 396 MW.
Liberty Water Co. (“Liberty Water”) provides water and wastewater utility services through 19 water distribution and wastewater utility systems in the United States. Liberty Water provides regulated water distribution and wastewater facilities in Arizona, Illinois, Missouri and Texas. These utility operating companies are regulated investor-owned utilities subject to regulation, including rate regulation, by the public utility commissions of the states in which they operate.
Business Strategy and Recent Developments
APUC’s business strategy is to maximize long term shareholder value as a dividend paying, growth oriented corporation actively competing within its clearly defined business sectors. APUC is committed to delivering a total shareholder return comprised of a dividend augmented by capital appreciation arising through growth in earnings and dividends. Through an emphasis on sustainable, long view renewable power and utility investments, over a medium term planning horizon APUC strives to deliver annualized earnings growth exceeding 5% and is committed to growing its dividend supported by such earnings.
Independent Power:APCo develops and operates a diversified portfolio of electrical energy generation facilities. Within this business there are three distinct divisions: Renewable Energy, Thermal Energy and Development. The Renewable Energy division operates APCo’s hydroelectric and wind power facilities. The Thermal Energy division operates co-generation, energy from waste, steam production and other thermal facilities. The Development division seeks to deliver continuing growth to APCo through the development of APCo’s greenfield power generation projects, accretive acquisitions of electrical energy generation facilities as well as development of organic growth opportunities within APCo’s existing portfolio of renewable energy and thermal energy facilities. The renewable power and thermal energy generation business of APCo is managed with an emphasis on growth through the development of green-field projects and opportunities within APCo’s existing portfolio. This involves building on APCo’s expertise in the origination of greenfield renewable energy projects, building upon APCo’s existing portfolio of assets for further growth, and capitalizing on opportunities that may emerge in the current turbulence of the capital markets.
Regulated Water Utilities: In 2009, APUC branded all of its utilities under the Liberty Water brand. Liberty Water is committed to being the leading utility provider of safe, high quality and reliable water and wastewater services while providing stable and predictable earnings from its utility operations. Liberty Water delivers long term shareholder value by profitably owning and operating investor owned water and wastewater utilities providing safe, reliable transportation and delivery of water and wastewater treatment in its service areas. It is also focused on delivering continued growth in earnings by identifying opportunities which accretively expand its business portfolio.
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Dividend Policy:APUC pays quarterly cash dividends to shareholders of $0.06 per share or $0.24 per share per annum. This level of dividends allows for both an immediate return on investment for shareholders and retention of sufficient cash within APUC to fund growth opportunities, debt repayment and mitigate the impact of volatility in foreign exchange rates. APUC strives to achieve its results within a moderate risk profile consistent with top-quartile North American power, utility, and infrastructure operations. APUC declared a per share dividend for the first quarter of 2010 of $0.06, which was paid on April 15, 2010.
Red Lily Wind Project
On April 21, 2010, APUC announced that it has entered into agreements to provide development, construction, operation and supervision services related to the construction, commissioning and operation of a 26.4 megawatt wind energy facility (“Red Lily I”) in south-eastern Saskatchewan. The equity in Red Lily I (the “Partnership”) is owned by an independent investor. The facility will be financed by $17.5 million of senior and subordinated debt from APUC, senior debt from third party lenders of $31.0 million and an equity contribution from the independent investor of $19.0 million. APUC has been granted an option to subscribe for a 75% equity interest in the project in exchange for its subordinated debt commitment, exercisable five years following commissioning of the project. SeeDevelopment Division – Red Lily for more discussion of this project.
Tinker Hydro-electric Generating Asset Acquisition
On January 12, 2010, APCo completed the acquisition of 36.8 MW of electrical generating assets (the “Tinker Assets”) that was announced on November 10, 2009. The Tinker Assets are located in New Brunswick and Maine and were purchased after satisfying the conditions of the acquisition, including regulatory approval.
Through the purchase of shares and assets, APCo acquired three hydroelectric generating stations, the 34.5MW Tinker Hydro, a hydroelectric generating facility with sufficient reservoir storage capability to move significant amounts of energy from off-peak to on-peak generation located on the Aroostook River near the Town of Perth-Andover, New Brunswick, Caribou Hydro, a 0.9MW run-of-river hydroelectric generating facility located in Northern Maine and Squa Pan Hydro, a 1.4MW run-of-river hydroelectric generating facility located in Northern Maine.
APCo also acquired five thermal generating facilities with a rated capacity of 40MW in Northern Maine and New Brunswick utilized for installed reserve capacity, not continuous generation, New Brunswick Public Utilities Board regulated transmission lines and interconnections which allow direct and indirect access to multiple electricity markets (Northern Maine ISA, New Brunswick ISO, New England ISO).
In connection with the acquisition of the Tinker Assets, on February 4, 2010, APCo acquired a number of load supply and energy procurement contracts with an approximate value of $4.4 million in northern Maine and the Independent System Operator New England (“ISO NE”) market (“Energy Services Business”). As part of the acquisition of these supply contracts, APCo also acquired commitments to acquire energy at fixed rates over a 14 month period, corresponding with the terms of the supply contracts. The mark to market value of the forward purchase contracts at the date of acquisition was a net liability of $3.4 million. It is anticipated that the majority of the energy sold by the Energy Services Business will be supplied through generation from the Tinker Assets, based on historical long term average levels of hydroelectric energy generation of these facilities. The Energy Services Business involves standard offer contracts for the supply of energy to commercial and industrial customers in northern Maine, as well as energy purchase obligations with the ISO NE required to supplement self-generated energy.
The Energy Services Business is based on a series of short-term energy supply agreements which generally will expire within the next 14 months. These include energy sales to a town in New Brunswick, Standard Offer Service contracts with three local electric utilities in northern Maine, and a series of direct energy contracts with commercial buyers also in northern Maine.
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The hydroelectric and thermal generation assets offer capacity to support the energy services obligations in northern Maine. The acquisition improves hydrologic diversification through a new geographical area to the APCo generation portfolio and builds APCo’s Eastern Canadian generating presence.
2010 First quarter results from operations
Key Selected Quarterly Financial Information
Three months ended March 31 | ||||||
2010 | 2009 | |||||
Revenue | $ | 45,884 | $ | 52,165 | ||
Adjusted EBITDA2 | $ | 17,933 | $ | 21,114 | ||
Cash provided by Operating Activities | 9,151 | 13,703 | ||||
Net earnings | 3,451 | 4,243 | ||||
Adjusted net earnings2 | 2,994 | 7,919 | ||||
Dividend/distributions to Shareholders/Unitholders1 | 5,597 | 4,774 | ||||
Per share/trust unit | ||||||
Net earnings | $ | 0.04 | $ | 0.05 | ||
Adjusted net earnings2 | $ | 0.03 | $ | 0.10 | ||
Diluted net earnings | $ | 0.04 | $ | 0.05 | ||
Cash provided by Operating Activities | $ | 0.10 | $ | 0.17 | ||
Dividends/distributions to Shareholders/Unitholders | $ | 0.06 | $ | 0.06 | ||
Total Assets | 966,169 | 974,216 | ||||
Long Term Debt3 | 237,088 | 286,325 |
1 | Includes dividends/distributions to APUC shareholders/unitholders and Airsource units exchangeable into Algonquin trust units. |
2 | APUC uses Adjusted EBITDA to enhance assessment and understanding of the operating performance of APUC without the effects of depreciation and amortization expense which are derived from a number of non-operating factors, accounting methods and assumptions. Adjusted EBITDA is a non-GAAP measure - see applicable section later in this MD&A and the caution regarding non-GAAP measures on page 1. |
3 | Includes the revolving credit facility which matures on January 14, 2011 and has been recorded as a current liability on the consolidated balance sheet. |
For the three months ended March 31, 2010, APUC reported total revenue of $45.9 million as compared to $52.2 million during the same period in 2009, a decrease of $6.3 million or 12%. The decrease in APUC revenue in the three months ended March 31, 2010 was primarily the result of a decrease of $1.6 million due to reduced average energy rates and lower demand for steam at the Windsor Locks facility in the APCo Thermal Energy division, $2.6 million in lower waste disposal revenue at the Energy-From-Waste (“EFW”) facility as a result of the unplanned outage and a $2.4 million decrease due to lower average hydrology and wind resources in the Ontario and Manitoba regions in the APCo Renewable Energy division, as compared to the same period in 2009. These factors were partially offset by an increase of $1.7 million resulting from increased weighted average energy rates in the Ontario and Manitoba regions and revenue of $5.5 million generated by the Maritime region in the APCo Renewable Energy division, as compared to the same period in 2009.
In addition, APUC reported decreased revenue of $4.2 million from U.S. operations as a result of the stronger Canadian dollar as compared to the same period in 2009. A more detailed analysis of these factors is presented within the business unit analysis.
For the three months ended March 31, 2010, APUC experienced an average U.S. exchange rate of approximately $1.041 as compared to $1.245 in the same period in 2009. As such, any year over year variance in revenue or expenses, in local currency, at any of APUC’s U.S. entities are affected by a change in the average exchange rate, upon conversion to APUC’s reporting currency. Although a stronger Canadian dollar relative to the U.S. dollar has an impact on both revenue and expenses generated by its U.S. subsidiaries, APUC actively manages this risk through the increased use of placing U.S. dollar denominated debt on its U.S. assets (see Risk Management).
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Adjusted EBITDA in the three months ended March 31, 2010 totalled $17.9 million as compared to $21.1 million during the same period in 2009, a decrease of $3.2 million or 15%. The decrease in Adjusted EBITDA is in part due to lower earnings from operations primarily resulting from lower average hydrology and wind resources in the Renewable division and the impact of the outage at the EFW facility, partially offset by the acquisition of the Tinker Assets as compared to the same period in 2009. A more detailed analysis of these factors is presented within the reconciliation of Adjusted EBITDA to net earnings set out below (see Non-GAAP Performance Measures).
For the three months ended March 31, 2010, net earnings totalled $3.5 million as compared to $4.2 million during the same period in 2009. Net earnings per share totalled $0.04 for the three months ended March 31, 2010, as compared to net earnings per trust unit of $0.05 during the same period in 2009.
Net earnings for the three months ended March 31, 2010 decreased by $2.9 million related to lower recoveries of future income tax expense primarily due to the reasons discussed inCorporate Expenses – Income Taxes,$2.8 million due to lower earnings from operating facilities, $0.7 million due to increased interest expense and $0.3 million due to increased administration expense as compared to the same period in 2009. These items were partially offset by a decrease of $0.3 million due to lower amortization expense, $0.6 million due to non-cash gains resulting from the stronger Canadian dollar, $0.5 million resulting from reduced minority interest expense at the St. Leon facility primarily due to the lower wind resource experienced in the quarter as compared to the same period in 2009.
The decrease in net earnings as compared to 2009 was partially offset by a change in income of $6.1 million due to unrealized mark to market gains on derivative financial instruments partially offset by losses on derivative financial instruments contracts settled in the period, as a result of increased interest rates and the stronger Canadian dollar.
The change in unrealized mark to market losses on derivative financial instruments resulting from changes in foreign exchange rates relate to contract periods which extend to fiscal 2013. Unrealized mark to market losses on derivative financial instruments resulting from changes in interest rates relate to contract periods which extend to fiscal 2015. The following chart provides a summary of the period over period changes between realized and unrealized mark to market gains and losses of derivative financial instruments:
Three months ended March 31 | ||||||||||||
2010 | 2009 | Change | ||||||||||
Foreign Exchange Contracts: | ||||||||||||
Change in unrealized mark to market loss/(gain) on derivative financial instruments | $ | (1,083 | ) | $ | 2,317 | $ | (3,400 | ) | ||||
Realized loss/(gain) on derivative financial instruments | (132 | ) | 510 | $ | (642 | ) | ||||||
$ | (1,215 | ) | $ | 2,827 | $ | (4,042 | ) | |||||
Interest Rate Swap Contracts: | ||||||||||||
Change in unrealized mark to market gain on derivative financial instruments | $ | (1,288 | ) | $ | (398 | ) | $ | (890 | ) | |||
Realized loss on derivative financial instruments | 1,596 | 1,069 | $ | 527 | ||||||||
$ | 308 | $ | 671 | $ | (363 | ) | ||||||
Energy Forward Purchase Contracts: | ||||||||||||
Change in unrealized mark to market gain on derivative financial instruments | $ | (1,834 | ) | — | $ | (1,834 | ) | |||||
Realized loss on derivative financial instruments | 1,828 | — | $ | 1,828 | ||||||||
$ | (6 | ) | $ | — | $ | (6 | ) | |||||
Derivative Financial Instruments Total: | ||||||||||||
Change in unrealized mark to market loss/(gain) on derivative financial instruments | $ | (4,205 | ) | $ | 1,919 | $ | (6,124 | ) | ||||
Realized loss on derivative financial instruments | 3,292 | 1,579 | $ | 1,713 | ||||||||
Total loss/(gain) on derivative financial instruments | $ | (913 | ) | $ | 3,498 | $ | (4,411 | ) | ||||
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During the three months ended March 31, 2010, cash provided by operating activities totalled $9.2 million or $0.10 per share as compared to cash provided by operating activities of $13.7 million, or $0.17 per trust unit during the same period in 2009. Cash provided by operating activities exceeded dividends by 1.6 times during the quarter ended March 31, 2010 as compared to 2.9 times distributions during the same period in 2009. The change in cash provided by operating activities after changes in working capital in the three months ended March 31, 2010, is primarily due to increased realized losses from derivative instruments and decreased cash flow from operating facilities, as compared to the same period in 2009.
Outlook
APCo
APCo’s Renewable Energy division is expected to perform at or below long term average resource conditions in the second quarter of 2010. In particular, the low wind resource experienced by the St. Leon facility which negatively impacted operating profit by approximately $1.5 million in the first quarter is expected to return to long term averages in the second quarter. The wind resource at the St. Leon facility returned to 95% of long term averages in April 2010. With the commencement of construction of Red Lily I, APCo will receive construction supervision fees of approximately $0.8 million in the second quarter and a total of approximately $2.2 million during fiscal 2010.
APCo Thermal Energy division’s Energy-From-Waste (“EFW”) facility is expected to operate below APCo’s expectations during the second quarter of 2010 due to an unplanned outage in January 2010. The facility is currently undergoing a major capital upgrade totaling $8.0 million and expects to be operational in early July 2010. The original restart date has been delayed from the original expectations of spring 2010 due to delays in boiler tube delivery and installation. The productivity enhancements resulting from the capital upgrade and acceleration of other capital maintenance originally planned for the second and third quarters of 2010 should allow the facility in the second half of 2010 to make up some of the income expected to be lost due to the outage. APCo estimates the outage will negatively impact operating profit from EFW in the second quarter of 2010 by $0.9 million compared to the second quarter of 2009, partially offset by improved operating profits in the third and forth quarters, resulting in approximately $1.8 million in reduced operating profits over the entire year in 2010 compared to the previous year.
APCo Thermal Energy division’s Sanger facility is expected to operate at or above APCo’s expectations for the second quarter of 2010 in line with 2009 results. Hydro-mulch sales are expected to remain below expectations for the second quarter due to the economic conditions in California. APCo’s power development team will continue to pursue new opportunities for power generation projects in both Canada and the U.S. APCo will continue to focus on cost containment and productivity improvement measures that will maximize Sanger’s margins and EBITDA throughout 2010.
APCo Thermal Energy division’s Windsor Locks facility is expected to perform in line with 2009 results up to the expiration of the power purchase agreement with Connecticut Light & Power (“CL&P”) in mid April 2010 after which APCo will sell between 10MW and 40MW of electrical capacity to a local utility or provide ancillary services such as “spinning reserves” to the ISO-NE beginning June 1, 2010. On April 30, 2010 APCo successfully bid 26 MW into the forward capacity market at a monthly rate of $14 per MW month. The change to a forward capacity market operating model is expected to negatively impact operating profit in the second quarter by approximately U.S. $1.5 million compared to the previous year when operating under the historical PPA with CL&P. For the full 2010 fiscal year, APCo currently anticipates operating profit at the Windsor Locks facility to be approximately U.S. $4.5 million compared to a historical operating profit of approximately U.S. $8.0 million. For a more detailed description of the options and expected impact see Development Division - Windsor Locks.
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Liberty Water
Liberty Water has ongoing rate cases at a number of its utilities and will continue to process these rate cases throughout 2010. These rate cases are discussed in further detail within this MD&A (see Liberty Water: Outlook). An exact determination of increased revenues from all rate case applications is not possible at this time as the timing of conclusion to the rate cases and the final decision on rate increases are determined by the regulator. As a result of delays in the progress of rate cases through the regulatory processes, Liberty Water anticipates that approximately $7 million of additional revenue from rate cases will be achieved in 2010 and the full annualized increase in revenues determined through the rate case processes is expected to be achieved in 2011.
Liberty Water has agreed to settlements with intervening Parties in its rate cases at its Tall Timbers and Silver Leaf Texas utilities. These settlements are subject to final approval by the Office of the Executive Director of the Texas Commission on Environmental Quality (“TCEQ”) and the Office of the Public Interest Counsel (“OPIC”). The settlements allow for Liberty Water’s requested combined revenue requirement increase of $1.4 million to be permanently implemented in the second quarter of 2010. The regulatory reviews of the rates and tariffs for the remainder of the facilities are expected to conclude in the second quarter of 2010, with the new rates and tariffs implemented and/or going into effect in mid 2010, depending on the state in which the relevant facility operates.
The business unit will also continue to consider accretive water and wastewater utility acquisition opportunities, as well as acquisitions in other regulated utilities, such as electricity distribution. On March 17, 2010 Liberty Water announced it had acquired a water and wastewater utility near Galveston Texas which is expected to generate operating profit of approximately $0.3 million in the balance of 2010.
With respect to growth, Liberty Water is expecting limited organic expansion due to the slowdown in the U.S. housing market.
Liberty Electric
In 2009, APUC announced its plan to establish a third distinct business subsidiary focused on the provision of local regulated electrical generation and distribution utilities within a new business subsidiary to be called Liberty Electric. In this regard APUC announced plans to co-acquire an electrical generation and regulated distribution utility through a strategic partnership with Emera Inc. (“Emera”). The utility is the California-based electricity distribution and related generation assets of NV Energy, Inc. (NYSE: NVE).
The acquisition is proceeding through the regulatory approval process before the California Public Utilities Commission (“CPUC”). Based on the current regulatory procedural schedule the closing of the transaction is expected to occur in the fourth quarter of 2010.
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APCo: Renewable Energy
2010 Long Term Average Resource | Three months ended March 31 | |||||||||
2010 | 2009 | |||||||||
Performance (MW-hrs sold) | ||||||||||
Quebec Region | 56,300 | 64,650 | 65,498 | |||||||
Ontario Region | 37,950 | 29,925 | 38,550 | |||||||
Manitoba Region | 105,000 | 79,175 | 109,960 | |||||||
New England Region | 20,350 | 18,800 | 22,074 | |||||||
New York Region | 27,350 | 23,925 | 23,161 | |||||||
Western Region | 10,200 | 9,400 | 10,348 | |||||||
Maritime Region | 28,000 | 31,400 | 508 | |||||||
Total | 285,150 | 257,275 | 270,099 | |||||||
Revenue | ||||||||||
Energy sales | $ | 22,219 | $ | 18,964 | ||||||
Less: | ||||||||||
Cost of Sales – Energy* | (2,089 | ) | — | |||||||
Net Energy Sales | $ | 20,130 | $ | 18,964 | ||||||
Expenses | ||||||||||
Operating expenses | (6,036 | ) | (5,312 | ) | ||||||
Other income | 138 | 244 | ||||||||
Division operating profit (including other income) | $ | 14,232 | $ | 13,896 |
* | Cost of Sales – Energy consists of energy purchases by the Energy Services Business, where this energy is immediately sold to customers pursuant to fixed rate energy contracts. |
On January 12, 2010, APCo completed the acquisition of three hydroelectric generating stations located in New Brunswick and Maine with installed capacity of 36.8MW, which include, most notably, the 34.5MW Tinker Hydroelectric station located on the Aroostook River near the Town of Perth-Andover, New Brunswick. The energy produced by these facilities is shown as the Maritime region.
In connection with the Tinker acquisition which closed January 12, 2010, on February 4, 2010, APCo acquired the Energy Services Business which provides energy to commercial and industrial customers in the northern Maine and New Brunswick markets. The Energy Services Business anticipates that, based on the expected load forecast for its existing contracts, it will provide approximately 150,000 MW-hrs of energy to its customers at an average rate of $80/MW-hr on an annualized basis. The Energy Services Business operates on a ‘balanced book’ basis. Essentially, the Energy Services Business purchases sufficient energy on the ISO NE market to meet its actual customer load during those periods when the energy generated by the Tinker Assets is insufficient to meet the demand of these customers and subsequently sells the surplus energy generated by the Tinker Assets on the ISO NE market when the production exceeds the customer demand in the period. Based on historical long term average levels of hydroelectric energy generation, the Tinker Assets are anticipated to provide greater than 80% of the energy required by the Energy Services Business to service its customers which provides a natural hedge on supply costs of the Energy Services Business.
In addition to the energy generation provided by the Tinker Assets, the Energy Services Business anticipates buying additional energy on the open market in order to service its customer demand. APCo manages the risk associated with this business through internally generated energy from the Tinker Assets, as well as, through the purchase of fixed volume/prices from the ISO NE market. In addition, APCo negotiates appropriate consumption volumes and pricing indexes with large retail and wholesale consumers in northern Maine to mitigate risk associated with volatility of consumption by the consumer.
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As APCo’s hydroelectric generating facilities in the New York and New England regions primarily sell their output at market rates, the average revenue earned per MW-hr sold can vary significantly from the same period in the prior year. APCo’s hydroelectric generating facilities in the Maritime region primarily sell their output to the Energy Services Business which sells this energy at fixed price contracts to local electric utilities and commercial buyers in Northern Maine. APCo’s facilities in the other regions are subject to varying rates, by facility, as set out in each facility’s individual power purchase agreement (“PPA”). As such, while most of APCo’s PPAs include annual rate increases, a change to the weighted average production levels resulting in higher average production from facilities which earn lower energy rates can result in a lower weighted average energy rate earned by the division, as compared to the same period in the prior year.
2010 First Quarter Operating Results
For the quarter ended March 31, 2010 the Renewable Energy division produced 257,275 MW-hrs of electricity, as compared to 270,099 MW-hrs produced in the same period in 2009, a decrease of 4.8%. The level of production in 2010 represents sufficient renewable energy to supply the equivalent of 57,200 homes on an annualized basis with renewable power. Using new standards of thermal generation, as a result of renewable energy production, the equivalent of 141,500 tons of CO2 gas was prevented from entering the atmosphere in the first quarter of 2010.
During the quarter ended March 31, 2010, the division generated electricity equal to 90% of long term projected average resources (wind and hydrology) as compared to 108% during the same period in 2009. During the quarter, the Quebec region experienced resources significantly higher than long term averages, at approximately 15% above long term averages while the Maritime region experienced resources significantly higher than long term averages, at approximately 12% above long term averages. Several regions experienced resources at or below long term averages including the New York region, which was 12% below long term averages and the Western and New England regions which were 8% below long term averages. Two regions experienced results significantly below long term averages including the Ontario region, which was 21% below long term average resources and the Manitoba region which was 25% below long term averages. The lower wind resource in the Manitoba region is similar to lower wind resources being experienced at other wind farms in North America in the first quarter of 2010.
For the quarter ended March 31, 2010, revenue from energy sales in the Renewable Energy division totalled $22.2 million, as compared to $19.0 million during the same period in 2009, an increase of $3.3 million. As the purchase of energy by the Energy Services Business is a significant revenue driver and component of variable operating expenses, the division compares ‘net energy sales’ (energy sales revenue less energy purchases) as a more appropriate measure of the division’s sales results. For the quarter ended March 31, 2010, net revenue from energy sales in the Renewable Energy division totalled $20.1 million, as compared to $19.0 million during the same period in 2009, an increase of $1.1 million.
Revenue from APCo’s New England and New York region facilities decreased $0.1 million due to a decrease in weighted average energy rates of approximately 2.7% and $0.1 million due to decreased average hydrology, as compared to the same period in 2009. Revenue from the Manitoba region increased $0.5 million due to an increase in weighted average energy rates of approximately 12.7%, offset by a decrease of $1.6 million due to a weaker wind resource, as compared to the same period in 2009. The Manitoba Region PPA requires the facility to generate a minimum amount of dependable energy during the contract year ending April 30. Energy generated above the dependable amount earns revenue at lower, non-dependable rates. As a result of the lower production during the contract year ending April 30, 2010, the facility earned revenue primarily at the dependable rates as compared to the same period in 2009 where a greater proportion of revenue was earned at the non-dependable rates. Revenue generated by the Ontario, Quebec and Western regions increased by $1.2 million due to an increase in weighted average energy rates, primarily the result of increased rates at the Long Sault facility in the Ontario region, as compared to the same period in 2009. The increases in revenue at APCo’s Ontario, Quebec and Western regions were partially offset by a decrease of $0.8 million due to lower energy production, primarily the result of lower production at the Long Sault facility in the Ontario region, as compared to the same period in 2009. The Maritime region, in conjunction with the Energy Services Business, generated $5.5 million in revenue, before energy purchases. The division reported decreased revenue of $0.2 million from U.S. operations as a result of the stronger Canadian dollar as compared to the same period in 2009.
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For the quarter ended March 31, 2010, energy purchase costs by the Energy Services Business totalled $2.1 million. During the quarter, the Energy Services Business purchased approximately 38,600 MW-hrs of energy at market and fixed rates averaging $52 per MW-hr. The energy purchases represent the load requirement of the Energy Services Business customers in excess of the energy production by the Tinker Assets. The division reported increased energy costs of $0.1 million as a result of the stronger Canadian dollar.
For the quarter ended March 31, 2010, operating expenses excluding energy purchases totalled $6.0 million, as compared to $5.3 million during the same period in 2009, an increase of $0.7 million. Operating expenses were impacted by $0.4 million of increased expenses at the St. Leon facility, primarily resulting from scheduled payments under the extended warranty and operation and maintenance agreements with Vestas, increased operational and administrative expenses of $0.1 million, $0.7 million related to operating costs associated with the Tinker Assets and the Energy Services Business, $0.1 million resulting from increased repair and maintenance expenses related to U.S. facilities, as compared to the same period in 2009. Operating expenses include costs of $0.3 million associated with the pursuit of various growth and development activities, as compared to $0.5 million in the same period in 2009. The division reported decreased expenses of $0.1 million from U.S. operations as a result of the stronger Canadian dollar as compared to the same period in 2009.
For the quarter ended March 31, 2010, Renewable Energy’s operating profit totalled $14.2 million, as compared to $13.9 million during the same period of 2009, representing an increase of 2.4%. For the quarter ended March 31, 2010, Renewable Energy’s operating profit did not meet APCo’s expectations primarily due to a lower than expected wind resource in the Manitoba region.
Divisional Outlook – Renewable Energy
The APCo Renewable Energy division is expected to perform at or below long term average resource conditions in the second quarter of 2010. In particular, the low wind resource experienced by the St. Leon facility which negatively impacted operating profit by approximately $1.5 million in the first quarter is expected to return to long term averages in the second quarter. The wind resource at the St. Leon facility returned to 95% of long term averages in April 2010.
As a result of certain legislation passed in Quebec (Bill C93), APCo’s Renewable Energy division is required to undertake technical assessments of eleven of the twelve hydroelectric facility dams owned or leased within the Province of Quebec. In the second quarter of 2010 APCo expects to complete the required assessments necessary to determine the work required and estimate capital cost of compliance with the legislation. APCo is required to submit plans for undertaking any remedial measures that are identified to comply with the legislation. As a result of nine completed and two partially completed assessments, APCo has estimated capital expenditures of approximately $17.5 million related to compliance with the legislation. The timing of when the actual capital costs need to be made is determined as part of the technical assessments.
APCo anticipates that these expenditures will be invested over the next five years approximately as follows:
Total | 2010 | 2011 | 2012 | 2013 | 2014 | |||||||
Estimated Bill C-93 Capital Expenditures | 17,500 | 500 | 6,000 | 5,700 | 2,800 | 2,500 |
The majority of these capital costs are associated with the Donnacona, St. Alban and Mont-Laurier facilities. During the quarter, APCo revised its assumptions related to the anticipated timing of the Donnacona capital expenditures and currently anticipates the majority of the costs associated with the facility will be incurred in fiscal 2011 and 2012. APCo does not anticipate any significant impact on power generation or associated revenue while the dam safety work is ongoing. APCo continues to explore several alternatives to mitigate the capital costs of the modifications, including cost sharing with other stakeholders and revenue enhancements which can be achieved through the modifications.
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APCo: Thermal Energy Division
Three months ended March 31 | ||||||||
2010 | 2009 | |||||||
Performance(MW-hrs sold) | 139,200 | 142,396 | ||||||
Performance(tonnes of waste processed) | 6,550 | 41,283 | ||||||
Revenue | ||||||||
Energy sales | $ | 14,299 | $ | 18,538 | ||||
Less: | ||||||||
Cost of Sales – Fuel * | (6,245 | ) | (9,869 | ) | ||||
Net Energy Sales Revenue | $ | 8,054 | $ | 8,669 | ||||
Waste disposal sales | 917 | 3,683 | ||||||
Other revenue | 203 | 1,308 | ||||||
Total net revenue | $ | 9,174 | $ | 13,660 | ||||
Expenses | ||||||||
Operating expenses * | (6,261 | ) | (8,275 | ) | ||||
Interest and other income | 139 | 132 | ||||||
Division operating profit | ||||||||
(including interest and dividend income) | $ | 3,052 | $ | 5,517 |
* | Cost of Sales – Fuel consists of natural gas and fuel costs at the Sanger and Windsor Locks facilities, where changes in these costs are passed to the customer in the energy price. |
2010 First Quarter Operating Results
In the first quarter of 2010, the EFW facility processed 6,550 tonnes of municipal solid waste as compared to 41,283 tonnes processed in the same period of 2009, a decrease of 84.1%. The significantly reduced throughput was a result of the unplanned outage experienced in January 2010 which resulted in the facility being temporarily shut down. The status of this outage is discussed in further detail inDivisional Outlook – Thermal Energy, below. This level of production resulted in the diversion of approximately 3,000 tonnes of waste from landfill sites in the first quarter of 2010.
During the quarter ended March 31, 2010, the business unit produced 139,200 MW-hrs of energy as compared to 142,396 MW-hrs of energy in the comparable period of 2009. During the quarter ended March 31, 2010, the business unit’s performance decreased by 1,000 MW-hrs at the Windsor Locks facility, 2,200 MW-hrs at the LFG facilities and 2,000 MW-hrs from EFW’s steam turbine as compared to the same period in 2009. The decrease in electrical generation at the EFW facility was the result of the unplanned outage which occurred in January 2010. During the quarter ended March 31, 2010, APCo ceased generating energy at the LFG facilities and has initiated a process to close these facilities. The LFG facilities were written down to their current net realizable value in the fourth quarter of 2009. The decreases in energy generation were partially offset by an increase of 1,700 MW-hrs at the Valley Power facility.
For the quarter ended March 31, 2010, revenue in the Thermal Energy division totalled $15.4 million, as compared to $23.5 million during the same period in 2009, a decrease of $8.1 million. As natural gas expense is a significant revenue driver and component of operating expenses, the division compares ‘net energy sales revenue’ (energy sales revenue less natural gas expense) as a more appropriate measure of the division’s results. For the quarter ended March 31, 2010, net energy sales revenue at the Thermal Energy division totalled $8.1 million, as compared to $8.7 million during the same period in 2009, a decrease of $0.6 million. The decrease in revenue from energy sales was primarily due to a decrease of $1.6 million at the Windsor Locks facility as a result of decreased energy rates, in part due to lower natural gas prices and $0.1 million as a result of decreased
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demand for steam production, partially offset by $0.2 million at the Sanger facility as a result of increased energy rates, in part due to higher natural gas prices as compared to the same period in 2009. The offsetting reduction in natural gas expense at the Sanger and Windsor Locks facilities is discussed in detail below. The division reported decreased revenue of $2.7 million from operations as a result of the stronger Canadian dollar, as compared to the same period of 2009.
Revenue from waste disposal sales for the quarter ended March 31, 2010 totalled $0.9 million, as compared to $3.7 million during the same period in 2009. The decrease in throughput at the EFW facility was the result of the unplanned outage in January 2010.
Other revenue for the quarter ended March 31, 2010 totalled $0.2 million, as compared to $1.3 million during the same period in 2009. The decrease in other revenue was primarily due to a decrease of $0.4 million at the hydro-mulch facility due to reduced customer demand in the quarter. In the comparable period in 2009, other revenue included $0.4 million from APCo’s MGT facility which was not operational in the current period.
For the quarter ended March 31, 2010, fuel costs at Sanger and Windsor Locks totalled $6.2 million, as compared to $9.9 million during the same period in 2009, a decrease of $3.6 million. Natural gas expense at the Windsor Locks facility decreased $2.0 million (31%), primarily the result of a 31% decrease in the average price for natural gas as compared to the same period in 2009. This was partially offset by an increase in the natural gas expense at Sanger of $0.1 million (8%), primarily the result of a 9% increase in the average price for natural gas as compared to the same period in 2009. The division reported decreased fuel costs of $1.7 million as a result of the stronger Canadian dollar as compared to the same period in 2009.
For the quarter ended March 31, 2010, operating expenses, excluding fuel costs at Windsor Locks and Sanger, totalled $6.3 million, as compared to $8.3 million during the same period in 2009, a decrease of $2.0 million. The decrease in operating expenses for the quarter was primarily due to reduced operating costs of $1.7 million at the EFW facility resulting from the outage at the facility, reduced material costs of $0.1 million at the hydro-mulch facility resulting from lower production, and $0.3 million of reduced operating costs at the LFG facilities partially offset by increased natural gas expense of $0.5 million at BCI as a result of decreased steam production at EFW and increased steam production from BCI’s auxiliary boiler as compared to the same period in 2009. The division reported decreased operating expenses of $0.6 million from U.S. operations as a result of the stronger Canadian dollar as compared to the same period in 2009.
For the quarter ended March 31, 2010, the Thermal Energy division’s operating profit totalled $3.1 million, as compared to $5.5 million during the same period in 2009, representing a decrease of $2.5 million or 45%. Operating profit in the Thermal Energy division did not meet overall expectations for the quarter ended March 31, 2010, primarily due to the unplanned outage at the EFW facility and lower demand for hydro-mulch from the Division’s co-generation assets resulting from the current economic slow down in the U.S.
Divisional Outlook – Thermal Energy
APCo Thermal Energy division’s EFW facility is expected to operate below APCo’s expectations during the second quarter of 2010 due to an unplanned outage in January 2010 from a failure with boiler and economizer tubes, some of which were scheduled for replacement as part of the current year capital expenditure plan. The facility is currently undergoing a major capital upgrade totaling $8.0 million and expects to be operational in early July 2010. The original restart date has been delayed from the original expectations of spring 2010 due to delays in boiler tube delivery and installation. The productivity enhancements resulting from the capital upgrade and acceleration of other capital maintenance originally planned for the second and third quarters of 2010 should allow the facility in the second half of 2010 to make up some of the income expected to be lost due to the outage. APCo estimates the outage will negatively impact operating profit from EFW in the second quarter of 2010 by $0.9 million compared to the second quarter of 2009, partially offset by improved operating profits in the third and forth quarters, resulting in approximately $1.8 million in reduced operating profit over the entire year in 2010 compared to the previous year.
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APCo Thermal Energy division’s Sanger facility is expected to operate at or above APCo’s expectations for the second quarter of 2010 in line with 2009 results. Hydro-mulch sales are expected to remain below expectations for the second quarter due to the economic conditions in the U.S. APCo will continue to focus on cost containment and productivity improvement measures that will maximize Sanger’s margins and EBITDA throughout 2010.
APCo Thermal Energy division’s Windsor Locks facility is expected to perform in line with 2009 results up to the expiration of the power purchase agreement with CL&P in mid April 2010 after which APCo will sell between 10MW and 40MW of electrical capacity to a local utility or provide ancillary services such as “spinning reserves” to the ISO-NE beginning June 1, 2010. From mid April to May 31, 2010, Windsor Locks will be selling between 10 MW and 40 MW of power into the grid based upon locational hourly pricing forecasts. The main power and steam contract to the local mill remains intact. The change to a forward capacity reserve market operating model is expected to negatively impact operating profit in the second quarter by approximately U.S. $1.5 million compared to the previous year. For the full 2010 fiscal year, APCo currently anticipates operating profit at the Windsor Locks facility to be approximately U.S. $4.5 million compared to a historical operating profit of approximately U.S. $8.0 million. For a more detailed description of the options and expected impact seeDevelopment Division - Windsor Locks.
APCo: Development Division
The Development division works to identify, develop and construct new, renewable and efficient energy generating facilities, as well as to identify, develop and construct other accretive projects that maximize the potential of APCo’s existing facilities. Development is focused on projects within North America with a commitment to working proactively with all stakeholders, including local communities. The Development division is led by five full time employees who have access to, and support from, all of APCo’s available resources to assist it in the development of projects. Typically, the division draws upon the support of the finance, engineering, technical services, and environmental and regulatory compliance groups. It also utilizes existing industry relationships to assist in the identification, evaluation, development and construction of projects, and retains expertise, as required, from the financial, legal, engineering, technical, and construction sectors.
The Development division may also create opportunities through the acquisition of operating assets with accretive characteristics and prospective projects that are at various stages of development. The Development division believes that the prevailing economic climate has also created opportunities for APCo to acquire third party development projects on terms that require the experience and financial resources that APCo has at its disposal. The strategy is to focus on high quality renewable and high efficiency thermal energy generation projects that benefit from low operating costs using proven technology that can generate sustainable and increasing operating profit in order to achieve a high return on invested capital.
APCo’s approach to project development is to maximize the utilization of internal resources while minimizing external costs. This allows development projects to evolve to the point where most major elements and uncertainties of a project are quantified and resolved prior to the commencement of project construction. Major elements and uncertainties of a project include the signing of a power purchase agreement, obtaining the required financing commitments to develop the project, completion of environmental permitting, and fixing the cost of the major capital components of the project. It is not until all major aspects of a project are secured that APCo will begin construction.
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Current Development Projects
Red Lily
On April 21, 2010, APUC announced that it has entered into agreements to provide development, construction, operation and supervision services related to the construction, commissioning and operation of a 26.4 megawatt wind energy facility (“Red Lily I”) in south-eastern Saskatchewan. The equity in Red Lily I is owned by an independent investor. The facility will be financed by $17.5 million of senior and subordinated debt from APUC, senior debt from third party lenders of $31.0 million and an equity contribution from the independent investor of $19.0 million. On April 21, 2010, APCo invested $6.6 million of subordinated debt, bearing an interest rate of 12.5%, in the Partnership. With the commencement of construction of Red Lily I, APCo will receive construction supervision fees of approximately $0.8 million in the second quarter and a total of approximately $2.2 million during fiscal 2010.
APUC has been granted an option to subscribe for a 75% equity interest in the project in exchange for its subordinated debt commitment of up to $19.5 million, exercisable five years following commissioning of the project.
In addition APCo has secured additional property to facilitate an additional 106 MW expansion (“Phase II”). The viability of the expanded project will be conditional upon satisfactory actual operating results from Red Lily I. During the quarter APCo responded to the request for quotations issued by SaskPower by submitting requested information pertaining to Phase II.
Successful development of wind projects are subject to significant risks and uncertainties including the ability to obtain financing on acceptable terms within deadlines imposed by the utility, reaching agreement with any other external parties involved in the project, currency fluctuations affecting the cost of major capital components such as wind turbines, price escalation for construction labour and other construction inputs and construction risk that the project is built without mechanical defects and is completed on time and within budget estimates.
Windsor Locks
The Windsor Locks facility is a 54MW natural gas power generating station located in Windsor Locks, Connecticut. The facility was acquired in 2003 and currently has an outstanding net book value to APCo of approximately US$16.8 million. The facility has two key energy agreements. The first agreement is the PPA with CL&P which expired in April 2010. The second agreement is the Energy Services Agreement (“ESA”) with Ahlstrom Windsor Locks, LLC (“Ahlstrom”), a leading paper and non woven materials manufacturer, which, if not further extended by mutual agreement, will continue until 2017. The expiration of the CL&P PPA will impact operations beyond April 2010.
Subsequent to March 31, 2010 and the expiration of the CL&P PPA, APCo continued serving the steam and power requirements of Ahlstrom pursuant to the existing ESA which continues until 2017. APCo also bid the remaining available capacity of approximately 40 MW into the thirty minute operating reserve (“TMOR”) market. APCo has entered into an agreement with a subsidiary of Emera to manage the off-take sales from this facility into the ISO-NE market.
APCo is continuing the preliminary engineering and environmental permitting work for the installation of a new combustion gas turbine more appropriately sized to meet the electrical and steam requirements of Ahlstrom. APCo believes it is eligible to receive a one-time non-recurring grant from the State of Connecticut equivalent to US $450/KW to a maximum of US $6.6 million to offset the cost of such re-powering. In addition to installing the new gas turbine, APCo would expect to continue to operate and maintain the existing equipment. Any investment in new capital for this site will be based on an assessment of the incremental earnings against such additional investment.
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The Development division currently anticipates operating profit at the Windsor Locks facility for 2010 to be approximately U.S. $4.5 million compared to a historical operating profit of approximately U.S. $8.0 million. This operating profit estimate assumes participation in the summer 2010 and the winter 2010/2011 forward reserve auctions. TMOR has cleared at US $14 per MW month for the last 7 forward capacity reserve procurement periods (two periods annually). On April 30, 2010, APCo was advised that it received an obligation for the summer 2010 forward capacity reserve TMOR of 26 MW at a price of US $14 per MW month.
During 2010, it is expected that APCo will continue to earn revenue from steam and electrical sales to Ahlstrom, steam and electrical capacity payments made by Ahlstrom, as well as energy sales to ISO-NE, capacity payments made by ISO-NE and TMOR payments made by ISO-NE. Under this operating protocol APCo will need to acquire 0.8 million MMBTU to 1.0 million MMBTU of natural gas annually in addition to the natural gas purchases reimbursed by Ahlstrom.
Other
APCo has completed preliminary engineering and a financial feasibility analysis on a 12 MW combined cycle high efficiency thermal energy generation project located in Ontario. APCo believes this project is an excellent fit for the Minister of Energy and Infrastructure’s Directive to procure electricity from combined heat and power projects.
Future Development Projects – Greenfield Projects
There are a number of future greenfield development projects which are being actively pursued by the Development division. These projects encompass several new wind energy projects, hydroelectric projects at different stages of investigation, and thermal energy generation projects. The projects being examined are located both in Canada and the United States.
In addition to the second phase of the Red Lily project, APCo is currently collecting wind data on three other sites in Saskatchewan and responded to the Provinces’ Request for Qualifications to procure up to 175MW of wind power from one or more independent power producers during the first quarter of 2010.
In 2008, APCo made a strategic decision to maintain land option agreements for two wind projects in Quebec in anticipation of future provincial tenders. In May 2009, Hydro Quebec released details in relation to a tender request for wind projects of a 25 MW maximum size. In addition, APCo has developed a relationship with two development co-operatives comprised of landowners and other small investors for the potential development of a third and fourth project in response to the expected call for tender. Algonquin will assess the economics of these projects individually and will bid into the May 19, 2010 RFP accordingly.
Discussions with the Ontario Power Authority indicate that energy procurement initiatives will be positively influenced by the Green Energy Act (“GEA”) which received Royal Assent on May 14, 2009. The GEA is intended to provide the catalyst for the development of 50,000 new green economy jobs and is viewed by APCo as positive for the development of renewable energy in Ontario. The Development division is maintaining relationships with potential partners for the development of a number of projects that could qualify under anticipated procurement initiatives undertaken by the Ontario Power Authority in accordance with the GEA.
APCo submitted applications for 42 MW of on-shore wind energy projects in eastern Ontario under the GEA’s Feed-in Tariff program (“FIT”). The on-shore wind price set by the FIT program is $0.135 per kWH. On April 8, 2009 Algonquin received confirmation from the Ontario Power Authority that 42 MW of projects submitted under the FIT program will proceed to the economic connection test scheduled for summer 2010.
APCo has the rights, including land options, meteorological towers and historical wind data related to a potential 80 MW Canadian wind project in Ontario. In the event the project is developed, it is currently estimated to require an investment of up to $250 million and is expected to require 2 to 3 years to complete.
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APCo has applied to become applicant of record for three crown land sites in Ontario under the Ministry of Natural Resources wind power site release programme.
Each project being contemplated is subject to a significant level of due diligence and financial modeling to ensure it satisfies return and diversification objectives established for the Development division. Accordingly, the likelihood of proceeding with some or all of these projects depends on the outcome of due diligence, material contract negotiations, the structure of future calls for tender, and request for proposal programs. To maximize APCo’s opportunities for development, new renewable and high efficiency thermal energy generating facilities are being pursued utilizing a variety of technologies and in diverse geographic locations.
Future Development Projects – Existing Facilities
The following sets out a summary of potential development projects at existing facilities which are being examined by the Development division.
Renewable Energy
APCo is exploring multiple options related to the St. Leon facility including pursuing a future adjacent project and/or pursuing an increase in the installed capacity of the existing facility. The projects being reviewed have a potential generation capacity of over 85 MW. In the event these projects are developed, it is currently estimated to require an investment of approximately $250 million.
Thermal Energy
The EFW facility in the Thermal Energy division of APCo is designed to incinerate over 500 tonnes per day of municipal solid waste from the Region of Peel to produce steam that is used in the production of electricity and to supply the internal steam load for a nearby recycled paper board manufacturing mill. APCo established BCI to operate the required facilities to supply steam to the nearby paper board customer and pursue additional steam load customers.
The Development division is currently reviewing several proposals at the EFW facility to expand its power generation and waste processing throughput capacity. Throughput capacity could be expanded by between 40,000 and 100,000 tonnes annually depending on the proposal that is selected. If the expansion is pursued, depending on the alternative chosen, an investment of between $60 million to $250 million would be required. APCo is currently evaluating the feasibility of an expanded facility including associated capital and operating costs and financing terms. APCo is also engaged in discussions with the Region of Peel to establish a new long term contract for a reliable supply of municipal solid waste.
Divisional Outlook - Development
APCo believes that future opportunities for power generation projects will continue to arise given that many jurisdictions, both in Canada and the United States, continue to increase targets for renewable and other clean power generation projects. In the past year the Ontario government passed the Green Energy Act. Accordingly the Ontario Power Authority has issued standard pricing for electricity from renewable sources under a Feed-in Tariff. Included within this legislation is the requirement for Ontario Power Authority to purchase power generated from green energy projects, and an obligation for all utilities to grant priority grid access to such projects. The intention of the legislation is to make development of renewable energy projects significantly easier than the prior process of formal bids in response to requests for proposals from the responsible power authority.
Other jurisdictions have passed similar legislation. British Columbia has announced the Clean Energy Act and Nova Scotia is pursuing the 2010 Renewable Electricity Plan. Both of these proposed pieces of legislation have set aggressive targets for the development of new, renewable power production. They also introduce the concept of fixed pricing based on a feed-in-tariff for some categories of new renewable power projects. The combination of increased renewable production targets and appropriate fixed pricing will present investment opportunities for APCo to consider in the future.
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LIBERTY WATER
Three months ended March 31 | Three months ended March 31 | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
US $ | US $ | Can $ | Can $ | |||||||||||||
Number of | ||||||||||||||||
Wastewater connections | 34,605 | 34,306 | ||||||||||||||
Wastewater treated (millions of gallons) | 525 | 500 | ||||||||||||||
Water distribution connections | 37,170 | 36,534 | ||||||||||||||
Water sold (millions of gallons) | 1,000 | 1,050 | ||||||||||||||
Assets for regulatory purposes (U.S. $) | 152,658 | 151,496 | ||||||||||||||
Revenue | ||||||||||||||||
Wastewater treatment | $ | 4,642 | $ | 4,442 | $ | 4,863 | $ | 5,532 | ||||||||
Water distribution | 3,075 | 3,157 | 3,221 | 3,932 | ||||||||||||
Other Revenue | 156 | 170 | 162 | 208 | ||||||||||||
$ | 7,873 | $ | 7,769 | $ | 8,246 | $ | 9,672 | |||||||||
Expenses | ||||||||||||||||
Operating expenses | (5,184 | ) | (4,852 | ) | (5,428 | ) | (6,106 | ) | ||||||||
Other income | 10 | — | 11 | — | ||||||||||||
Business Unit operating profit (including other income) | $ | 2,699 | $ | 2,917 | $ | 2,829 | $ | 3,566 |
Liberty Water is committed to being the leading utility provider of safe, high quality and reliable water and wastewater services while providing stable and predictable earnings from its utility operations. Liberty Water has presented the division’s results in both the reporting currency and its functional currency. Liberty Water believes that as the division’s operations are entirely in the U.S., it is useful to show the results without the impact of foreign exchange.
Liberty Water reports total connections, inclusive of vacant connections rather than customers. Liberty Water had 34,605 wastewater connections as at March 31, 2010, as compared to 34,306 as at March 31, 2009, an increase of 299 in the period or 0.9%. Liberty Water had 37,170 water distribution connections as at March 31, 2010, as compared to 36,534 as at March 31, 2010, representing an increase of 636 in the period of March 31, 2010 or 1.7%. Total connections include approximately 1,796 vacant wastewater connections and 1,412 vacant water distributions connections. Liberty Water’s marginal change in water distribution and wastewater treatment customer base during the period continues to primarily relate to the inclusion of 144 water distribution and 144 wastewater treatment connections resulting from the acquisition of a small utility in Texas during the first quarter of 2010 and limited organic growth at Liberty Water’s facilities resulting from the slow recovery in U.S. new residential home sales in areas served by the division.
Liberty Water has investments in regulatory assets of U.S. $152.7 million across four States as at March 31, 2010, as compared to U.S. $151.5 million as at March 31, 2009 and has active proceedings in Texas and Arizona to allow it to earn its full regulatory return on its investment in regulatory assets.
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2010 First Quarter Operating Results
During the quarter ended March 31, 2010, Liberty Water provided approximately 1.0 billion U.S. gallons of water to its customers, treated approximately 525 million U.S. gallons of wastewater and sold approximately 30 million U.S. gallons of treated effluent.
For the quarter ended March 31, 2010, Liberty Water’s revenue totalled U.S. $7.9 million as compared to U.S. $7.8 million during the same period in 2009, an increase of U.S. $0.1 million.
Revenue from water distribution totalled U.S. $3.1 million, as compared to U.S. $3.2 million during the same period in 2009, a decrease of U.S. $0.1 million. The first quarter water distribution revenue was impacted by decreased revenue of U.S. $0.2 million primarily due to lower commercial water sales at the Litchfield Park facility (“LPSCo”) and lower customer demand at six water distribution facilities, partially offset by an increase of $0.1 million at the four Texas Silverleaf facilities primarily due to the implementation of interim rate increases as compared to the same period in 2009.
Revenue from wastewater treatment totalled U.S. $4.6 million, as compared to U.S. $4.4 million during the same period in 2009, an increase of U.S. $0.2 million. The first quarter wastewater treatment revenue was impacted by increased revenue of U.S. $0.2 million at the four Texas Silverleaf facilities and the Tall Timbers facility, primarily due to the ongoing rate cases and the related implementation of interim rate increases, U.S. $0.1 million at LPSCo primarily due to higher treated effluent revenue as compared to the same period in 2009. These increases were partially offset by decreased wastewater treatment revenue of U.S. $0.1 million due to lower treated effluent revenue at the Gold Canyon facility and lower customer demand at four wastewater treatment facilities as compared to the same period in 2009.
For the quarter ended March 31, 2010, operating expenses totalled U.S. $5.2 million, as compared to U.S. $4.9 million during the same period in 2009. Overall expenses increased U.S. $0.3 million or 6.9% as compared to the same period in 2009. Operating expenses increased U.S. $0.7 million as a result of increased wages, salary and other operating costs, partially offset by decreases of U.S. $0.1 million in reduced contracted services expenses and U.S. $0.1 million in reduced utilities and consumables expenses as compared to the same period in 2009. The comparable period includes expenses of U.S. $0.2 million related to rate case costs. As a result of the adoption of rate regulated accounting during the fourth quarter of 2009, these costs are being capitalized in the current period.
For the quarter ended March 31, 2010, Liberty Water’s operating profit totalled U.S. $2.7 million as compared to U.S. $2.9 million in the same period in 2009, a decrease of U.S. $0.2 million or 7.5%. Liberty Water’s operating profit met expectations for the three months ended March 31, 2010.
Including the impact of foreign exchange, for the quarter ended March 31, 2010, Liberty Water’s revenue totalled $8.2 million as compared to $9.7 million during the same period in 2009, a decrease of $1.4 million. Revenue from wastewater treatment totalled $4.9 million, as compared to $5.5 million during the same period in 2009, a decrease of $0.7 million. Revenue from water distribution totalled $3.2 million, as compared to $3.9 million during the same period in 2009, a decrease of $0.7 million. Liberty Water reported decreased revenue from operations of $1.5 million in the first quarter of 2010 as a result of the stronger Canadian dollar as compared to the same period in 2009.
Including the impact of foreign exchange, for the quarter ended March 31, 2010, operating expenses totalled $5.4 million, as compared to $6.1 million during the same period in 2009. Liberty Water reported lower expenses from operations of $1.0 million as a result of the stronger Canadian dollar, as compared to the same period in 2009.
For the quarter ended March 31, 2010, Liberty Water’s operating profit totalled $2.8 million as compared to $3.6 million in the same period in 2009, a decrease of $0.7 million or 20.7%. Liberty Water’s operating profit met expectations for the three months ended March 31, 2010.
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Outlook – Liberty Water
Notwithstanding the slowdown in the U.S. economy, Liberty Water is not expecting any material reduction in customers in fiscal 2010. Liberty Water continues to provide water distribution and wastewater collection and treatment services, primarily in the southern and southwestern U.S., in communities that have traditionally experienced long term growth and that provide continuing future opportunities for organic growth.
Liberty Water is proceeding through the regulatory process with rate cases relating to a number of its facilities. The following table sets out some particulars with respect to the status of the rate cases as at April 25, 2010:
Test Year | Status of Rate Case Application | Estimated Annual U.S. $ Revenue Increase as Filed | Estimated Timing of Rate Increase | ||||||
Facility | |||||||||
Arizona | |||||||||
Black Mountain | Q2 2008 | Hearing has concluded. Awaiting Recommended Order & Opinion | $ | 0.9 million | Q3 2010 | ||||
LPSCo | Q3 2008 | Hearing has concluded. Awaiting Recommended Order & Opinion | $ | 12.5 million | Q2/Q3 2010 | ||||
Rio Rico | Q4 2008 | Hearing has concluded. Currently preparing Hearing Briefs | $ | 2.0 million | Q3 2010 | ||||
Bella Vista, Northern and Southern Sunrise | Q1 2009 | Responding to interrogatories, hearing scheduled for July 2010 | $ | 1.5 million | Q4 2010 | ||||
Texas | �� | ||||||||
Texas Utilities (Silverleaf – 4 utilities) | Q4 2008 | Achieved negotiated settlement - $1.2 million annual revenue increase, subject to formal regulator approval | $ | 1.2 million | Interim rates Implemented October 2009 | ||||
Tall Timbers | Q4 2008 | Achieved negotiated settlement - $0.2 million annual revenue increase, subject to formal regulator approval | $ | 0.2 million | Interim rates implemented July 2009 | ||||
Woodmark | Q4 2008 | Uncontested rate case. Achieved $0.1 million annual revenue increase, subject to regulator approval | $ | 0.1 million | Interim rates implemented January 2010 |
Rate cases ensure that a particular facility has the opportunity to recover its operating costs and earn a fair and reasonable return on its capital investment as allowed by the regulatory authority under which the facility operates. Liberty Water monitors current and anticipated operating costs, capital investment and the rates of return in respect of each of its facility investments to determine the appropriate timing of a rate case filing in order to ensure it fully earns a rate of return on its investments.
In Texas, the TCEQ allows the utilities’ customers a period of 90 days from the effective date of the proposed rates to object to the imposition of interim rates pending final rates determination. If greater than 10% of a specific Texas utility’s customers object to the new proposed rates, the proposed rates would be subjected to a full regulatory hearing process administered over by the TCEQ in order to finalize the rates. If fewer than 10% of the customers record an objection to the proposed rates, those proposed rates are likely to be adopted and declared final as proposed. Any difference between the interim rates charged and collected and the final rates as approved by TCEQ will be subject to a retroactive adjustment and refund on the customers’ subsequent monthly bill.
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In July 2009, Tall Timbers implemented interim rates to customers in a portion of its service area as applied for in its rate case application. The interim rates were being contested by various homeowners in Tall Timbers service area affected by the increase. Liberty Water has reached a settlement agreement with these homeowners which reduced the annualized revenue increase requested by approximately $20. The settlement is subject to the Office of the Executive Director of the TCEQ and OPIC endorsement which is typically provided within 60 to 90 days of a settlement agreement being reached.
In October 2009, the Texas Silverleaf utility began charging interim rates based on its rate case applications. The interim rates are being contested by greater than 10% of the customers in the service area. An administrative hearing was held on April 27, 2010. The hearing resulted in a settlement with the named Parties to the proceeding. The settlement allows for Liberty Water’s requested revenue requirement to be permanently implemented effective May 13, 2010. The agreed upon settlement is subject to approval from the Office of the Executive Director of the TCEQ and OPIC which is typically provided within 60 to 90 days of a settlement agreement being reached.
In January 2010, Woodmark implemented interim rates based on its rate case application. The TCEQ did not receive the required 10% objection to call a hearing, and the rate application is now subject to TCEQ approval. TCEQ Staff have authority to call a hearing on the application which could result in the application proceeding through the normal evidentiary hearing process administered by the TCEQ.
In Arizona, the Arizona Corporate Commission requires a full regulatory process for all rate cases using a historic test year. It is anticipated that the regulatory review of the proposed rates and tariffs for the Arizona facilities would be completed by mid-2010, with the new rates and tariffs in Arizona going into effect throughout 2010.
An exact determination of increased revenues from all rate case applications is not possible at this time as the timing of conclusion to the rate cases and the final decision on rate increases are determined by the regulator. As a result of delays in the progress of rate cases through the regulatory processes, Liberty Water anticipates that approximately $7 million of additional revenue from rate cases will be achieved in 2010 and the full annualized increase in revenues determined through the rate case processes is expected to be achieved in 2011.
APUC: Corporate
Three months ended March 31 | ||||||
2010 | 2009 | |||||
Corporate and other expenses: | ||||||
Administrative expenses | 2,915 | 2,387 | ||||
Management costs | — | 213 | ||||
Loss / (Gain) on foreign exchange | (39 | ) | 577 | |||
Interest expense | 6,247 | 5,513 | ||||
Interest, dividend and other Income | (735 | ) | (735 | ) | ||
Loss (gain) on derivative financial instruments | (913 | ) | 3,498 | |||
Income tax expense (recovery) | (2,207 | ) | (4,992 | ) |
OVERVIEW
2010 First Quarter Corporate and Other Expenses
During the quarter ended March 31, 2010, administrative expenses totalled $2.9 million, as compared to $2.4 million in the same period in 2009. The expense increase in the three months ended March 31, 2010 results from increased capital taxes resulting from APUC’s conversion to a corporation in 2009, increased payroll related to the internalization of management and developing the IFRS conversion plan as well as added requirements to administer APUC’s operations as compared to the same period in 2009.
In 2009, APUC entered into an agreement to acquire the management contract for Algonquin from Algonquin Power Management Inc. (“APMI”), Algonquin’s previous manager and internalize management within APUC.
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As a result, during the quarter ended March 31, 2010, APUC recorded no ‘Management costs’ as compared to $0.2 million in the same period in 2009.
Foreign exchange gains and losses primarily represent unrealized gains or losses on U.S. dollar denominated debt and working capital balances held by Canadian operating entities and do not impact current cash position. During the quarter ended March 31, 2010, APUC classified all of its power generation operating facilities based in the U.S. as self sustaining. As a result, changes in the values of U.S. denominated debt and working capital balances in these U.S. operating entities after January 1, 2010 no longer flow though the consolidated statement of operations. For the three months ended March 31, 2010, APUC reported a foreign exchange gain of $39 as compared to a loss of $577 during the same period in 2009. The three months ended March 31, 2010 experienced a decrease in value of the U.S. dollar of 3% which resulted in unrealized losses on APUC’s U.S. denominated debt and working capital balances held by Canadian entities. In the comparable period in 2009, APUC’s power generation operating facilities based in the U.S. were classified as integrated and the increase in the value of the U.S. dollar of 3% experienced in the quarter resulted in unrealized losses on APUC’s U.S. denominated debt and working capital balances held by its integrated U.S. operating facilities.
For the quarter ended March 31, 2010, interest expense totalled $6.2 million as compared to $5.5 million in the same period in 2009. Interest expense increased as a result of higher levels of convertible debentures, partially offset by decreased interest expense resulting from lower interest rates charged and lower average borrowings on APUC’s variable interest rate credit facilities, as compared to the prior year.
For the quarter ended March 31, 2010, interest, dividend and other income was consistent with the prior period. Interest, dividend and other income primarily consists of dividends from APUC’s share investment in the Kirkland and Cochrane facilities. This income was previously allocated to interest and other income in the Thermal Energy division.
Loss on derivative financial instruments consists of realized and unrealized mark to market losses on foreign exchange forward contracts, interest rate swaps and forward energy contracts during the quarter. The unrealized portion of any mark to market gains or losses on derivative instruments does not impact APUC’s current cash position.
An income tax recovery of $2.2 million was recorded in the three months ended March 31, 2010, as compared to a recovery of $5.0 million during the same period in 2009. On October 27, 2009, Algonquin converted from a publicly traded income trust to a publicly traded corporation. APUC’s calculation of current and future income taxes for the quarter ended March 31, 2010 is based on its new corporate structure effective October 27, 2009, whereas APUC’s calculation of current and future income taxes for the quarter ended March 31, 2009 is based on a publicly traded income trust structure. The income tax recovery of $2.2 million in the three months ended March 31, 2010 results from APUC being able to build additional tax pools within certain of its corporate entities in both Canada and the US. The primary reasons for the reduction in income tax expense recovery in the three months ended March 31, 2010 compared to the same period in 2009 relates to the conversion to a corporation from an income trust, reduced tax losses on U.S. operations as a result of bonus depreciation being recorded in the comparable period and the reversal in the current year of unrealized losses on derivative financial instruments booked in the prior fiscal year, partially offset by decreases in expected future income tax rates. .
NON-GAAP PERFORMANCE MEASURES
Reconciliation of Adjusted EBITDA to net earnings
EBITDA is a non-GAAP metric used by many investors to compare companies on the basis of ability to generate cash from operations. APUC uses these calculations to monitor the amount of cash generated by APUC as compared to the amount of dividends paid by APUC. APUC uses Adjusted EBITDA to assess the operating performance of APUC without the effects of depreciation and amortization expense which are derived from a number of non-operating factors, accounting methods and assumptions. APUC believes that presentation of this measure will enhance an investor’s understanding of APUC’s operating performance. Adjusted EBITDA is not intended to be representative of cash provided by operating activities or results of operations determined in accordance with GAAP.
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The following table is derived from and should be read in conjunction with the interim unaudited Consolidated Statement of Operations. This supplementary disclosure is intended to more fully explain disclosures related to Adjusted EBITDA and provides additional information related to the operating performance of APUC. Investors are cautioned that this measure should not be construed as an alternative to GAAP consolidated net earnings.
Three months ended | ||||||||
March 31 | ||||||||
2010 | 2009 | |||||||
Net earnings (loss) | $ | 3,451 | 4,243 | |||||
Add: | ||||||||
Income tax provision (recovery) | (2,207 | ) | (4,992 | ) | ||||
Interest expense | 6,247 | 5,513 | ||||||
(Gain) / loss on derivative financial instruments | (913 | ) | 3,498 | |||||
(Gain) / loss on foreign exchange | (39 | ) | 577 | |||||
Amortization | 11,329 | 11,667 | ||||||
Other | 65 | 608 | ||||||
Adjusted EBITDA | $ | 17,933 | $ | 21,114 | ||||
For the quarter ended March 31, 2010, Adjusted EBITDA decreased by $3.2 million compared to the same period in 2009. The decrease in Adjusted EBITDA in the quarter ended March 31, 2010 is primarily due to $1.8 million in lower earnings from operations at the St. Leon facility, $1.3 million in lower earnings from operations at the EFW facility, $0.9 million in lower earnings from operations at the BCI facility, $0.9 million in lower earnings from operations as a result of a stronger Canadian dollar and $0.3 million in increased administration expenses, partially offset by $2.7 million in increased earnings from operations by the Tinker Assets as compared to the previous quarter.
Reconciliation of adjusted net earnings/(loss) to net earnings/(loss)
Adjusted net earnings is a non-GAAP metric used by many investors to compare net earnings from operations without the effects of certain volatile primarily non-cash items that generally have no current economic impact and are viewed as not directly related to a company’s operating performance. Net earnings/(loss) of APUC can be impacted positively or negatively by gains and losses on derivative financial instruments, including foreign exchange forward contracts, interest rate swaps as well as to movements in foreign exchange rates on foreign currency denominated debt and working capital balances. APUC uses adjusted net earnings to assess the performance of APUC without the effects of gains or losses on foreign exchange, foreign exchange forward contracts, interest rate swaps as these are not reflective of the performance of the underlying business of APUC. APUC believes that analysis and presentation of net earnings or loss on this basis will enhance an investor’s understanding of the operating performance of APUC’s businesses. It is not intended to be representative of net earnings or loss determined in accordance with GAAP.
The following table is derived from and should be read in conjunction with the interim unaudited Consolidated Statement of Operations. This supplementary disclosure is intended to more fully explain disclosures related to adjusted net earnings and provides additional information related to the operating performance of APUC. Investors are cautioned that this measure should not be construed as an alternative to consolidated net earnings in accordance with GAAP.
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The following table shows the reconciliation of net earnings to adjusted net earnings exclusive of these items:
Three months ended | |||||||
March 31 | |||||||
2010 | 2009 | ||||||
Net earnings | $ | 3,451 | $ | 4,243 | |||
Add: | |||||||
Loss (gain) on derivative financial instruments, net of tax | (418 | ) | 3,099 | ||||
Loss (gain) on foreign exchange, net of tax | (39 | ) | 577 | ||||
Adjusted net earnings | $ | 2,994 | $ | 7,919 | |||
Adjusted net earnings per share/trust unit * | $ | 0.03 | $ | 0.10 | |||
* | Algonquin converted to a corporation on October 27, 2009. Earnings prior to this date represent earnings per trust unit. |
The decrease in adjusted net earnings in the three months ended March 31, 2010 is primarily due to lower future income tax recoveries in the current year and lower earnings from operations as compared to the same period in 2009. The reasons for decreased future income tax recoveries are discussed in the APUC – Corporate section above.
SUMMARY OF PROPERTY, PLANT AND EQUIPMENT EXPENDITURES BY BUSINESS SUBSIDIARY
Three months ended | ||||||
March 31 | ||||||
2010 | 2009 | |||||
APCo | ||||||
Renewable Energy Division | ||||||
Capital expenditures | $ | 264 | $ | 298 | ||
Acquisition of operating entities | 40,281 | — | ||||
Total | $ | 40,545 | $ | 298 | ||
Thermal Energy Division | ||||||
Capital expenditures | $ | 3,835 | $ | 1,054 | ||
Total | $ | 3,835 | $ | 1,054 | ||
LIBERTY WATER | ||||||
Capital Investment in regulatory assets | $ | 45 | $ | 4,302 | ||
Acquisition of operating entities | 2,038 | — | ||||
$ | 2,083 | $ | 4,302 | |||
Consolidated (includes Corporate) | ||||||
Capital expenditures | $ | 4,114 | $ | 1,352 | ||
Capital investment in regulatory assets | 45 | 4,302 | ||||
Acquisition of operating entities | 42,319 | — | ||||
Total | $ | 46,478 | $ | 5,654 |
APUC’s consolidated capital expenditures in the first quarter of 2010 increased as compared to the same period in 2009 primarily due to APCo’s acquisition of the Tinker Assets and the Energy Services Business as well as the acquisition by Liberty Water of a water distribution and wastewater treatment facility in Texas.
Property, plant and equipment expenditures for the remainder of the 2010 fiscal year are anticipated to be between $11.5 million and $15.0 million, including approximately $2.0 million related to ongoing requirements by Liberty Water, $6.0 million related to the APCo Thermal division, and $3.5 million related to the APCo Renewable Energy division.
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APUC anticipates that it can generate sufficient liquidity through internally generated operating cash flows, working capital and bank credit facilities to finance its property, plant and equipment expenditures and other commitments.
2010 First Quarter Property Plant and Equipment Expenditures
During the three months ended March 31, 2010, APUC incurred capital expenditures of $4.1 million, as compared to $1.4 million during the comparable period in 2009. APCo also invested $40.3 million to acquire operating assets/entities during the three months ended March 31, 2010, as compared to nil during the comparable period in 2009.
During the three months ended March 31, 2010, APCo Renewable Energy division’s capital expenditures were not significant, consistent with the comparable period in 2009. The APCo Renewable Energy division’s acquisition of operating assets primarily relate to the Tinker Assets located in New Brunswick and Maine.
During the three months ended March 31, 2010, APCo Thermal Energy division’s capital primarily relate to the EFW facility where major maintenance is currently ongoing. APCo currently anticipates that it will incur a further $4.0 million in capital expenditures at the EFW facility as part of the major maintenance. In the comparable period, the expenditures primarily related to minor capital projects at the hydro-mulch facility, the BCI steam sales facility and the EFW facility.
During the three months ended March 31, 2010, Liberty Water did not invest significant capital into regulatory assets, as compared to an investment of $4.3 million in the comparable period. In the comparable period in 2009, Liberty Water’s expenditures primarily related to the completion and commissioning of projects initiated in 2008.
As previously noted, these investments, other than non-utility assets, have been included in the rate case applications currently underway. In the comparable period, the expenditures primarily related to investment in additional wells, engineering work regarding wastewater treatment operations and arsenic treatment at the LPSCo facility. The expenditures in the comparable period are included in the rate case applications which are currently in process.
LIQUIDITY AND CAPITAL RESERVES
The following table sets out the amounts drawn, letters of credit issued and outstanding amounts available to APUC and its subsidiaries under the senior banking credit facilities previously arranged by Algonquin (the “Facilities”):
2010 Q1 | 2009 Q4 | 2009 Q3 | 2009 Q2 | 2009 Q1 | ||||||||||||||||
Committed and available Facilities | $ | 177,950 | $ | 179,500 | $ | 176,700 | $ | 189,050 | $ | 192,750 | ||||||||||
Funds Drawn on Facilities | (91,650 | ) | (94,000 | ) | (129,000 | ) | (134,000 | ) | (129,500 | ) | ||||||||||
Letters of Credit issued | (32,400 | ) | (33,100 | ) | (33,400 | ) | (35,250 | ) | (37,600 | ) | ||||||||||
Remaining available Facilities | $ | 53,900 | $ | 52,400 | $ | 14,300 | $ | 19,800 | $ | 25,650 | ||||||||||
Cash on Hand | 750 | 2,800 | 7,700 | 6,900 | 900 | |||||||||||||||
Total liquidity and capital reserves | $ | 54,650 | $ | 55,200 | $ | 22,000 | $ | 26,700 | $ | 26,550 | ||||||||||
As at and for the period ended March 31, 2010, APUC and Algonquin are in compliance with the covenants under its Facilities.
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As at March 31, 2010, Can. $81.5 million and U.S. $10.0 million had been drawn on the Facilities as compared to $94.0 million as at December 31, 2009. In addition to amounts actually drawn, there was $32.4 million in letters of credit currently outstanding as at March 31, 2010. As at March 31, 2010, APUC and its subsidiaries had $53.9 million of committed and available bank facilities remaining and $0.8 million of cash resulting in $54.7 million of total liquidity and capital reserves.
The term of the Facilities matures on January 14, 2011. During the quarter ended march 31, 2010, APUC initiated discussions with its senior lenders with regards to entering into a new multi-year term senior debt facility.
CONTRACTUAL OBLIGATIONS
Information concerning contractual obligations as of March 31, 2010 is shown below:
Total | Due less than 1 year | Due 1 to 3 years | Due 4 to 5 years | Due after 5 years | |||||||||||
Long term debt obligations1 | $ | 240,469 | $ | 95,039 | $ | 71,421 | $ | 3,647 | $ | 70,362 | |||||
Convertible Debentures | $ | 187,381 | — | — | 64,164 | 123,217 | |||||||||
Interest on long term debt obligations | $ | 148,428 | 21,401 | 37,733 | 34,579 | 54,715 | |||||||||
Purchase obligations | $ | 36,679 | 36,679 | — | — | — | |||||||||
Derivative financial instruments: | |||||||||||||||
Currency forward | $ | 386 | 57 | 329 | — | — | |||||||||
Interest rate swap | $ | 6,938 | 4,766 | 1,684 | 423 | 65 | |||||||||
Energy forward contracts | $ | 1,475 | 1,475 | — | — | — | |||||||||
Capital lease obligations | $ | 698 | 203 | 408 | 86 | — | |||||||||
Other obligations | $ | 9,906 | 504 | 1,008 | 1,008 | 7,386 | |||||||||
Total obligations | $ | 632,359 | $ | 160,124 | $ | 112,583 | $ | 103,907 | $ | 255,745 | |||||
1 | Includes Funds due on Facilities, which matures on January 14, 2011 and has been recorded as a current liability on the consolidated balance sheet. |
Long term obligations include regular payments related to long term debt and other obligations. During the quarter ended March 31, 2010, the amount due under the Facility was reclassified as a current obligation as the term of the Facility matures on January 14, 2011.
SHAREHOLDER’S EQUITY AND CONVERTIBLE DEBENTURES
On October 27, 2009, pursuant to the Unit Exchange Offer, all Algonquin’s trust units were exchanged for shares of APUC that began to be publicly traded on the Toronto Stock Exchange while Algonquin’s trust units concurrently ceased trading on the Toronto Stock Exchange.
As at March 31, 2010, APUC had 93,745,244 issued and outstanding shares on a fully diluted basis.
APUC may issue an unlimited number of common shares. The holders of common shares are entitled to: dividends, if and when declared; one vote for each share at meetings of the holders of common shares, and upon liquidation, dissolution or winding up of APUC, to receive a pro rata share of any remaining property and assets of APUC. All shares are of the same class and with equal rights and privileges and are not subject to future calls or assessments.
In 2008, Algonquin entered into an agreement with Highground Capital Corporation (“Highground”) (previously Algonquin Power Venture Fund) and CJIG Management Inc. (“CJIG”) which was the manager of Highground and a related party of Algonquin controlled by the shareholders of APMI. Under the agreement, CJIG acquired all of the issued and outstanding common shares of Highground and Algonquin issued trust units to the Highground shareholders and CJIG.
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In 2009, APUC’s consideration received from the acquisition exceeded $26,970, the minimum contemplated under the agreements, and, as a result is entitled to 50% of any additional proceeds from the assets formerly owned by Highground. CJIG is entitled to the remaining 50% of any proceeds in excess of the minimum amount. During the three months ended March 31, 2010, APUC received $0.2 million (2009 - $nil) from CJIG as APUC’s share of the 50% of additional proceeds from the further liquidation of the assets held by Highground This has been recorded as an increased amount assigned to the equity originally issued.
The remaining investments, formerly held by Highground, currently consist of two non-liquid debt assets having an approximate principal amount of $2.4 million. The payments on these assets are current and the debt matures in 2010 and 2012. APUC’s 50% share of any additional proceeds from liquidation of the remaining Highground assets will be recorded when received as additional proceeds from the issuance of equity.
On October 27, 2009, APUC issued convertible unsecured subordinated debentures bearing interest at 7.5%, maturing on November 30, 2014 (“Series 1A Debentures”) in a principal amount of $66,943. During the first quarter of 2010, $2,779 principal amount of Series 1A Debentures were converted at the option of holders into 681,124 shares of APUC. Subsequent to March 31, 2010, an additional $692 principal amount of Series 1A Debentures were converted at the option of holders into 169,480 shares of APUC.
On March 31, 2010, there were 64,164 Series 1A Debentures outstanding with a face value of $64,164.
On October 27, 2009, APUC issued convertible unsecured subordinated debentures bearing interest at 6.35%, maturing on November 30, 2016 (“Series 2A Debentures”) in a principal amount of $59,967. On March 31, 2010 there were 59,967 Series 2A Debentures outstanding with a face value of $59,967.
On December 2, 2009, APUC issued 63,250 convertible unsecured subordinated debentures maturing on June 30, 2017 (“Series 3 Debentures”) in a principal amount of $63,250. On March 31, 2010, there were 63,250 Series 3 Debentures outstanding with a face value of $63,250.
MANAGEMENT OF CAPITAL STRUCTURE
APUC views its capital structure in terms of its debt levels, both at a project and an overall company level, in conjunction with its equity balances.
APUC’s objectives when managing capital are:
• | To maintain appropriate debt and equity levels in conjunction with standard industry practices and to limit financial constraints on the use of capital; |
• | To ensure capital is available to finance capital expenditures sufficient to maintain existing assets; |
• | To ensure generation of cash is sufficient to fund sustainable dividends to shareholders as well as meet current tax and internal capital requirements; |
• | To maintain sufficient cash reserves on hand to ensure sustainable dividends made to shareholders; and |
• | To have proper credit facilities available for ongoing investment in growth and investment in development opportunities. |
APUC monitors its cash position on a regular basis to ensure funds are available to meet current normal as well as capital and other expenditures. In addition, APUC continuously reviews its capital structure to ensure its individual business units are using a capital structure which is appropriate for their respective industries.
RELATED PARTY TRANSACTIONS
The following related party transactions occurred during the year ended December 31, 2009:
• | Up to December 21, 2009, APMI provided management services to Algonquin including advice and consultation concerning business planning, support, guidance and policy making and general management services. On December 21, 2009, the Board of Directors of Algonquin (the “Board”) |
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reached an agreement with APMI to internalize all management functions of Algonquin which were provided by APMI. Therefore, for the three months ended March 31, 2010, APMI was not paid a management fee. For the three months ended March 31, 2009 APMI was paid on a cost recovery basis for all costs incurred and charged $213. |
• | APUC has leased its head office facilities since 2001 from an entity owned by the shareholders of APMI on a net basis. Base lease costs for the three month period ended March 31, 2010 were $82 (2009 - $82). APUC believes the lease is on terms equivalent to fair market value for prime office space of similar size and quality at the time the lease was executed. |
• | APUC utilizes chartered aircraft, including the use of an aircraft owned by an affiliate of APMI. During the three month period ended March 31, 2010, APUC incurred costs in connection with the use of the aircraft of $148 (2009 - $80) and amortization expense related to the advance against expense reimbursements of $57 (2009 - $56). APUC believes the amounts paid for chartering the aircraft are equivalent to or better than fair market value terms otherwise available for chartering a similar aircraft. |
• | Affiliates of APMI hold 60% of the outstanding Class B limited partnership units issued by the St. Leon Wind Energy LP (“St. Leon LP”), an indirect subsidiary of APUC and the legal owner of the St. Leon facility. The holders of the Class B Units are entitled to 2.5% of the income allocations and cash distributions from St. Leon LP for a 5 year period commencing June 17, 2008 growing to a maximum of 10% by year 15. In any particular period, cash distributions to the holders of the Class B Units are only to be made after distributions have been made to the other partners, in an aggregate amount, equal to the debt service on the outstanding debt in respect of such period. The related party holders of the Class B units are entitled to cash distributions of $39 for the three month period ended March 31, 2010 (2009 - $89). |
• | APMI is entitled to 50% of the cash flow above 15% return on investment for the BCI project pursuant to its project management contract. During the three months ended March 31, 2010 and 2009, no amounts were paid under this agreement. In 2008, APMI earned a construction supervision fee of $100 in relation to the development of this project. As of March 31, 2010 this amount is accrued and included in accounts payable on the consolidated balance sheet. |
• | A member of the Board is an executive at Emera. A contract with a subsidiary of Emera to purchase energy on ISO NE and provide scheduling services on ISO NE was included as part of the acquisition of the Energy Services Business. The contract expired in the three months ended March 31, 2010 and was not renewed. As a result of this contract, during the three months ended March 31, 2010 a subsidiary of Emera provided services to and purchased energy on ISO NE on behalf of APCo’s Energy Services Business. In this capacity, APCo paid a subsidiary of Emera the amount $1,258 (2009 - $nil) which was included as an operating expense on the interim consolidated statement of operations. APUC believes that the prices paid were in accordance with normal commercial terms. |
• | During the three months ended March 31, 2010, APCo entered into a one year contract with a subsidiary of Emera to provide lead market participant services for fuel capacity and forward reserve markets in ISO NE for the Windsor Locks facility. No expenses were incurred in the quarter in relation to this contract. Subsequent to March 31, 2010, APCo issued a letter of credit to a subsidiary of Emera in an amount of U.S. $500 in conjunction with this contract. |
TREASURY RISK MANAGEMENT
APUC attempts to proactively manage the risk exposures of its subsidiaries in a prudent manner. APUC ensures that both APCo and Liberty Water maintain insurance on all of their facilities. This includes property and casualty, boiler and machinery, and liability insurance. It has also initiated a number of programs and policies including currency and interest rate hedging policies to manage its risk exposures.
There are a number of risk factors relating to the business of APUC and its subsidiaries. Some of these risks include the U.S. versus Canadian dollar exchange rates, energy market prices, any credit risk associated with a
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reliance on key customers, interest rate, liquidity and commodity price risk considerations. The risks discussed below are not intended as a complete list of all exposures that APUC may encounter. A further assessment of APUC and its subsidiaries’ business risks is also set out in the most recent Annual Information Form.
Foreign currency risk
Currency fluctuations may affect the cash flows APUC would realize from its consolidated operations, as certain APUC subsidiary businesses sell electricity or provide utility services in the United States and receive proceeds from such sales in U.S. dollars. Such APUC businesses also incur costs in U.S. dollars. At the current exchange rate, approximately 45% of EBITDA and 60% of cash flow from operations is generated in U.S. dollars. APUC estimates that, on an unhedged basis, a $0.10 increase in the strength of the U.S. dollar relative to the Canadian dollar would result in increased reported revenue from U.S. operations of approximately $9.6 million and increased reported expenses from U.S. operations of approximately $6.4 million or a net impact of $3.2 million ($0.035 per share) on an annual basis.
APUC previously managed this risk primarily through the use of forward contracts as it required U.S. dollar cash inflows to meet Canadian dollar cash outflows. As a result of the current business strategy and lower payout ratio, APUC has determined that the prior practice of hedging 100% of its U.S. currency exposure is no longer appropriate and is taking steps to eliminate its existing forward currency contract program. Subsequent to the quarter ended March 31, 2010, APUC terminated forward contracts of $11.7 million at a net cost of $10. APUC’s policy is not to utilize derivative financial instruments for trading or speculative purposes. For the quarter ended March 31, 2010 APUC realized a $0.1 million gain on managing its forward contracts.
The following chart sets out as at March 31, 2010 the amounts, hedge proceeds and average hedged rates over the term of the foreign exchange forward contracts outstanding. Contracts terminated subsequent to the quarter are omitted from this chart:
Total | 2010 | 2011 | 2012 | 2013 | ||||||||||||||
Total U.S. $ Hedged | $ | 28,030 | $ | — | $ | 16,700 | $ | 10,580 | $ | 750 | ||||||||
Total Can. $ Proceeds | $ | 28,479 | — | 16,856 | 10,820 | 803 | ||||||||||||
Average Hedged Rate | $ | 1.016 | n/a | $ | 1.009 | $ | 1.023 | $ | 1.070 | |||||||||
Unrealized Gain (loss) | $ | (326 | ) | n/a | (251 | ) | (96 | ) | 21 | |||||||||
Impact of a $0.10 move in exchange rates | $ | 2,803 | n/a | $ | 1,670 | $ | 1,058 | $ | 75 |
Based on the fair value of the forward contracts using the exchange rates as at March 31, 2010, the exercise of these forward contracts will result in the use of cash of $0.3 million in fiscal 2011 and result in the use of cash of $0.1 million for the remainder of the hedged period beyond 2011. Assuming a decrease in the strength of the US dollar relative to the Canadian dollar of $0.10 at March 31, 2010, with a corresponding increase in the forward yield curve, the fair value of the outstanding forward exchange contracts would increase by $2.8 million, resulting in the generation of additional cash of $1.7 million in fiscal 2011, and the generation of $1.1 million in additional cash for the remainder of the hedged period beyond 2011.
Market price risk
The majority of APCo’s electricity generating facilities sell their output pursuant to long term PPAs. However, certain of APCo’s hydroelectric facilities in the New England and New York regions sell energy at current spot market rates. In this regard, each $10.00 per MW-hr change in the market prices in the New England and New York regions would result in a change in revenue of $1.0 million on an annualized basis.
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Energy price risk
APCo’s Energy Services Business provides the short-term energy requirements to various customers at fixed rates. The energy requirements of these customers are estimated at approximately 150,000 MW-hrs on an annualized basis. While the Tinker Assets are expected to provide the majority of the energy required to service these customers, the Energy Services Business anticipates having to purchase a portion of its energy requirements at the ISO NE spot rates to supplement self-generated energy. In the event that the Energy Services Business was required to purchase all of its energy requirements at ISO NE spot rates, each $10.00 change per MW-hr in the market prices in ISO NE would result in a change in expense of $1.5 million on an annualized basis.
This risk is mitigated though the use of short term forward energy hedge contracts. APCo has committed to acquire approximately 5,000 MW-hrs of net energy over the next 11 months at an average rate of approximately $75 per MW-hr. The mark to market value of these forward energy hedge contracts at March 31, 2010 was a net million liability of U.S. $1.5 million.
Interest rate risk
APUC and its subsidiaries have a number of project specific and other debt facilities that are subject to a variable interest rate. These facilities and the sensitivity to changes in the variable interest rates charged are discussed below:
• | The Facilities had an outstanding balance drawn of Can. $81.5 million and U.S. $10.0 million as at March 31, 2010. Assuming the current level of borrowings over an annual basis, a 1% change in the variable rate charged would impact interest expense by Can $0.8 million and U.S. $0.1 million annually. Algonquin has fixed for floating interest rate swaps in an amount of $100.0 million which fix the interest expense on $100.0 million of borrowings at approximately 4.125% for the remainder of 2010. This reduces volatility in the interest expense on this debt. The financial impact of any changes in interest rates are partially offset between the change in interest expense and the change in the underlying value of the interest rate swap. At March 31, 2010, the mark to market value of the interest rate swap was a net $2.4 million liability (March 31, 2009 – $5.3 million net liability). |
• | APCo’s project debt at the St. Leon facility had a balance of $70.0 million as at March 31, 2010. Assuming the current level of borrowings over an annual basis, a 1% change in the variable rate charged would impact interest expense by $0.7 million annually. Although the underlying debt with the project lenders carries variable rate of interest tied to the Canadian bank’s prime rate, APCo has entered into a fixed for floating interest rate swap on this project specific debt until September 2015 which mirrors the underlying debt’s interest and principal repayment schedule. This minimizes volatility in the interest expense on this debt. The financial impact of interest rate changes are effectively offset between the change in interest expense and the change in value of the interest rate swap. APCo has effectively fixed its interest expense on its senior debt facility at 5.47%. At March 31, 2010, the mark to market value of the interest rate swap was a net liability of $4.5 million (March 31, 2009 – net liability of $10.0 million). |
• | APCo’s project debt at its Sanger cogeneration facility has a balance of U.S. $19.2 million as at March 31, 2010. Assuming the current level of borrowings over an annual basis, a 1% change in the variable rate charged would impact interest expense by U.S. $0.2 million annually. |
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Liquidity risk
Liquidity risk is the risk that APUC and its subsidiaries will not be able to meet their financial obligations as they become due. APUC’s approach to managing liquidity risk is to ensure, to the extent possible, that it will always have sufficient liquidity to meet liabilities when due.
APUC currently pays a dividend of $0.24 per share per year. The Board determines the amount of dividends to be paid, consistent with APUC’s commitment to the stability and sustainability of future dividends, after providing for amounts required to administer and operate APUC and its subsidiaries, for capital expenditures in growth and development opportunities, to meet current tax requirements and to fund working capital that, in their judgment, ensure APUC’s long-term success. Based on the current level of dividends paid during the quarter ended March 31, 2010, cash provided by operating activities exceeded dividends declared by 2.6 times.
As at March 31, 2010, APUC had cash on hand of $0.8 million and $53.9 million available to be drawn on the Facilities. The term of the Facilities matures on January 14, 2011 and therefore it is currently classified on the interim consolidated balance sheet as a current liability. During the quarter ended March 31, 2010, APUC initiated discussions with its senior lenders with regards to entering into a new multi-year term senior debt facility. See the Liquidity and Capital Reserves section for a more detailed discussion and chart of the funds available to APUC and its subsidiaries under the Facilities.
The Facilities and project specific debt total approximately $240.5 million with maturities set out in the Contractual Obligation table. In the event that APUC was required to replace these Facilities with borrowings having less favourable terms or higher interest rates, the level of cash generated for dividends and reinvestment into the company may be negatively impacted. APUC attempts to manage the risk associated with floating rate interest loans through the use of interest rate swaps.
The cash flow generated from several of APUC’s operating facilities is subordinated to senior project debt. In the event that there was a breach of covenants or obligations with regards to any of these particular loans which was not remedied, the loan could go into default which could result in the lender realizing on its security and APUC losing its investment in such operating facility. APUC actively manages cash availability at its operating facilities to ensure they are adequately funded and minimize the risk of this possibility.
Commodity price risk
APCo’s exposure to commodity prices is primarily limited to exposure to natural gas price risk. Liberty Water is not subject to any material commodity price risk. In this regard, a discussion of this risk is set out as follows:
• | APCo’s Sanger facility’s PPA includes provisions which reduce its exposure to natural gas price risk. In this regard, a $1.00 increase in the price of natural gas per mmbtu, based on expected production levels, would result in an increase in expenses of approximately $1.1 million on an annual basis. However, because the facility’s energy price is linked to the price of natural gas, this increase would result in a corresponding increase in revenue of $1.2 million or a net increase in operating profits of approximately $0.1 million. |
• | APCo’s Windsor Locks facility’s PPA includes provisions which reduce its exposure to natural gas price risk. In this regard, a $1.00 increase in the price of natural gas per mmbtu, based on expected production levels, would result in an increase in expenses of approximately $1.0 million on an annual basis. |
• | APCo’s BCI facility’s energy services agreement includes provisions which reduce its exposure to natural gas price risk. In this regard, a $1.00 increase in the price of natural gas |
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per mmbtu, based on expected production levels, would result in an increase in expenses of approximately $0.3 million on an annual basis. However, because the facility’s energy price is linked to the price of natural gas, this increase would result in a corresponding increase in revenue of $0.4 million or a net increase in operating profits of approximately $0.1 million. |
RISK MANAGEMENT
APUC attempts to proactively manage its risk exposures in a prudent manner and has initiated a number of programs and policies such as employee health and safety programs and environmental safety programs to manage its risk exposures.
There are a number of risk factors relating to the business of APUC and its subsidiaries. Some of these risks include the dependence upon APUC businesses, regulatory climate and permits, tax related matters, gross capital requirements, labour relations, reliance on key customers and environmental health and safety considerations. In addition to risk disclosed herein, an assessment of APUC risks should be considered in conjunction with the risks disclosed in APUC’s MD&A for the year ended December 31, 2009. The risks discussed below are not intended as a complete list of all exposures that APUC and its subsidiaries may encounter. A further assessment of APUC’s business risks is also set out in the most recent AIF.
Regulatory Risk
The utility facilities are subject to rate setting by State regulatory agencies. Liberty water has 9 ongoing rate cases before regulatory bodies in Arizona and Texas in varying stages of completion. More details regarding the status of these proceedings are set out inOutlook – Liberty Water. The time between a utility’s incurring of costs and the granting of the rates to recover those costs by utility commissions is known as regulatory lag. As a result of regulatory lag, inflationary effects may impact the ability to recover expenses, and profitability could be impacted. Federal, State and local environmental laws and regulations impose substantial compliance requirements on water and wastewater utility operations.
Asset Retirement Obligations
APUC and its subsidiaries complete periodic reviews of potential asset retirement obligations that may require recognition. As part of this process, APUC and its subsidiaries consider the contractual requirements outlined in their operating permits, leases and other agreements, the probability of the agreements being extended, the likelihood of being required to incur such costs in the event there is an option to require decommissioning in the agreements, the ability to quantify such expense, the timing of incurring the potential expenses as well as business and other factors which may be considered in evaluating if such obligations exist and in estimating the fair value of such obligations. Based on its assessments, APUC’s businesses do not have any significant retirement obligation liabilities and has not recorded any liability in its financial statements.
Environmental Risks
APUC and its subsidiaries face a number of environmental risks that are normal aspects of operating within the renewable power generation, thermal power generation and utilities business segments which have the potential to become environmental liabilities. Many of these risks are mitigated through the maintenance of adequate insurance which include property, boiler and machinery, environmental and excess liability policies.
APUC’s policy is to record estimates of environmental liabilities when they are known or considered probable and the related liability is estimable. There are no known material environmental liabilities as at March 31, 2010.
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Critical Accounting Estimates
APUC prepared its interim Consolidated Financial Statements in accordance with Canadian GAAP. An understanding of APUC’s accounting policies is necessary for a complete analysis of results, financial position, liquidity and trends. Refer to Note 1 to the interim Consolidated Financial Statements for additional information on accounting principles. The interim Consolidated Financial Statements are presented in Canadian dollars rounded to the nearest thousand, except per unit amounts and except where otherwise noted.
Additional disclosure of APUC’s critical accounting estimates is also available in APUC’s MD&A for the year ended December 31, 2009 available on SEDAR atwww.sedar.com and on the APUCwebsite at www.AlgonquinPowerandUtilities.com.
Controls and Procedures
There were no changes made in the first quarter of 2010 to the internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the internal control over financial reporting.
Quarterly Financial Information
The following is a summary of unaudited quarterly financial information for the two years ended March 31, 2010.
Millions of dollars (except per share amounts) | 2nd Quarter 2009 | 3rdQuarter 2009 | 4thQuarter 2009 | 1stQuarter 2010 | ||||||||||
Revenue | $ | 46.5 | $ | 45.1 | $ | 43.4 | $ | 45.9 | ||||||
Net earnings /(loss) | 15.3 | 13.1 | (1.4 | ) | 3.5 | |||||||||
Net earnings / (loss) per share/trust unit | 0.20 | 0.17 | (0.03 | ) | 0.04 | |||||||||
Total Assets | 952.4 | 925.7 | 1,013.4 | 966.2 | ||||||||||
Long term debt* | 456.2 | 445.4 | 439.9 | 433.9 | ||||||||||
Dividend/distribution per share/trust unit | 0.06 | 0.06 | 0.06 | 0.06 | ||||||||||
2nd Quarter 2008 | 3rd Quarter 2008 | 4th Quarter 2008 | 1st Quarter 2009 | |||||||||||
Revenue | $ | 54.2 | $ | 55.1 | $ | 56.5 | $ | 52.2 | ||||||
Net earnings / (loss) | 8.0 | (4.4 | ) | (21.1 | ) | 4.2 | ||||||||
Net earnings / (loss) per trust unit | 0.10 | (0.06 | ) | (0.27 | ) | 0.05 | ||||||||
Total Assets | 950.0 | 962.7 | 978.5 | 974.2 | ||||||||||
Long term debt* | 469.6 | 460.9 | 462.9 | 457.6 | ||||||||||
Distribution per trust unit | 0.23 | 0.23 | 0.06 | 0.06 |
* | Long term debt includes long term liabilities, the Facilities, convertible debentures and other long term obligations |
The quarterly results are impacted by various factors including seasonal fluctuations and acquisitions of facilities as noted in this MD&A.
Quarterly revenues have fluctuated between $43.4 million and $56.5 million over the prior two year period. A number of factors impact quarterly results including seasonal fluctuations, hydrology and winter and summer rates built into the PPAs. In addition, a factor impacting revenues year over year is the significant fluctuation in the strength of the Canadian dollar which has resulted in significant changes in reported revenue from U.S. operations.
Quarterly net earnings have fluctuated between net earnings of $15.3 million and a net loss of $21.1 million over the prior two year period. Earnings have been significantly impacted by non-cash factors such as future tax expense due to the enactment of Bill C-52 and gains and losses on financial instruments due to APUC’s adoption of Section 3855 and the discontinuation of hedge accounting under Section 3865.
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Changes in Accounting Policies
APUC’s accounting policies are described in Note 1 to the interim Consolidated Financial Statements for the period ended March 31, 2010. There have been no changes to the critical accounting policies as disclosed in APUC’s audited Consolidated Financial Statements for the period ended December 31, 2009 except as disclosed below.
Change in accounting estimates
As a result of the change in its corporate structure, APUC reevaluated its exposure to currency exchange rate changes as determined by the underlying facts and circumstances of the economy in which the U.S. divisions operate. APUC concluded that the U.S. operations of the Renewable Energy and Thermal Energy divisions no longer should be classified as integrated foreign operations but rather self-sustaining operations. Consequently, these divisions are prospectively translated into Canadian dollars using the current rate method, effective January 1, 2010. The net exchange adjustment of $37.6 million resulting from the current rate translation of non-monetary items principally property, plant and equipment and intangible assets as of the date of the change is included as a separate component of other comprehensive income with a corresponding reduction to the carrying amount of the non-monetary items.
Changeover to International Financial Reporting Standards
In 2011, APUC is required to change the accounting framework under which financial statements are prepared in Canada to International Financial Reporting Standards (“IFRS”). For the quarter ended March 31, 2011, APUC will report quarterly comparative financial information using IFRS. While the exact impact on APUC’s financial statements of moving to IFRS is not completely known at this time; APUC conducted a high level diagnostic and qualitative assessment of its operations in order to identify the main areas where IFRS conversion will have the largest impact. Based on the analysis to date, areas of potential change may involve the valuation of property, plant and equipment, business combinations, translation of financial statements of foreign operations, consolidation, income taxes, financial statement disclosure and initial adoption of IFRS under the provisions of IFRS 1, First-Time Adoption of IFRS. Experience in other jurisdictions has shown that earnings may tend to become more volatile and there will be an increase in the volume and complexity of financial disclosures.
APUC has developed a conversion plan in order to be prepared for the conversion and to minimize any disruption the conversion may cause. APUC’s conversion plan, detailed below, addresses matters including detailed assessment of the effect of IFRS on its financial statements preparation, information systems requirements, internal control over financial reporting (“ICOFR”) as well as disclosure controls and procedures (“DC&P”), in addition to training and other related business matters. This conversion plan is subject to change as a result of ongoing and subsequent changes to IFRS standards and interpretations. APUC’s Audit Committee is involved with this process and will be provided formal updates on a quarterly basis and as required.
Financial Statement preparation
APUC has begun to prepare IFRS format financial statements to highlight note disclosure differences between IFRS and Canadian GAAP. Following the company wide high-level analysis, detailed analyses are being performed for each of the main areas of differences. At that point, detailed accounting differences are identified and quantified, the impact on information systems and the need for training are assessed and the resulting changes to ICOFR and DC&P evaluated, designed and implemented area by area. The company-wide impact will then be summarized and finalized. The adjustments that arise on retrospective conversion from Canadian GAAP to IFRS will be recognized directly in opening retained earnings. Four key areas of differences are described below.
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Property, Plant & Equipment (“PP&E”)
The plan focuses initially on its greatest area of required effort being PP&E. IFRS and Canadian GAAP contain the same basic principles for PP&E; however, there are some differences. Specifically, there may be changes in accounting for PP&E relating to:
• | Component accounting, including periodic overhaul costs (power generation) |
• | Rate-regulated entities |
IFRS requires PP&E to be measured at cost in accordance with IFRS, breaking down material items into components and amortizing each one separately. This method of componentizing PP&E may result in an increased number of component parts for the power generation facilities that are separately recorded and depreciated and, as a result, may impact the calculation of depreciation expense. Significant progress has been made in this area.
In April 2010, the International Accounting Standards Board (“IASB”) decided to include in the Annual Improvements 2008-2010 cycle an amendment to IFRS 1First-time Adoption of International Financial Reporting Standards regarding the use of a previous GAAP carrying amount as deemed cost for property, plant and equipment and intangible assets used in operations subject to rate regulation. APUC intends to avail itself of this IFRS 1 exemption which will allow Liberty Water to use the carrying amount of PP&E reported under Canadian GAAP as at December 31, 2009 as its deemed cost at the date of transition to IFRSs.
In addition, IFRS permits PP&E to be measured at fair value or amortized cost. In this regard, APUC expects to continue to reflect PP&E at amortized costs.
Impairment of long-lived assets
Canadian GAAP impairment testing for long-lived assets involves two steps, the first of which compares the asset carrying values with undiscounted future cash flows to determine whether impairment exists. If the carrying value exceeds the amount recoverable on an undiscounted basis, then the carrying values are written down to estimated fair value. IFRS uses a one-step approach for both testing for and measurement of impairment, with an asset carrying value compared directly with the higher of fair value less costs to sell and value in use (which uses discounted future cash flows). This may result in more frequent write-downs where carrying values of assets were previously considered recoverable under Canadian GAAP on an undiscounted cash flow basis, but could not be supported on a discounted cash flow basis. The work in this area will be performed once the carrying value of assets, namely PP&E, under IFRS as been assessed and finalized.
Business combinations
No significant immediate impact on the financial statements is anticipated on adoption of IFRS as APUC expects to take advantage of the IFRS 1 exemption which avoids the requirement to retrospectively restate all business combinations prior to the date of transition to IFRS, subject to certain balance sheet adjustments. Going forward, a number of differences between IFRS and Canadian GAAP will affect APUC’s business acquisitions. Under IFRS, all assets and liabilities of an acquired business are recorded at fair value. Estimated obligations for contingent considerations and contingencies are also recorded at fair value at the acquisition date. In addition, acquisition-related costs are expensed as incurred. Under Canadian GAAP, acquisition-related costs form part of the consideration paid for the acquisition and contingent considerations are recorded as part of the cost of the acquisition when the contingency is resolved and the consideration is issued or becomes issuable.
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Translation of foreign currency operations
IFRS requires each entity to determine its functional currency using a hierarchy of criteria. Under Canadian GAAP, prior to January 1, 2010, the power generation facilities operating in the U.S. were considered integrated operations and translated into Canadian dollars using the temporal method whereby current rates of exchange are used for monetary assets and liabilities, historical rates of exchange for non-monetary assets and liabilities and average rates of exchange for revenues and expenses, except amortization which is translated at the rates of exchange applicable to the related assets. Gains and losses resulting from these translation adjustments are included in income. Under IFRS, APUC expects that its U.S. operations will all be considered to have a U.S. dollar functional currency. The assets and liabilities of these operations will be translated into Canadian dollars at the rate prevailing at the balance sheet date while revenues and expenses to be converted using average rates for the period. Unrealized gains or losses arising as a result of the translation of the operations of self-sustaining operations will be reported as a component of Other Comprehensive Income in the Consolidated Statement of Comprehensive Income. Effective January 1, 2010, the power generation facilities operating in the U.S. are accounted for as self-sustaining operations under Canadian GAAP and are prospectively translated into Canadian dollars using the current rate method. As the current rate method is essentially the same as the translation method used under IFRS, APUC no longer expects any translation differences upon transition to IFRS.
Activity | Milestone/Deadlines | Progress to date | ||
Identify relevant differences between IFRS and Canadian GAAP, design and implement solutions. | Assessment and quantification of the significant effects of the changeover completed by approximately the third quarter of 2010. | Fundamental IFRS/GAAP differences identified. | ||
Evaluate and select one-time and ongoing accounting policy alternatives. | Final selection of accounting policy alternatives by the fourth quarter of 2010. | Assessment and quantification is underway. | ||
Quantify the effects of changeover to IFRS. | ||||
Prepare draft IFRS format financial statements. | Draft IFRS format financial statements presented to the Audit Committee. |
Financial reporting expertise
APUC hired subject matter experts to co-ordinate, manage and execute on the changeover process. APUC’s key personnel and Audit Committee members continue to invest in various training courses with regards to IFRS rules and the impact it will have on APUC’s reporting requirements. Internal training continues to be developed for the Audit Committee and personnel affected by IFRS.
Activity | Milestone/Deadlines | Progress to date | ||
Define and introduce appropriate level of IFRS expertise. | Audit Committee training in advance of accounting policy decisions. | Key areas training presented to Audit Committee members in 2009. | ||
Training for accounting and operations as each area is rolled out, no later than Q4 2010. | Other areas are in progress. |
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Information systems
APUC continues to assess the expected impact of the conversion to IFRS on the IT systems. APUC does not expect combining the IFRS conversion with major IT system conversion. No significant changes to the systems have been required to date.
Activity | Milestone/Deadlines | Progress to date | ||
Identify and address changes required to IT systems. | Changes to significant systems and dual reporting completed for the third quarter of 2010. | IT assessment for the critical areas is under way. | ||
Evaluate and select methods to address need for dual record-keeping during 2010 for comparative and budget planning purposes in 2011. |
Internal controls
APUC continuously assess the expected impact of the conversion to IFRS on internal control over financial reporting (“ICOFR”) and disclosure controls and procedures (“DC&P”). No significant changes have been required to internal controls to-date. Investor relations will be updated once the impacts of the transition to IFRS are better understood which will most likely be sometime in 2010 or 2011.
Activity | Milestone/Deadlines | Progress to date | ||
Identify and address changes required to ICOFR and DC&P to financial systems. | Changes to significant systems assessed and designed by Q3 2010. | ICOFR & DC&P assessment for the critical areas is under way. | ||
Assess design and effectiveness implications. | Effectiveness of internal controls signed off by Q4 2010. |
Business matters
APUC’s Facilities mature on January, 14, 2011. Bank discussions have been initiated during the quarter ended March 31, 2010. Accordingly, APUC will be in a position to review and amend any financial covenants impacted by IFRS during the renewal process.
Activity | Milestone/Deadlines | Progress to date | ||
Identify and address changes required to business matters such as bank covenants, compensation, internal reporting, budgeting and rate case filings. | Changes to significant systems and dual reporting completed for the fourth quarter of 2010. | Bank discussions have been initiated. |
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