Exhibit 99.3
Management Discussion & Analysis
(All monetary amounts are in thousands of Canadian dollars, except per share amounts or where otherwise noted.)
Management of Algonquin Power & Utilities Corp. (“APUC” or the “Company”) has prepared the following discussion and analysis to provide information to assist its shareholders’ understanding of the financial results for the three and twelve months ended December 31, 2014. The Management Discussion & Analysis (“MD&A”) should be read in conjunction with APUC’s audited consolidated financial statements for the years ended December 31, 2014 and 2013. This material is available on SEDAR at www.sedar.com and on the APUC website at www.AlgonquinPowerandUtilities.com. Additional information about APUC, including the most recent Annual Information Form (“AIF”) can be found on SEDAR at www.sedar.com.
This MD&A is based on information available to management as of March 15, 2015.
Caution concerning forward-looking statements and non-GAAP Measures
Forward-looking statements
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 “anticipates”, “believes”, “continues”, “could”, “expect”, “estimates”, “intends”, “may”, “outlook”, “plans”, “project”, “strives”, “will”, 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 actual results may differ materially from the expectations set out in the forward-looking statements. Material risk factors include 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. In addition, such statements are made based on information available and expectations as of the date of this MD&A and such expectations may change after this date. APUC reviews material forward-looking information it has presented, not less frequently than on a quarterly basis. 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.
Non-GAAP Financial Measures
The terms “adjusted net earnings”, “adjusted earnings before interest, taxes, depreciation and amortization” (“Adjusted EBITDA”), “adjusted funds from operations”, “per share cash provided by adjusted funds from operations”, “per share cash provided by operating activities”, "net energy sales", and "net utility sales", are used throughout this MD&A. The terms “adjusted net earnings”, “per share cash provided by operating activities”, “adjusted funds from operations”, “per share cash provided by adjusted funds from operations”, Adjusted EBITDA, "net energy sales" and "net utility sales" are not recognized measures under GAAP. There is no standardized measure of “adjusted net earnings”, Adjusted EBITDA, “adjusted funds from operations”, “per share cash provided by adjusted funds from operations”, “per share cash provided by operating activities”, "net energy sales", and "net utility sales" 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”, Adjusted EBITDA, “adjusted funds from operations”, “per share cash provided by adjusted funds from operations”, “per share cash provided by operating activities”, "net energy sales" and "net utility sales" can be found throughout this MD&A. Per share cash provided by operating activities is not a substitute measure of performance for earnings per share. Amounts represented by per share cash provided by operating activities do not represent amounts available for distribution to shareholders and should be considered in light of various charges and claims against APUC.
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Use of Non-GAAP Financial Measures
Adjusted EBITDA
EBITDA is a non-GAAP measure 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 (as applicable): depreciation and amortization expense, income tax expense or recoveries, acquisition costs, litigation expenses, interest expense, gain or loss on derivative financial instruments, write down of intangibles and property, plant and equipment, earnings attributable to non-controlling interests and gain or loss on foreign exchange, earnings or loss from discontinued operations and other typically non-recurring items. APUC adjusts for these factors as they may be non-cash, unusual in nature and are not factors used by management for evaluating the operating performance of the company. 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.
Adjusted net earnings
Adjusted net earnings is a non-GAAP measure 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 or items such as acquisition expenses or litigation expenses and are viewed as not directly related to a company’s operating performance. Net earnings of APUC can be impacted positively or negatively by gains and losses on derivative financial instruments, including foreign exchange forward contracts, interest rate swaps and energy forward purchase contracts as well as to movements in foreign exchange rates on foreign currency denominated debt and working capital balances. Adjusted weighted average shares outstanding represents weighted average shares outstanding adjusted to remove the dilution effect related to shares issued in advance of funding requirements. APUC uses adjusted net earnings to assess its performance without the effects of (as applicable): gains or losses on foreign exchange, foreign exchange forward contracts, interest rate swaps, acquisition costs, litigation expenses and write down of intangibles and property, plant and equipment, earnings or loss from discontinued operations and other typically non-recurring items 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 its businesses. It is not intended to be representative of net earnings or loss determined in accordance with GAAP.
Adjusted funds from operations
Adjusted funds from operations is a non-GAAP measure used by investors to compare cash flows from operating activities without the effects of certain volatile items that generally have no current economic impact or items such as acquisition expenses and are viewed as not directly related to a company’s operating performance. Cash flows from operating activities of APUC can be impacted positively or negatively by changes in working capital balances, acquisition expenses, litigation expenses cash provided or used in discontinued operations. Adjusted weighted average shares outstanding represents weighted average shares outstanding adjusted to remove the dilution effect related to shares issued in advance of funding requirements. APUC uses adjusted funds from operations to assess its performance without the effects of (as applicable) changes in working capital balances, acquisition expenses, litigation expenses, cash provided or used in discontinued operations and other typically non-recurring items affecting cash from operations as these are not reflective of the long-term performance of the underlying businesses of APUC. APUC believes that analysis and presentation of funds from operations on this basis will enhance an investor’s understanding of the operating performance of its businesses. It is not intended to be representative of cash flows from operating activities as determined in accordance with GAAP.
Net energy sales
Net energy sales is a non-GAAP measure used by investors to identify revenue after commodity costs used to generate revenue where revenue generally is increased or decreased in response to increases or decreases in the cost of the commodity to produce that revenue. APUC uses net energy sales to assess its revenues without the effects of fluctuating commodity costs as such costs are predominantly passed through either directly or indirectly in the revenue that is charged. APUC believes that analysis and presentation of net energy sales on this basis will enhance an investor’s understanding of the revenue generation of its businesses. It is not intended to be representative of revenue as determined in accordance with GAAP.
Net utility sales
Net utility sales is a non-GAAP measure used by investors to identify utility revenue after commodity costs, either natural gas or electricity, where these commodities are generally included as a pass through in rates to its utility customers. APUC uses net utility sales to assess its utility revenues without the effects of fluctuating commodity costs as such costs are predominantly passed through and paid for by the utility customer. APUC believes that analysis and presentation of net utility sales on this
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basis will enhance an investor’s understanding of the revenue generation of its utility businesses. It is not intended to be representative of revenue as determined in accordance with GAAP.
Overview and Business Strategy
APUC is incorporated under the Canada Business Corporations Act. APUC owns and operates a diversified portfolio of regulated and non-regulated generation, distribution and transmission utility assets which deliver predictable earnings and cash flows. APUC seeks to maximize total shareholder value through a quarterly dividend augmented by share price appreciation arising from dividend growth supported by increasing per share cash flows and earnings.
APUC’s current quarterly dividend to shareholders is U.S. $0.0875 per share or U.S. $0.35 per share per annum. Based on exchange rates as at December 31, 2014, the quarterly dividend is equivalent to CAD $0.10 per share or CAD $0.41 per share per annum. APUC believes its annual dividend payout allows for both an immediate return on investment for shareholders and retention of sufficient cash within APUC to fund growth opportunities and mitigate the impact of fluctuations in foreign exchange rates. Further increases in the level of dividends paid by APUC are at the discretion of the APUC Board of Directors (the “Board”) with dividend levels being reviewed periodically by the Board in the context of cash available for distribution and earnings together with an assessment of the growth prospects available to APUC. APUC strives to achieve its results in the context of a moderate risk profile consistent with top-quartile North American power and utility operations.
APUC's operations are organized across three business units consisting of Generation, Transmission and Distribution. The Generation Business Group ("Generation Group") owns and operates a diversified portfolio of non-regulated renewable and thermal electric generation utility assets; the recently formed Transmission Business Group ("Transmission Group") is responsible for evaluating and capitalizing upon natural gas pipeline and electric transmission asset opportunities in North America; and the Distribution Business Group ("Distribution Group") owns and operates a portfolio of North American electric, natural gas and water distribution and wastewater collection utility systems.
Generation Business Group
The Generation Group generates and sells electrical energy produced by its diverse portfolio of non-regulated renewable power generation and clean energy power generation facilities located across North America. The Generation Group seeks to deliver continuing growth through development of new greenfield power generation projects and accretive acquisitions of additional electrical energy generation facilities.
The Generation Group owns or has interests in hydroelectric, wind, and solar facilities with a combined generating capacity of approximately 120 MW, 675 MW, and 10MW, respectively. Approximately 83% of the electrical output from the hydroelectric, wind and solar generating facilities is sold pursuant to long term contractual arrangements which have a weighted average remaining contract life of 14 years.
The Generation Group owns or has interests in thermal energy facilities with approximately 335 MW of installed generating capacity. Approximately 91% of the electrical output from the owned thermal facilities is sold pursuant to long term power purchase agreements (“PPA”) with major utilities, which have a weighted average remaining contract life of 7 years.
The Generation Group also has a portfolio of development projects that between 2015 and 2018 will add approximately 529 MW of generation capacity from wind and solar powered generating stations with an average contract life of 22 years.
Distribution Business Group
The Distribution Group operates diversified rate regulated electricity, natural gas, water distribution and wastewater collection utility services to approximately 488,000 connections. The Distribution Group provides safe, high quality and reliable services to its ratepayers through its nationwide portfolio of utility systems and delivers stable and predictable earnings to APUC. In addition to encouraging and supporting organic growth within its service territories, the Distribution Group delivers continued growth in earnings through accretive acquisition of additional utility systems.
The Distribution Group's regulated electrical distribution utility systems and related generation assets are located in the States of California and New Hampshire; and together serve approximately 93,000 electric connections.
The Distribution Group's regulated natural gas distribution utility systems are located in the States of Georgia, Illinois, Iowa, Massachusetts, Missouri and New Hampshire; and together serve approximately 292,000 natural gas connections.
The Distribution Group's regulated water distribution and wastewater collection utility systems are located in the States of Arizona, Arkansas, Illinois, Missouri, and Texas; and together serve approximately 103,000 connections.
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Transmission Business Group
In 2014, APUC created a Transmission Group that is responsible for identifying, evaluating and capitalizing upon natural gas pipeline and electric transmission investment opportunities in North America. The Company believes that the creation of the Transmission Group complements the growth of both the Generation and Distribution Groups.
Major Highlights
2014 Corporate Highlights
Dividend Increased to U.S. $0.35 Per Common Share Annually
APUC has completed several acquisitions and advanced on other initiatives including its power development projects that have raised the growth profile for APUC’s earnings and cash flows which in turn supports an increase in the dividend to shareholders. As a result, on August 14, 2014, the Board approved a dividend increase to U.S. $0.35 per share per annum, paid quarterly at a rate of U.S. $0.0875 per share per annum, a 12.4% increase over the previous dividend of CDN $0.34 calculated using the exchange rate in effect at that time. The change in the currency of the dividend better aligns APUC's dividend with the currency profile of its underlying operations. APUC's consolidated assets are approximately 80% based in the U.S. and generate approximately 77% of its underlying cash flows.
Management believes that the increase in dividend is consistent with APUC’s stated strategy of delivering total shareholder return comprised of attractive current dividend yield and capital appreciation founded on increased earnings and cash flows.
Strengthening the Balance Sheet and Poising for Continued Growth
Issuance of $100 million Preferred Shares
On March 5, 2014, APUC issued 4.0 million cumulative rate reset preferred shares, Series D at a price of $25 per share, for aggregate gross proceeds of $100.0 million. The Series D shares will yield 5.0% annually for the initial five-year period ending March 31, 2019. The preferred shares have been assigned a rating of P-3 (High) and Pfd-3 (Low) by S&P and DBRS, respectively. The net proceeds of the offering were used to partially finance certain of APUC’s previously disclosed growth opportunities, reduce amounts outstanding on APUC’s revolving credit facilities, and for general corporate purposes.
Issuance of Common Shares
On September 16, 2014, APUC completed a public offering (the "September Offering") of 16,860,000 common shares at a price of $8.90 per share, for gross proceeds of approximately $150.0 million. On September 26, 2014, the underwriters exercised the over-allotment option granted with the September Offering and an additional 2,529,000 common shares were issued on the same terms and conditions of the September Offering. As a result, APUC issued an aggregate of 19,389,000 common shares under the September Offering for the total gross proceeds of approximately $172.6 million.
On December 11, 2014, APUC completed a public offering of 10,055,000 common shares at a price of $9.95 per share, for gross proceeds of approximately $100.0 million.
Net proceeds of both common share offerings were used to finance certain of APUC's previously disclosed growth opportunities, reduce amounts outstanding on APUC's revolving credit facilities, and for general corporate purposes.
Private Placement of Subscription Receipts to Emera Inc.
On September 4, 2014, APUC and Emera Inc. (“Emera”) entered into a subscription agreement pursuant to which Emera agreed to subscribe for an aggregate of 7,865,170 subscription receipts (“Subscription Receipts”) of APUC at a price of $8.90 per Subscription Receipt, for a subscription price of $70.0 million.
On September 26, 2014, as a result of the Underwriters exercising the Over-Allotment Option, an additional 843,000 Subscription Receipts were issued to Emera at a price of $8.90 per Subscription Receipt, for an aggregate subscription price of $77.5 million.
On December 2, 2014, APUC and Emera entered into an additional subscription agreement to which Emera agreed to subscribe for an aggregate of 3,316,583 Subscription Receipts at a price of $9.95 per Subscription Receipt, for a subscription price of $33.0 million.
The proceeds of the Subscription Receipts private placements are intended to be used to partially finance the acquisitions of the Odell Wind Project and the Park Water Facility (described below).
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2014 Generation Group Highlights
Acquisition of Odell Wind Project
On September 4, 2014, the Generation Group announced an opportunity to acquire an interest in the Odell Wind Project, of Minnesota. The Odell Wind Project is a 200 MW wind development located in Cottonwood, Jackson, Martin, and Watonwan counties in Minnesota and is being constructed on approximately 23,000 acres of leased land. The project will utilize 100 Vestas V110-2.0 wind turbines. Pursuant to a 20-year PPA, all energy, capacity and renewable energy credits from the project will be sold to Northern States Power Company, a subsidiary of Xcel Energy Inc., which is a diversified utility operating in the Midwest U.S. Construction is expected to begin in the second quarter of 2015, with total costs estimated at U.S. $322.8 million. It is anticipated that the Odell Project will qualify for U.S. federal production tax credits having satisfied the Internal Revenue Service 5% beginning of construction investment safe-harbor guidance. Accordingly, approximately 60% of the permanent project financing is expected to be funded by tax equity investors.
The Generation Group's participation in the project will be via a 50% equity interest in a new joint venture with a third party developer. The Company is accounting for the joint venture as an equity method investment since both partners have joint control of the new venture. The Generation Group holds an option to acquire the other 50% interest on commencement of operations, which is expected in late 2015 or early 2016.
Completion of Cornwall Solar Project
During the quarter ended March 31, 2014, the Generation Group completed the construction of its 10 MWac solar project located near Cornwall, Ontario. The facility reached commercial operation on March 27, 2014 for a total capital cost of approximately $47.6 million. The facility represents the first solar project in the Generation Group’s portfolio. The facility is expected to generate approximately 14,400 MW-hrs of electricity annually with the power sold under a 20 year FIT PPA with the Ontario Power Authority.
Completion of St. Damase Wind Project
On December 2, 2014, the first phase of the wind facility located in the local municipality of St. Damase reached commercial operations. The 24 MW facility is expected to generate 76,900 MW-hrs of electricity annually with the power sold under a 20 year PPA with Hydro Quebec.
It is expected that the turbines and other components utilized in the first 24 MW phase of the St. Damase Wind Project will qualify as Canadian Renewable and Conservation Expense ("CRCE"), and therefore a significant portion of the Phase I capital cost will be eligible for a refundable Quebec tax credit ("Quebec CRCE Tax Credit"). The estimated value of the Quebec CRCE tax credit for the St. Damase project is expected to be approximately $16.6 million. Phase II of the project will be constructed following evaluation of the wind resource at the site, completion of satisfactory permitting, and entering into appropriate energy sales arrangements.
Significant Progress on Power Development Projects
During 2014, the Generation Group made significant progress advancing several of its development projects. Construction on the Bakersfield I Solar Project near Bakersfield, California began in the second quarter of 2014 and was placed in service on December 30, 2014. Final construction efforts continue with the project expected to reach full commercial operations in the first quarter of 2015.
Construction of the Morse Wind Project near Morse, Saskatchewan is in its final stages. Installation of access roads and foundations are complete, turbine delivery commenced in January 2015, and seven of ten turbines have been erected. The project is expected to be operational by March 31, 2015.
Expansion of Bakersfield I Solar Project
On November 24, 2014, APUC announced that it intends to proceed with a 10 MW project adjacent to its 20MW Bakersfield I Solar project in Kern County, California, which is currently under construction.
The 10MW Bakersfield II Solar project executed a 20 year PPA on September 22, 2014 with a large California based electric utility. The project will be located on 64 acres of land adjacent to the 20MW Bakersfield I Solar project. Construction of Bakersfield I Solar is nearing completion, with commercial operations expected to occur in the first quarter of 2015.
The total project cost for Bakersfield II Solar of approximately U.S. $27.0 million will be funded with a combination of senior debt, common equity, and contributions from tax equity investors. Consistent with financing structures utilized for U.S. based renewable energy projects including Bakersfield I Solar, it is anticipated that Bakersfield II Solar will source financing in the amount of approximately 40% of the capital costs from certain tax equity investors.
Acquisition of the Remaining 40% of a 400 MW Wind Power Portfolio
On March 31, 2014, the Generation Group acquired from Gamesa Wind US, LLC (“Gamesa”) the remaining 40% of the Class B partnership units of the entity which owns a three facility 400 MW wind power portfolio (the “U.S. Wind Portfolio”)
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in the United States for total consideration of approximately U.S. $115.0 million. As a result of the transaction, the Generation Group now owns 100% of the Class B partnership units of the entity that owns the U.S. Wind Portfolio.
The Generation Group originally acquired 60% of the Class B units of the entity which owns the U.S. Wind Portfolio in 2012. The U.S. Wind Portfolio is a 400 MW wind portfolio consisting of three facilities: Minonk (200MW), Senate (150MW), and Sandy Ridge (50MW) located in the states of Illinois, Texas, and Pennsylvania, respectively. Gamesa will continue to provide operations, warranty and maintenance services for the wind turbines and balance of plant facilities under 20 year contracts.
$200 million Senior Unsecured Debentures
On January 17, 2014, the Generation Group issued $200.0 million 4.65% senior unsecured debentures with a maturity date of February 15, 2022 (the "Generation Group Debentures") pursuant to a private placement in Canada and the United States. The Generation Group Debentures were sold at a price of $99.864 per $100.00 principal amount resulting in an effective yield of 4.67%. Concurrent with the offering, the Generation Group entered into a fixed for fixed cross currency swap, coterminous with the debentures, to economically convert the Canadian dollar denominated debentures into U.S. dollars, resulting in an effective interest rate throughout the term of approximately 4.77%.
Net proceeds were used towards financing the acquisition of the remaining 40% ownership interest in its U.S. Wind Portfolio, to reduce amounts outstanding on project debt related to its Shady Oaks Wind Facility, to reduce amounts outstanding under the Generation Group's senior unsecured revolving credit facility ("Generation Credit Facility"), and for general corporate purposes.
Additional Liquidity
On July 31, 2014, the Generation Group increased the credit available under the Generation Credit Facility to $350 million from $200 million. The larger credit facility will be used to provide additional liquidity in support of the group's $1,225.0 million development portfolio to be completed over the next three years. In addition to the larger size, the maturity of the facility has been extended from three to four years and now extends until July 31, 2018.
2014 Distribution Group Highlights
Agreement to acquire Park Water System
On September 19, 2014, the Distribution Group announced the entering into an agreement with Western Water Holdings, a wholly-owned investment of Carlyle Infrastructure, to acquire the regulated water distribution utility Park Water Company (“Park Water System”). Park Water System owns and operates three regulated water utilities engaged in the production, treatment, storage, distribution, and sale of water in Southern California and Western Montana. The three utilities collectively serve approximately 74,000 customer connections and have more than 1,000 miles of distribution mains.
Total consideration for the utility purchase is expected to be approximately U.S. $327 million, which includes the assumption of approximately U.S. $77 million of existing long-term utility debt. The acquisition will maintain APUC’s strategic business mix and further enhance its investment grade consolidated capital structure.
Acquisition of White Hall Water System
On May 30, 2014, the Distribution Group acquired the assets of the White Hall Water System, a regulated water distribution and wastewater treatment utility located in White Hall, Arkansas. The White Hall Water System serves approximately 1,900 water distribution and 2,400 wastewater treatment customers. Total purchase price for the White Hall Water System assets, adjusted for certain working capital and other closing adjustments, is approximately U.S. $4.5 million.
Acquisition of New Hampshire Gas
On January 2, 2015, the Distribution Group completed the acquisition of New Hampshire Gas, a regulated propane gas distribution utility located in Keene, New Hampshire. The New Hampshire Gas System services approximately 1,200 propane gas distribution customers. Total purchase price for the New Hampshire Gas System is approximately U.S. $3.0 million, subject to certain closing adjustments.
Successful Rate Case Outcomes
A core strategy of the Distribution Group is to ensure appropriate return on the rate base at its various utility systems. The group has successfully completed several rate cases throughout 2014, representing a cumulative annual revenue increase of approximately U.S. $29.1 million. The full annualized impact of these rate cases will be realized in 2015. Further detail on the various regulatory proceedings of the Distribution Group can be found under Regulatory Proceedings.
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2014 Transmission Group Highlights
Agreement to acquire interest in Natural Gas Transmission Pipeline
On November 24, 2014, APUC announced its agreement to participate in a natural gas pipeline transmission project in partnership with Kinder Morgan, Inc. Specifically, Kinder Morgan Operating L.P. “A,” a wholly owned subsidiary of Kinder Morgan, Inc., and Liberty Utilities (Pipeline & Transmission) Corp., a wholly owned subsidiary of APUC, have agreed to form a new entity ("Northeast Expansion LLC") to undertake the development, construction and ownership of a 30-inch or 36-inch natural gas transmission pipeline to be located between Wright, New York and Dracut, Massachusetts(the “Project”), which will be operated by Tennessee Gas Pipeline Company, L.L.C. (“Tennessee”) . The Project is scalable up to 2.2 billion cubic feet per day (Bcf/d), and the pipeline capacity will be contracted with local distribution utilities, and other customers, to help ease constraints on natural gas supply in the northeast U.S. and help ensure much needed reliability to the power-generation grid. It is anticipated that Tennessee will receive a FERC certificate in the fourth quarter of 2016, with commercial operations occurring by late 2018.
Under the agreement, APUC will initially subscribe for a 2.5% interest in Northeast Expansion LLC with an opportunity to increase its participation up to 10%. The total capital investment opportunity for APUC could be up to U.S. $400 million, depending on the final pipeline configuration and design capacity.
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2014 Annual Results From Operations
As outlined, APUC has continued to advance growth initiatives throughout 2014 that had a positive contribution to the annual results. In addition, the results now reflect full year operations from the gas and water systems acquisitions completed by the Distribution Group in 2013.
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Key Selected Annual Financial Information | | Year ended December 31 |
| (all dollar amounts in $ millions except per share information) | | 2014 | | 2013 | | 2012 |
| Revenue | | $ | 943.6 |
| | $ | 675.3 |
| | $ | 348.8 |
|
Adjusted EBITDA 1 | | 290.6 |
|
| 228.1 |
| | 88.1 |
|
| Cash provided by operating activities | | 192.7 |
| | 98.9 |
| | 63.0 |
|
Adjusted funds from operations1 | | 206.5 |
|
| 154.9 |
| | 66.8 |
|
| Net earnings attributable to Shareholders from continuing operations | | 77.8 |
|
| 62.3 |
| | 13.5 |
|
| Net earnings attributable to Shareholders | | 75.7 |
| | 20.3 |
| | 14.5 |
|
Adjusted net earnings 1 | | 88.4 |
|
| 59.5 |
| | 18.9 |
|
| Dividends declared to Common Shareholders | | 82.9 |
|
| 68.3 |
| | 50.2 |
|
| Weighted Average number of common shares outstanding | | 213,953,870 |
|
| 204,350,689 |
| | 158,304,340 |
|
| Per share | | | | | | |
| Basic net earnings from continuing operations | | $ | 0.32 |
|
| $ | 0.28 |
| | $ | 0.08 |
|
| Basic net earnings | | $ | 0.31 |
| | $ | 0.07 |
| | $ | 0.09 |
|
Adjusted net earnings 1, 2 | | $ | 0.37 |
|
| $ | 0.26 |
| | $ | 0.11 |
|
| Diluted net earnings | | $ | 0.31 |
| | $ | 0.07 |
| | $ | 0.09 |
|
Cash provided by operating activities 1, 2 | | $ | 0.90 |
| | $ | 0.48 |
| | $ | 0.40 |
|
Adjusted funds from operations1, 2 | | $ | 0.92 |
|
| $ | 0.73 |
| | $ | 0.42 |
|
| Dividends declared to Common Shareholders | | $ | 0.37 |
|
| $ | 0.33 |
| | $ | 0.30 |
|
| Total assets | | 4,113.7 |
| | 3,476.5 |
| | 2,779.0 |
|
Long term liabilities 3 | | 1,280.0 |
| | 1,255.6 |
| | 770.8 |
|
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| 1 | Non-GAAP Financial Measures |
| 2 | APUC uses per share adjusted net earnings, cash provided by operating activities and adjusted funds from operations to enhance assessment and understanding of the performance of APUC. |
| 3 | Includes long-term liabilities and current portion of long-term liabilities |
For the year ended December 31, 2014, APUC experienced an average U.S. exchange rate of approximately $1.1049 as compared to $1.0300 in the same period in 2013. 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 Canadian dollar reporting currency.
For the year ended December 31, 2014, APUC reported total revenue of $943.6 million as compared to $675.3 million during the same period in 2013, an increase of $268.3 million or 39.7%. The major factors resulting in the increase in APUC revenue for the year ended December 31, 2014 as compared to the corresponding period in 2013 are set out as follows:
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| (all dollar amounts in $ millions) | Year to date December 31, 2014 |
| Comparative Prior Period Revenue | $ | 675.3 |
|
| Significant Changes: | |
| Generation Group | |
| Renewable: | |
| Increased wind resources net of hedge settlements at the Minonk, Senate, and Sandy Ridge Wind Facilities | 1.1 |
|
| Higher realized prices from Renewable Energy Credits generated from the U.S. Wind Facilities | 4.8 |
|
| Start of commercial operations of the Cornwall Solar Facility | 5.5 |
|
| Increased customer load in the Maritime region | 1.7 |
|
| Thermal: | |
| Increased average prices at the Windsor Locks and Sanger Thermal Facilities | 5.3 |
|
| Increased sale of Renewable Energy Credits generated at the Windsor Locks Thermal Facility | 0.7 |
|
| Distribution Group | |
| Natural Gas Systems - Increased revenue due to acquisition of the Peach State Gas System (U.S. $32.9 million), and the New England Gas System (U.S. $76.3 million) | 108.2 |
|
| Natural Gas Systems - Revenue increase due to higher customer demand as a result of colder than average weather at the EnergyNorth and Midstates Natural Gas Systems | 35.2 |
|
| Electric Systems - Revenue increase at the electric systems predominantly due to higher customer demand at the Granite State Electric System | 13.8 |
|
| Rate Cases – Revenue increase due to higher electricity rates at the Granite State Electric System (U.S. $11.8 million) and Peach State Gas System (U.S. $5.5 million) | 17.2 |
|
| Water and Waste Systems – Revenue increase due to the increased customer demand | 3.5 |
|
| Increase due to acquisition of New England Gas System's water heater rental service (U.S. $2.8 million) and increased revenues at Peach State Gas System's Fort Benning operation (U.S. $1.0 million) | 3.8 |
|
| Impact of the stronger U.S. dollar | 68.4 |
|
| Other | (0.9 | ) |
| Current Period Revenue | $ | 943.6 |
|
A more detailed discussion of these factors is presented within the business unit analysis.
Adjusted EBITDA in the year ended December 31, 2014 totalled $290.6 million as compared to $228.1 million during the same period in 2013, an increase of $62.5 million or 27.4%. The increase in Adjusted EBITDA was primarily due to acquisitions completed in 2014 and 2013, impact of rate case settlements, increased customer demand for Gas distribution, and the increase in REC transactions. 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 year ended December 31, 2014, net earnings from continuing operations attributable to Shareholders totalled $77.8 million as compared to $62.3 million during the same period in 2013, an increase of $15.5 million. The increase was due to $63.7 million in increased earnings from operating facilities, $0.5 million in increased foreign exchange gains, and $1.2 million due to a gain on sale of assets, as compared to the same period in 2013. These items were partially offset by $18.0 million in increased depreciation and amortization expenses, $11.2 million in increased administration charges, $9.0 million in increased interest expense, $0.4 million in increased acquisition costs, $8.5 million in increased write-downs on notes receivable and property, plant, and equipment, $6.6 million in increased loss from derivative instruments, $11.4 million in increased allocations of earnings to non-controlling interests, and $7.7 million in increased income tax expense (tax explanations are discussed in APUC: Corporate and Other Expenses), as compared to the same period in 2013.
For the year ended December 31, 2014, net earnings (including discontinued operations) attributable to Shareholders totalled $75.7 million as compared to $20.3 million during the same period in 2013, an increase of $55.4 million. Net earnings per share totalled $0.31 for the year ended December 31, 2014, as compared to $0.07 during the same period in 2013.
|
| |
| 2014 Annual Report | 9 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
During the year ended December 31, 2014, cash provided by operating activities totalled $192.7 million or $0.90 per share as compared to cash provided by operating activities of $98.9 million, or $0.48 per share during the same period in 2013. During the year ended December 31, 2014, adjusted funds from operations, a non-GAAP measure, totalled $206.5 million or $0.92 per share as compared to adjusted funds from operations of $154.9 million, or $0.73 per share during the same period in 2013, an increase of $51.6 million.
Cash per share provided by operating activities and per share adjusted funds from operations are non-GAAP measures. Per share cash provided by operating activities and per share adjusted funds from operations are not substitute measures of performance for earnings per share. Amounts represented by per share cash provided by operating activities and per share adjusted funds from operations do not represent amounts available for distribution to shareholders and should be considered in light of various charges and claims against APUC.
2014 Fourth Quarter Results From Operations
|
| | | | | | | | |
Key Selected Fourth Quarter Financial Information | | Three months ended December 31 |
| (all dollar amounts in $ millions except per share information) | | 2014 | | 2013 |
| Revenue | | $ | 259.3 |
| | $ | 205.3 |
|
Adjusted EBITDA 1 | | 84.3 |
|
| 68.5 |
|
| Cash provided by operating activities | | 96.5 |
| | 28.4 |
|
Adjusted funds from operations1 | | 65.9 |
|
| 46.0 |
|
| Net earnings attributable to Shareholders from continuing operations | | 33.1 |
|
| 19.8 |
|
| Net earnings attributable to Shareholders | | 31.6 |
| | 13.2 |
|
Adjusted net earnings1 | | 35.2 |
|
| 18.8 |
|
| Dividends declared to Common Shareholders | | 25.4 |
|
| 17.6 |
|
| Weighted Average number of common shares outstanding | | 230,664,583 |
|
| 206,219,121 |
|
| Per share | | | | |
| Basic net earnings/(loss) from continuing operations | | $ | 0.13 |
|
| $ | 0.09 |
|
| Basic net earnings/(loss) | | $ | 0.13 |
| | $ | 0.06 |
|
Adjusted net earnings1, 2, | | $ | 0.14 |
|
| $ | 0.08 |
|
| Diluted net earnings/(loss) | | $ | 0.12 |
| | $ | 0.06 |
|
Cash provided by operating activities 1, 2, | | $ | 0.42 |
| | $ | 0.14 |
|
Adjusted funds from operations1, 2 | | $ | 0.27 |
|
| $ | 0.22 |
|
| Dividends declared to Common Shareholders | | $ | 0.10 |
|
| $ | 0.09 |
|
|
| |
| 1 | Non-GAAP Financial Measures |
| 2 | APUC uses per share adjusted net earnings, cash provided by operating activities and adjusted funds from operations to enhance assessment and understanding of the performance of APUC. |
For the three months ended December 31, 2014, APUC experienced an average U.S. exchange rate of approximately $1.136 as compared to $1.050 in the same period in 2013. As such, any quarter over quarter 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.
For the three months ended December 31, 2014, APUC reported total revenue of $259.3 million as compared to $205.3 million during the same period in 2013, an increase of $54.0 million. The major factors resulting in the increase in APUC revenue in the three months ended December 31, 2014 as compared to the corresponding period in 2013 are set out as follows:
|
| |
| 2014 Annual Report | 10 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
|
| | | |
| (all dollar amounts in $ millions) | Quarter ended December 31, 2014 |
| Comparative Prior Period Revenue | $ | 205.3 |
|
| Significant Changes: | |
| Generation Group | |
| Renewable: | |
| Effect of hydrology resource compared to comparable period in prior year | 1.6 |
|
| Increased wind resources net of hedge settlements at the Minonk, Senate, and Sandy Ridge Wind Facilities | 1.2 |
|
| Higher realized prices from Renewable Energy Credits generated from the U.S. Wind Facilities | 1.1 |
|
| Start of commercial operations of the Cornwall Solar Facility | 0.7 |
|
| Decreased sales due to reduced retail customer load at the Maritime region | (0.9 | ) |
| Distribution Group | |
| Increased revenue due to acquisition of the New England Gas System | 10.5 |
|
| Electric Systems - Revenue increase at the electric systems predominantly due to higher customer demand at the Granite State Electric System | 4.3 |
|
| Natural Gas Systems - Revenue increase due to higher customer demand as a result of colder than average weather at the EnergyNorth, Midstates, and Peach State Natural Gas Systems | 8.5 |
|
| Rate Cases – Revenue increase due to higher electricity rates at the Granite State Electric System (U.S. $1.6 million) and Peach State Gas System (U.S. $2.2 million) | 3.8 |
|
| Water and Waste Systems – Revenue increase due to the increased customer demand | 1.1 |
|
| Increase due to acquisition of New England Gas System's water heater rental service (U.S. $0.8 million) and increased revenues at Peach State Gas System's Fort Benning operation (U.S. $1.0 million) | 1.8 |
|
| Impact of the stronger U.S. dollar | 21.2 |
|
| Other | (0.9 | ) |
| Current Period Revenue | $ | 259.3 |
|
A more detailed discussion of these factors is presented within the business unit analysis.
Adjusted EBITDA in the three months ended December 31, 2014 totalled $84.3 million as compared to $68.5 million during the same period in 2013, an increase of $15.8 million or 23.1%. The increase in Adjusted EBITDA was primarily due to acquisitions completed in December 2013, impact of rate case settlements, increased hydrology and wind resources, and increase customer demand at the EnergyNorth and Midstates Gas Systems. 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 December 31, 2014, net earnings attributable to Shareholders from continued operations totalled $33.1 million as compared to $19.8 million during the same period in 2013, an increase of $13.3 million. The increase was due to $20.3 million in increased earnings from operating facilities, $1.5 million in decreased income tax expense (tax explanations are discussed in APUC: Corporate and Other Expenses), $0.3 million in decreased interest expense, $0.7 million due to a gain on sale of assets, and $4.9 million in increased allocation of earnings to non-controlling interests, as compared to the same period in 2013. These items were partially offset by $2.1 million in increased depreciation and amortization expenses, $5.4 million in increased administration charges, $0.4 million in decreased foreign exchange gains, $0.5 million in decreased interest and dividend income, $1.0 million in increased acquisition costs, $0.3 million in increased write-downs on notes receivable and property, plant, and equipment, and $4.7 million in decreased gains from derivative instruments.
For the three months ended December 31, 2014, net earnings (including discontinued operations) attributable to Shareholders totalled $31.6 million as compared to net earnings attributable to Shareholders of $13.2 million during the same period in 2013, an increase of $18.4 million. Net earnings per share totalled $0.13 for the three months ended December 31, 2014, as compared to net earnings per share of $0.06 during the same period in 2013.
|
| |
| 2014 Annual Report | 11 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
During the three months ended December 31, 2014, cash provided by operating activities totalled $96.5 million or $0.42 per share as compared to cash provided by operating activities of $28.4 million, or $0.14 per share during the same period in 2013. During the three months ended December 31, 2014, adjusted funds from operations totalled $65.9 million or $0.27 per share as compared to adjusted funds from operations of $46.0 million, or $0.22 per share during the same period in 2013. The change in adjusted funds from operations in the three months ended December 31, 2014, is primarily due to increased earnings from operations, as compared to the same period in 2013.
Cash per share provided by operating activities and per share adjusted funds from operations are non-GAAP measures. Per share cash provided by operating activities and per share adjusted funds from operations are not substitute measures of performance for earnings per share. Amounts represented by per share cash provided by operating activities and per share adjusted funds from operations do not represent amounts available for distribution to shareholders and should be considered in light of various charges and claims against APUC.
GENERATION BUSINESS GROUP
|
| | | | | | | | | | | | | | | | | | |
| Renewable Energy Division | | | | Three months ended December 31 | | | | Year ended December 31 |
| | | Long Term Average Resource | | 2014 | | 2013 | | Long Term Average Resource | | 2014 | | 2013 |
| Performance (GW-hrs sold) | | | | | | | | | | | | |
| Hydro Facilities: | | | | | | | | | | | | |
| Maritime Region | | 45.8 |
| | 38.0 |
| | 37.9 |
| | 177.8 |
| | 146.2 |
| | 203.1 |
|
Quebec Region1 | | 72.8 |
| | 72.3 |
| | 68.1 |
| | 274.9 |
| | 259.4 |
| | 277.7 |
|
Ontario Region2 | | 33.8 |
| | 38.7 |
| | 39.3 |
| | 139.8 |
| | 144.5 |
| | 90.4 |
|
| Western Region | | 12.6 |
| | 13.4 |
| | 12.1 |
| | 65.0 |
| | 74.1 |
| | 66.6 |
|
| | 165.0 |
| | 162.4 |
|
| 157.4 |
| | 657.5 |
| | 624.2 |
| | 637.8 |
|
| Wind Facilities: | | | | | | | | | | | | |
St. Damase3 | | 6.7 |
| | 4.7 |
| | — |
| | 6.7 |
| | 4.7 |
| | — |
|
| St. Leon | | 121.4 |
| | 119.9 |
| | 116.5 |
| | 430.2 |
| | 441.4 |
| | 398.0 |
|
Red Lily4 | | 24.1 |
| | 23.8 |
| | 22.8 |
| | 88.5 |
| | 87.7 |
| | 79.0 |
|
| Sandy Ridge | | 43.6 |
| | 46.7 |
| | 38.7 |
| | 158.3 |
| | 149.0 |
| | 138.7 |
|
| Minonk | | 195.8 |
| | 195.4 |
| | 182.8 |
| | 673.3 |
| | 648.5 |
| | 621.8 |
|
| Senate | | 140.0 |
| | 139.0 |
| | 133.8 |
| | 520.4 |
| | 537.6 |
| | 524.5 |
|
| Shady Oaks | | 100.4 |
| | 92.2 |
| | 88.7 |
| | 364.0 |
| | 339.9 |
| | 317.1 |
|
| | 632.0 |
|
| 621.7 |
|
| 583.3 |
|
| 2,241.4 |
|
| 2,208.8 |
|
| 2,079.1 |
|
| Solar Facilities: | | | | | | | | | | | | |
| Cornwall | | 2.2 |
| | 1.8 |
| | — |
| | 11.8 |
| | 12.8 |
| | — |
|
| Total Performance | | 799.2 |
| | 785.9 |
| | 740.7 |
|
| 2,910.7 |
|
| 2,845.8 |
|
| 2,716.9 |
|
|
| |
| 1 | The Generation Group's Donnacona Hydro Facility was offline during the second half of 2014. Insurance proceeds were received to compensate for lost revenue. |
| 2 | The Generation Group's Long Sault hydro facility was offline during most of the first nine months of 2013. Insurance proceeds were received to compensate for lost revenue. |
| 3 | The St Damase Wind Facility achieved commercial operation on December 2, 2014. Long term average resource and production represent production from December 2 to December 31, 2014. |
| 4 | APUC does not consolidate the operating results from this facility in its financial statements. Production from the facility is included as APUC manages the facility under contract and has an option to acquire a 75% equity interest in the facility in 2016. |
|
| |
| 2014 Annual Report | 12 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
For the twelve months ended December 31, 2014, the Renewable Energy Division generated 2,845.8 GW-hrs of electricity. This level of production represents sufficient energy to supply the equivalent of 210,800 homes on an annualized basis with renewable power. As a result of renewable energy production, the equivalent of 2,086,900 tons of CO2 gas was prevented from entering the atmosphere.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Three months ended December 31 | | | | Year ended December 31 |
| (all dollar amounts in $ millions) | | 2014 | | 2013 | | | | 2014 |
| 2013 |
Revenue1 | | | | | | | | | | |
| Hydro Sales | | $ | 16.8 |
| | $ | 15.9 |
| | | | $ | 65.1 |
| | $ | 61.9 |
|
| Wind | | 26.9 |
| | 24.5 |
| | | | 88.8 |
| | 83.8 |
|
| Solar | | 0.7 |
| | — |
| | | | 5.5 |
| | — |
|
| Total Revenue | | $ | 44.4 |
| | $ | 40.4 |
| — |
|
| — |
| $ | 159.4 |
| — |
| $ | 145.7 |
|
| | | | | | | | | | |
| Less: | | | | | | | | | | |
Cost of Sales - Energy2 | | (1.5 | ) | | (3.8 | ) | | | | (16.7 | ) |
| (8.7 | ) |
Realized gain/(loss) on hedges3 | | (0.2 | ) | | 0.3 |
| | | | 3.6 |
| | 0.5 |
|
| Net Energy Sales | | $ | 42.7 |
| | $ | 36.9 |
| | | | $ | 146.3 |
| | $ | 137.5 |
|
| | | | | | | | | | |
Renewable Energy Credits ("REC")4 | | 4.0 |
| | 2.6 |
| | | | 11.7 |
|
| 5.9 |
|
| Other Revenue | | 0.4 |
| | 0.2 |
| | | | 1.6 |
|
| 1.2 |
|
| Total Net Revenue | | $ | 47.1 |
| | $ | 39.7 |
| | | | $ | 159.6 |
| | $ | 144.6 |
|
| | | | | | | | | | |
| Expenses & Other Income | | | | | | | | | | |
| Operating expenses | | (11.0 | ) | | (11.2 | ) | | | | (46.1 | ) | | (40.3 | ) |
| Interest and Other income | | 0.4 |
| | 0.5 |
| | | | 1.7 |
|
|
| 1.9 |
|
| HLBV income/(loss) | | 8.9 |
| | 6.8 |
| | | | 27.2 |
| | 20.4 |
|
| Divisional operating profit | | $ | 45.4 |
| 45.4 |
| $ | 35.8 |
| — |
| | — |
| $ | 142.4 |
| — |
| $ | 126.6 |
|
|
| |
| 1 | While most of the Generation Group's PPAs include annual rate increases, a change to the weighted average production levels resulting in higher average production from facilities that 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. |
| 2 | Cost of Sales - Energy consists of energy purchases in the Maritime Region to manage the energy sales from the Tinker Facility which is sold to retail and industrial customers under multi-year contracts. |
| 3 | See financial statements note 25(b)(iv). |
| 4 | Qualifying renewable energy projects receive Renewable Energy Credits (RECs) for the generation and delivery of renewable energy to the power grid. The energy credit certificates represent proof that 1 MW of electricity was generated from an eligible energy source. The RECs can be traded and the owner of the REC can claim to have purchases of renewable energy. REC revenue is recognized only at the time a generated REC unit is matched up with a previously signed REC sales contract with a third party. Generated REC units not immediately available to match against a signed contract are recorded as inventory with the offset recorded as a decrease in operating expenses. |
2014 Fourth Quarter Operating Results
For the three months ended December 31, 2014, the hydro facilities generated 162.4 GW-hrs of electricity, as compared to 157.4 GW-hrs produced in the same period in 2013, an increase of 3.2%. The increased generation is largely attributable to significantly better hydrology in Quebec that more than offset the Donnacona Hydro Facility being offline throughout the quarter. See the "Quebec Dam Safety Act" section for a further discussion on the Donnacona Hydro Facility.
During the three months ended December 31, 2014, the hydro facilities generated electricity equal to 98.4% of long-term projected average resources as compared to 95.2% during the same period in 2013. During the three months ended December 31, 2014, the Ontario and Western Hydro regions achieved production greater than their long-term averages. The Quebec region was below the long term average due to Donnacona being offline. Excluding Donnacona, the Quebec region would have achieved 108% of the LTAR.
|
| |
| 2014 Annual Report | 13 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
For the three months ended December 31, 2014, revenue from the hydro facilities totalled $16.8 million as compared to $15.9 million during the same period in 2013, an increase of $0.9 million. Revenue from generation at the hydro facilities located in the Quebec region increased by $1.4 million, as compared to the same period in 2013. The increase is attributed to more favorable hydrology in the Quebec region. This was offset by decreased revenues in the Maritime region of $0.7 million, primarily due to decreased customer load served. Revenue in the Maritime region primarily consists of the sale of the off-take from the Tinker Hydro Facility through wholesale deliveries to local electric utilities, retail sales to commercial and industrial customers in Northern Maine, merchant sales of production in excess of committed customer deliveries from the Tinker Hydro Facility, and other revenue.
For the three months ended December 31, 2014, energy purchase costs at the Maritime region totalled $1.5 million, as compared to $3.8 million during the same period in 2013, a decrease of $2.3 million. The decrease in the energy purchase costs for the three months ended December 31, 2014 were primarily due to decreased retail customer load served in the quarter requiring reduced energy purchases from the market as the Maritime region was able to generate sufficient energy to meet its retail demand. During this period, approximately 21.4 GW-hrs of energy was purchased at market and fixed rates averaging U.S. $61 per MW-hr.
During the three months ended December 31, 2014, the Maritime region generated approximately 69% of the load required to service its customers, as compared to 44% in the same period in 2013. To mitigate the risk of higher average energy prices, certain power hedges are entered into as part of risk mitigation strategies. For the three months ended December 31, 2014, $0.2 million was realized in connection with these hedges and is recorded as a realized gain on derivative financial instruments in the financial statements.
For the three months ended December 31, 2014, the wind facilities produced 621.7 GW-hrs of electricity, as compared to 583.3 GW-hrs produced in the same period in 2013, an increase of 6.6%. The higher generation was a result of increased wind resources at all sites and the start of production at the newest facility, the St. Damase Wind Facility, which achieved COD on December 2, 2014. The St. Damase wind facility generated 4.7 GW-hrs.
During the three months ended December 31, 2014, the wind facilities (excluding the St. Damase Wind Facility) generated electricity equal to 98.4% of long-term projected average resources, as compared to 93.3% during the same period in 2013, due to variability in the wind resource.
For the three months ended December 31, 2014, revenue from the wind facilities totalled $26.9 million as compared to $24.5 million during the same period in 2013, an increase of $2.4 million. Revenue increases were evident at all wind facilities due mainly to the 38.4 GW/h increase in production due to an increase in wind resources, as compared to the same period last year. As a result, revenues from the Generation Group’s Canadian wind facilities increased $0.8 million, while the U.S. wind facilities increased $1.9 million, as compared to the same period last year. These gains were partly offset by $0.3 million in hedge settlements under the Minonk, Senate and Sandy Ridge Wind Facilities' power hedges.
For the three months ended December 31, 2014, REC revenue totalled $4.0 million, as compared to $2.6 million in the same period in 2013, an increase of $1.4 million, primarily attributed to increased market pricing in all regions with the PJM region having the largest impact. The increase in market pricing is largely caused by the annually increasing renewable requirement of the RPS (Renewable Portfolio Standard) outpacing the increase in supply of available RECs. REC units are generated at a ratio of one REC unit per one MW-hr generated and are sold in the market in which the REC is generated. For the three months ended December 31, 2014, REC units and related revenues were generated at the Sandy Ridge, Minonk, Senate, and Shady Oaks Wind Facilities.
During the three months ended December 31, 2014, the Generation Group's solar facility located in Ontario had its third full quarter of operations generating 1.8 GW-hrs of electricity, which is equal to 18.2% below long-term average resources. The facility reached commercial operation on March 27, 2014 and has a 20 year FIT PPA with the Ontario Power Authority.
Revenue from generation at the Generation Group’s new solar facility located in Cornwall, Ontario totalled $0.7 million for the period. As commercial operation was achieved late in the first quarter of 2014, there is no comparative data from the previous year.
For the three months ended December 31, 2014, operating expenses excluding energy purchases totalled $11.0 million, as compared to $11.2 million during the same period in 2013, a decrease of $0.2 million. The decrease was primarily attributable to greater inventorying of REC costs at the Senate Wind facility partly offset by operating costs at the new Cornwall Solar Facility.
The Red Lily I Wind Facility located in Saskatchewan produced 23.8 GW-hrs of electricity for the three months ended December 31, 2014. The Generation Group's economic return from its investment in Red Lily currently comes in the form of interest payments, fees and other charges and is not reflected in revenue from energy sales. Under the terms of the agreements, the Generation Group has the right to exchange these contractual and debt interests in the Red Lily I Wind Facility for a direct 75% equity interest in 2016. For the three months ended December 31, 2014, the Generation Group earned fees of $0.3 million (which is classified as other revenue) and interest income of $0.4 million from the Red Lily I Wind Facility.
For the three months ended December 31, 2014, interest and other income totalled $0.4 million, consistent with the same period in 2013. Interest and other income primarily consist of interest related to the senior and subordinated debt interest in Red Lily I Wind Facility. This amount is included as part of the Generation Group’s earnings from its investment in the Red Lily I Wind Facility, as discussed above.
For the three months ended December 31, 2014, the value of net tax attributes generated amounted to an approximate HLBV income of $8.9 million, an increase of $2.1 million compared to the prior year. The increase was attributable to increased production, a stronger U.S. dollar exchange rate, and the reduced economic interest in the projects attributable to tax equity.
For the three months ended December 31, 2014, the Renewable Energy Division’s operating profit totalled $45.4 million, as compared to $35.8 million during the same period in 2013, an increase of $9.6 million; $2.5 million of the increase is attributable to the stronger U.S. dollar.
2014 Twelve Month Operating Results
For the twelve months ended December 31, 2014, the hydro facilities generated 624.2 GW-hrs of electricity, as compared to 637.8 GW-hrs produced in the same period in 2013, a decrease of 2.1%. The slight decrease in generation is largely due to a decrease in production in the Maritime region due to lower hydrology in the first 3 quarters of the year, almost completely offset by an increased production in the Ontario region with the Long Sault facility return to service, which was offline for the majority of the first and second quarter of 2013.
During the twelve months ended December 31, 2014, the hydro facilities generated electricity equal to 94.9% of long-term projected average resources, as compared to 103.4% during the same period in 2013. During the twelve months ended December 31, 2014, the Ontario and Western Hydro regions achieved production above their long-term averages. The Quebec and Maritime regions were below the long term average production. Had the Quebec region's Donnacona facility been on line, the region would have achieved 102% of the long term average hydrological resource.
For the twelve months ended December 31, 2014, revenue from the hydro facilities totalled $65.1 million, as compared to $61.9 million during the same period in 2013, an increase of $3.2 million. Revenue from generation in the Ontario region increased by $0.7 million due to the Long Sault Hydro Facility being back on-line for the full year 2014. The Quebec and Western regions experienced a decrease of $0.3 million and $0.7 million, respectively. The decrease in the Quebec region is primarily due to the Donnacona Hydro Facility being offline, while the decrease in the Western region is primarily due to lower market pricing on the unhedged portion of the production. The increase in production at the Western region caused the market exposed production amount to increase 8% while the weighted average market price fell by more than 50%. Revenue from the Maritime region increased $3.5 million, primarily due to increased retail customer load served.
For the twelve months ended December 31, 2014, energy purchases totalled $16.7 million, as compared to $8.7 million during the same period in 2013, an increase of $8.0 million. Increased energy purchase costs for the twelve months ended December 31, 2014 were primarily due to lower hydrology in the Maritime region in the first half of the year, which required increased energy purchases from external suppliers at higher average prices. During this period, purchases of approximately 166.0 GW-hrs of energy at market and fixed rates averaging U.S. $91 per MW-hr were made. During the twelve months ended December 31, 2014, the Maritime region generated approximately 46% of the load required to service its customers, as compared to 67% in the same period in 2013. To mitigate the risk of higher average energy prices, the Maritime region had previously entered into certain power hedges as part of its risk mitigation strategies. For the twelve months ended December
|
| |
| 2014 Annual Report | 14 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
31, 2014, $3.6 million was realized in connection with these hedges and is recorded as a realized gain on derivative financial instruments on the Consolidated Statement of Operations.
For the twelve months ended December 31, 2014, the wind facilities produced 2,208.8 GW-hrs of electricity, as compared to 2,079.1 GW-hrs produced in the same period in 2013, an increase of 6.2%. The increased generation was a result of stronger wind resources at the St. Leon, Minonk, Sandy Ridge, and Senate Wind Facility along with the St. Damase Wind Facility which achieved COD on December 2, 2014.
During the twelve months ended December 31, 2014, the wind facilities generated electricity equal to 98.5% of long-term projected average resources, as compared to 93.1% during the same period in 2013. For the twelve months ended December 31, 2014, revenue from the wind facilities totalled $88.8 million, as compared to $83.8 million during the same period in 2013, an increase of $5.0 million. The increase in revenue was due primarily to a 129.7 GW/h increase in production from stronger wind resources, as compared to the same period last year. As a result, revenues from the Generation Group’s Canadian wind facilities increased $3.5 million, while the U.S. wind facilities increased $1.5 million, net of hedge settlements under the Minonk, Senate and Sandy Ridge Wind Facilities' power hedges.
For the twelve months ended December 31, 2014, REC revenue totalled $11.7 million, as compared to $5.9 million in the same period in 2013, an increase of $5.8 million, primarily a result of increased market pricing and a greater number of RECs generated and sold. REC units are generated at a ratio of one REC unit per one MW-hr generated and are sold in the market in which the REC is generated. For the twelve months ended December 31, 2014, REC units and related revenues were generated at the Sandy Ridge, Minonk, Senate, and Shady Oaks Wind Facilities.
During the twelve months ended December 31, 2014, the Generation Group's solar facility located in Ontario generated 12.8 GW-hrs of electricity, which is equal to 8.5% above long-term average resources from the commercial operation date. The facility reached commercial operation on March 27, 2014 and has a 20 year FIT PPA with the Ontario Power Authority.
Revenue from generation totalled $5.5 million for the period. The facility achieved commercial operation on March 27, 2014 and therefore there is no comparative data from the previous year.
For the twelve months ended December 31, 2014, operating expenses excluding energy purchases totalled $46.1 million, as compared to $40.3 million during the same period in 2013, an increase of $5.8 million. The increase was due to the appreciation of the U.S. dollar, operating costs for Cornwall's first year of operations, and cost of RECs contracted in the first quarter of 2014 but produced in the fourth quarter of 2013.
For the twelve months ended December 31, 2014, interest and other income totalled $1.7 million, as compared to $1.9 million during the same period in 2013. Interest and other income primarily consist of interest related to the senior and subordinated debt interest in Red Lily I Wind Facility. This amount is included as part of the Generation Group’s earnings from its investment in Red Lily I Wind Facility, as discussed below.
The Red Lily I Wind Facility located in Saskatchewan produced 87.7 GW-hrs of electricity for the twelve months ended December 31, 2014. The Generation Group's economic return from its investment in Red Lily currently comes in the form of interest payments, fees and other charges and is not reflected in revenue from energy sales. Under the terms of the agreements, the Generation Group has the right to exchange these contractual and debt interests in the Red Lily I Wind Facility for a direct 75% equity interest in 2016. For the twelve months ended December 31, 2014, the Generation Group earned fees of $1.3 million (which is classified as other revenue) and interest income of $1.6 million from the Red Lily I Wind Facility.
Hypothetical Liquidation at Book Value (“HLBV”) income represents the value of net tax attributes, primarily related to electricity production generated by the Generation Group in the period from certain of its U.S. wind power generation facilities. The value of net tax attributes generated in the twelve months ended December 31, 2014 amounted to an approximate HLBV income of $27.2 million, as compared to $20.4 million in the prior year. The increase of $6.8 million was primarily a result of a stronger U.S. dollar exchange rate, increased production at all U.S. sites, and a higher income allocation to the Generation Group due to the reduced economic interest of Tax Equity investors in the projects.
For the twelve months ended December 31, 2014, the Renewable Energy Division’s operating profit totalled $142.4 million, as compared to $126.6 million during the same period in 2013, an increase of $15.8 million; $3.5 million of the increase is attributable to the stronger U.S. dollar.
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| 2014 Annual Report | 15 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
GENERATION BUSINESS GROUP
|
| | | | | | | | | | | | | | | | | | | |
| Thermal Energy Division | Three months ended December 31, 2014 |
| Three months ended December 31, 2013 |
| Windsor Locks | Sanger | Total |
| Windsor Locks | Sanger | Total |
Performance (GW-hrs sold) | 26.3 |
| 35.1 |
| 61.4 |
|
| 28.8 |
| 35.6 |
| 64.4 |
|
Performance (steam sales – billion lbs) | 157.3 |
| — |
| 157.3 |
|
| 161.3 |
| — |
| 161.3 |
|
| | | | | | | | |
| (all dollar amounts in $ millions) | | | | | | | |
| Revenue | | | | | | | |
| Energy/steam sales | $ | 4.7 |
| $ | 4.3 |
| $ | 9.0 |
| | $ | 4.6 |
| $ | 3.9 |
| $ | 8.5 |
|
| Less: | | | | | | | |
| Cost of Sales – Fuel | (3.1 | ) | (1.9 | ) | (5.0 | ) | | (3.1 | ) | (1.5 | ) | (4.6 | ) |
| Net Energy/Steam Sales | $ | 1.6 |
| $ | 2.4 |
| $ | 4.0 |
| | $ | 1.5 |
| $ | 2.4 |
| $ | 3.9 |
|
| Other Revenue | 0.1 |
| 0.6 |
| 0.7 |
| | 0.2 |
| 0.6 |
| 0.8 |
|
| Total Net Revenue | $ | 1.7 |
| $ | 3.0 |
| $ | 4.7 |
| | $ | 1.7 |
| $ | 3.0 |
| $ | 4.7 |
|
| Expenses | | | | | | | |
| Operating Expenses | $ | (0.7 | ) | $ | (1.3 | ) | $ | (2.0 | ) | | $ | (0.9 | ) | $ | (1.2 | ) | $ | (2.1 | ) |
| Facility operating profit | $ | 1.0 |
| $ | 1.7 |
| $ | 2.7 |
| | $ | 0.8 |
| $ | 1.8 |
| $ | 2.6 |
|
| Interest and other income | | | (0.3 | ) | | | | 0.1 |
|
| Divisional operating profit | | | $ | 2.4 |
| | | | $ | 2.7 |
|
2014 Fourth Quarter Operating Results
The Generation Group’s Sanger and Windsor Locks Thermal Facilities purchase natural gas from different suppliers and at prices based on different regional hubs. As a result, the average landed cost per unit of natural gas will differ between the two facilities in the average landed cost for natural gas and may result in the facilities showing differing costs per unit compared to each other and compared to the same period in the prior year. Total natural gas expense will vary based on the volume of natural gas consumed and the average landed cost of natural gas for each MMBTU.
Production data, revenue and expenses have been adjusted to remove the results of the EFW and BCI Thermal Facilities, which were divested on April 4, 2014 for proceeds approximating the carrying value of the net assets on the Consolidated Balance Sheet of the Company as at March 31, 2014. The results of the EFW and BCI Thermal Facilities for the period up to the date of sale are reported as discontinued operations. See Financial Statement note 17 for details.
For the three months ended December 31, 2014, the Thermal Energy Division’s operating profit was $2.4 million, as compared to $2.7 million in the same period in 2013, a decrease of $0.3 million. Operating profit contributions for the three months ended December 31, 2014 were $1.0 million from the Windsor Locks Thermal Facility and $1.7 million from the Sanger Thermal Facility, as compared to $0.8 million and $1.8 million, respectively, during the same period in 2013. Interest and other income for the three months ended December 31, 2014 was a loss of $0.3 million, as compared to income of $0.1 million in the prior period. As a result of the stronger U.S. dollar, operating profit increased by $0.2 million.
Windsor Locks Thermal Facility
For the three months ended December 31, 2014, the Windsor Locks Thermal Facility sold 157.3 billion lbs of steam and 26.3 GW-hrs of electricity, as compared to 161.3 billion lbs of steam and 28.8 GW-hrs of electricity in the comparable period of 2013.
The Windsor Locks Thermal Facility’s operating profit was driven by energy/steam sales of $4.7 million (U.S. $4.1 million), as compared to $4.6 million (U.S. $4.4 million) in the same period in 2013. The change in electricity/steam sales is attributed to lower production, but partly offset by a higher average price for gas as a result of the better ISO NE electricity market price. Gas costs for the period were $3.1 million (U.S. $2.7 million), as compared to$3.1 million (U.S. $2.9 million) in the same period in 2013. The change in gas costs is a result of decreased production, partly offset by increases in the average landed cost of natural gas per MMBTU in the quarter, as compared to the same period in 2013.
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| 2014 Annual Report | 16 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
As natural gas expense is a significant revenue driver and component of operating expenses, the division compares ‘net energy sales’ (see non-GAAP Financial Measures) as an appropriate measure of the division’s results. For the three months ended December 31, 2014, net sales at the Windsor Locks Thermal Facility totalled $1.6 million (U.S. $1.4 million) as compared to $1.5 million (U.S. $1.5 million) in the same period in 2013. This variance was driven by a small increase in revenue, which was largely the result of the stronger US dollar, and a small decrease in gas costs.
Operating expenses excluding fuel costs were $0.7 million (U.S. $0.6 million), as compared to $0.9 million (U.S. $0.8 million) in the same period in 2013. The decrease was primarily due to an increase in inventorying of REC costs vs the same period last year. Generated RECs that have not been sold under a customer contract are recorded as an increase to inventory with an offset booked to operating expense. The Windsor Locks Thermal Facility’s resulting net operating income for the three months ended December 31, 2014 was $1.0 million (U.S. $0.9 million), as compared to $0.8 million (U.S. $0.9 million) in the same period in 2013; $0.2 million of the increase is attributable to the stronger U.S. dollar.
Sanger Thermal Facility
For the three months ended December 31, 2014, the Sanger Thermal Facility sold 35.1 GW-hrs of electricity, as compared to 35.6 GW-hrs of electricity in the comparable period of 2013.
For the three months ended December 31, 2014, the Sanger Thermal Facility’s operating profit was driven by energy/steam sales of $4.3 million (U.S. $3.8 million), as compared to $3.9 million (U.S. $3.7 million) in the same period in 2013, an increase of $0.4 million. The increase in energy/steam sales is primarily due to an increase in the contract basis differential and passing on higher gas prices to our customer, as compared to the same period in 2013. Capacity revenues remained unchanged at $1.7 million. Gas costs for the period were $1.9 million (U.S. $1.7 million), as compared to $1.5 million (U.S. $1.5 million) in the same period in 2013. The increase in gas costs is largely due to a an increase in the average cost of natural gas per MMBTU and a stronger U.S. dollar, as compared to the same period in 2013.
As natural gas expense is a significant revenue driver and component of operating expenses, the division compares ‘net energy sales’ (see non-GAAP Financial Measures) as an appropriate measure of the division’s results. For the three months ended December 31, 2014, net energy sales at the Sanger Thermal Facility totalled $2.4 million (U.S. $2.1 million), as compared to $2.4 million (U.S. $2.2 million) during the same period in 2013.
Operating expenses excluding natural gas costs were $1.3 million (U.S. $1.2 million), as compared to $1.2 million (U.S. $1.1 million) in the same period in 2013. The Sanger Thermal Facility’s resulting net operating income for the three months ended December 31, 2014 was $1.7 million (U.S. $1.5 million), as compared to $1.8 million (U.S. $1.6 million) during the same period in 2013; the net U.S. dollar impact on the change in the Sanger Thermal Facility's net operating income was nil.
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| 2014 Annual Report | 17 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
|
| | | | | | | | | | | | | | | | | | | |
| Twelve months ended December 31, 2014 |
| Twelve months ended December 31, 2013 |
| Windsor Locks | Sanger | Total |
| Windsor Locks | Sanger | Total |
Performance(GW-hrs sold) | 112.4 |
| 134.2 |
| 246.6 |
|
| 115.3 |
| 137.4 |
| 252.7 |
|
Performance(steam sales – billion lbs) | 609.1 |
| — |
| 609.1 |
|
| 623.0 |
| — |
| 623.0 |
|
| | | | | | | | |
| (all dollar amounts in $ millions) | | | | | | | |
| Revenue | | | | | | | |
| Energy/steam sales | $ | 23.1 |
| $ | 19.8 |
| $ | 42.9 |
| | $ | 17.6 |
| $ | 16.9 |
| $ | 34.5 |
|
| Less: | | | | | | | |
| Cost of Sales – Fuel | (15.1 | ) | (7.5 | ) | $ | (22.6 | ) | | (11.2 | ) | (6.0 | ) | (17.2 | ) |
| Net Energy/Steam Sales | $ | 8.0 |
| $ | 12.3 |
| $ | 20.3 |
|
| $ | 6.4 |
| $ | 10.9 |
| $ | 17.3 |
|
| Other revenue | 1.3 |
| 1.9 |
| 3.2 |
| | 0.5 |
| 1.9 |
| 2.4 |
|
| Total net revenue | $ | 9.3 |
| $ | 14.2 |
| $ | 23.5 |
|
| $ | 6.9 |
| $ | 12.8 |
| $ | 19.7 |
|
| Expenses | | | | | | | |
| Operating expenses | (4.4 | ) | (5.0 | ) | (9.4 | ) | | (3.7 | ) | (4.8 | ) | (8.5 | ) |
| Facility operating profit | $ | 4.9 |
| $ | 9.2 |
| $ | 14.1 |
|
| $ | 3.2 |
| $ | 8.0 |
| $ | 11.2 |
|
| Interest and other income (loss) | | | $ | (0.5 | ) | | | | $ | 0.2 |
|
| Divisional operating profit | | | 13.6 |
| | | | 11.4 |
|
2014 Twelve Month Operating Results
The Generation Group’s Sanger and Windsor Locks Thermal Facilities purchase natural gas from different suppliers and at prices based on different regional hubs. As a result, the average landed cost per unit of natural gas will differ between the two facilities in the average landed cost for natural gas and may result in the facilities showing differing costs per unit compared to each other and compared to the same period in the prior year. Total natural gas expense will vary based on the volume of natural gas consumed and the average landed cost of natural gas for each MMBTU.
Production data, revenue and expenses have been adjusted to remove the results of the EFW and BCI Thermal Facilities, which were divested on April 4, 2014 for proceeds approximating the carrying value of the net assets on the Consolidated Balance Sheet of the Company as at March 31, 2014. The results of the EFW and BCI Thermal Facilities for the period up to the date of sale are reported as discontinued operations. See Financial Statement note 17 for details.
For the twelve months ended December 31, 2014, the Thermal Energy Division’s operating profit was $13.6 million, as compared to $11.4 million in the same period in 2013, an increase of $2.2 million. The Windsor Locks Thermal Facility contributed $4.9 million, while the Sanger Thermal Facility contributed $9.2 million of operating profit during the twelve months ended December 31, 2014, as compared to $3.2 million and $8.0 million, respectively, during the same period in the prior year. Interest and other income for the twelve months ended December 31, 2014 was a loss of $0.5 million, as compared to income of $0.2 million during the same period in the prior year. As a result of the stronger U.S. dollar, operating profit was positively impacted by $1.1 million.
Windsor Locks Thermal Facility
For the twelve months ended December 31, 2014, the Windsor Locks Thermal Facility sold 609.1 billion lbs of steam and 112.4 GW-hrs of electricity, as compared to 623.0 billion lbs of steam and 115.3 GW-hrs of electricity in the comparable period of 2013.
The Windsor Locks Thermal Facility’s operating profit was driven by energy/steam sales of $23.1 million (U.S. $20.9 million), as compared to $17.6 million (U.S. $17.1 million) in the same period in 2013. The increase in electricity/steam sales is attributed to a higher average price for gas as a result of the better ISO NE electricity market price driven by seasonally low temperatures in the first half of 2014. Gas costs for the period were $15.1 million (U.S. $13.7 million), as compared to
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| 2014 Annual Report | 18 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
$11.2 million (U.S. $10.9 million) in the same period in 2013. The increase in gas costs is a result of increases in the average landed cost of natural gas per MMBTU in the first three quarters of the year, as compared to the same period in 2013.
As natural gas expense is a significant revenue driver and component of operating expenses, the division compares ‘net energy sales’ (see non-GAAP Financial Measures) as an appropriate measure of the division’s results. For the twelve months ended December 31, 2014, net energy/steam sales at the Windsor Locks Thermal Facility totalled $8.0 million (U.S. $7.2 million), as compared to $6.4 million (U.S. $6.2 million) during the same period in 2013, an increase of $1.6 million (U.S. $1.0 million).
Operating expenses excluding natural gas costs were $4.4 million (U.S. $4.0 million), as compared to $3.7 million (U.S. $3.6 million) during the same period in 2013. The increase is primarily attributable to a stronger U.S. dollar and the cost of RECs sold in the first nine months of 2014 but generated in 2013 (an offset to operating expense is booked when a REC is generated and is recorded as inventory). The Windsor Locks Thermal Facility’s resulting net operating income for the twelve months ended December 31, 2014 was $4.9 million (U.S. $4.4 million), as compared to $3.2 million (U.S. $3.1 million) in the same period in 2013, an increase of $1.7 million; $0.4 million of the increase is attributable to the stronger U.S. dollar.
Sanger Thermal Facility
For the twelve months ended December 31, 2014, the Sanger Thermal Facility sold 134.2 GW-hrs of electricity, as compared to 137.4 GW-hrs of electricity in the comparable period of 2013. The decrease in production is due to the Sanger Thermal Facility's planned outage and limitation of run hours in the first quarter of 2014.
For the twelve months ended December 31, 2014, the Sanger Thermal Facility’s operating profit was driven by energy/steam sales of $19.8 million (U.S. $17.9 million), as compared to $16.9 million (U.S. $16.4 million) in the same period in 2013, an increase of $2.9 million. The increase in energy/steam sales is attributed primarily to increased gas prices, as compared to 2013, which is a pass through to customers. Capacity revenues remained unchanged at $8.4 million. Gas costs for the period were $7.5 million (U.S. $6.8 million), as compared to $6.0 million (U.S. $5.8 million) in the same period in 2013. The increase in gas costs is largely due to a 19% increase in the average cost of natural gas per MMBTU and a stronger U.S. dollar, as compared to the same period in 2013.
As natural gas expense is a significant revenue driver and component of operating expenses, the division compares ‘net energy sales’ (see non-GAAP Financial Measures) as an appropriate measure of the division’s results. For the twelve months ended December 31, 2014, net energy sales at the Sanger Thermal Facility totalled $12.3 million (U.S. $11.1 million), as compared to $10.9 million (U.S. $10.6 million) during the same period in 2013, an increase of $1.4 million primarily due to more favorable pricing on the variable portion of the supply contract and an increase in the U.S. dollar exchange rate.
Operating expenses excluding natural gas costs were $5.0 million (U.S. $4.5 million), as compared to $4.8 million (U.S. $4.7 million) during the same period in 2013. The Sanger Thermal Facility’s resulting net operating income for the twelve months ended December 31, 2014 was $9.2 million (U.S. $8.3 million), as compared to $8.0 million (U.S. $7.8 million) in the same period in 2013, an increase of $1.2 million; $0.7 million of the increase is attributable to the stronger U.S. dollar.
GENERATION BUSINESS GROUP
Development Division
The Development Division works to identify, develop and construct new power generating facilities, as well as to identify, and acquire, operating projects that would be complementary and accretive to the Generation Group’s existing portfolio. The Development Division is focused on projects within North America and is committed to working proactively with all stakeholders including local communities. The Generation Group’s approach to project development and acquisition is to maximize the utilization of internal resources while minimizing external costs. This allows projects to mature to the point where most major elements and uncertainties are quantified and resolved prior to the commencement of project construction. Major elements and uncertainties of a project include the signing of a PPA, obtaining the required financing commitments to develop the project, completion of environmental and other required 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 the Generation Group’s Development Division will begin construction or execute an acquisition agreement.
The Generation Group’s Development Division has successfully completed, is constructing and is developing a number of power generation projects. The projects are as follows:
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| 2014 Annual Report | 19 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
|
| | | | | | | | | | |
| Project Name | Location | Size (MW) | Estimated Capital Cost (millions) | Commercial Operation | PPA Term | Production GW-hrs |
| Projects Completed | | | | | | |
Cornwall Solar Facility1 | Ontario | 10 |
| $ | 47.6 |
| 2014 | 20 | 14.4 |
|
St. Damase Wind Facility1 | Quebec | 24 |
| $ | 69.7 |
| 2014 | 20 | 76.9 |
|
| Total Completed | | 34 |
| $ | 117.3 |
| | | 91.3 |
|
| | | | | | | |
| Projects in Construction | | | | | | |
Morse Wind Project1 | Saskatchewan | 23 |
| $ | 81.3 |
| 2015 | 20 | 104.0 |
|
Bakersfield I Solar Project1,2 | California | 20 |
| $ | 67.9 |
| 2015 | 20 | 53.3 |
|
| Total Project in Construction | | 43 |
| $ | 149.2 |
| | | 157.3 |
|
| | | | | | | |
| Projects in Development | | | | | | |
Odell Wind Project1,3 | Minnesota | 200 |
| $ | 374.5 |
| 2015/16 | 20 | 814.7 |
|
Val Eo Wind Project1,4,5 | Quebec | 24 |
| $ | 70.0 |
| 2016/17 | 20 | 66.0 |
|
Bakersfield II Solar Project1,6 | California | 10 |
| $ | 31.3 |
| 2016 | 20 | 26.5 |
|
Amherst Island Wind Project1 | Ontario | 75 |
| $ | 260.0 |
| 2016/17 | 20 | 235.0 |
|
Chaplin Wind Project1,7 | Saskatchewan | 177 |
| $ | 340.0 |
| 2017/18 | 25 | 720.0 |
|
| Total Projects in Development | | 486 |
| $ | 1,075.8 |
| | | 1,862.2 |
|
| Total in Construction and Development | | 529 |
| $ | 1,225.0 |
| | | 2,019.5 |
|
|
| |
| 1 | PPA Signed. |
| 2 | Total cost of the project is expected to be approximately $58.5 million in U.S. dollars. |
| 3 | Total cost of the project is expected to be approximately $322.8 million in U.S. dollars. |
| 4 | The Val Eo Wind Project is being developed in two phases: Phase I of the project (24 MW) will be erected in 2015 and the101 MW Phase II of the project will be constructed following evaluation of the wind resource at the site, completion of satisfactory permitting and entering into appropriate energy sales arrangements. |
| 5 | Size, Estimated Capital Costs, Commercial Operation Date, PPA Term and Production refer solely to Phase I of the Val-Eo Wind Project. |
| 6 | Total cost of the project is expected to be approximately $27.0 million in U.S. dollars. |
| 7 | The Chaplin project is being developed in two phases: Phase I of the project , which comprises approximately 35 MW of the total project, will be erected in 2017 and Phase II of the project, which comprises the remaining approximately 142 MW, will be constructed following evaluation of the wind resource at the site, and completion of satisfactory permitting. |
Projects Completed
Cornwall Solar Facility
Construction of the project is now complete and commercial operation was achieved on March 27, 2014. The Cornwall Solar Facility is anticipated to have energy production of 14.4 GW-hrs/year. The Cornwall Solar Facility has been granted a 10 MW Feed In Tariff ("FIT") contract by the OPA, with a 20 year term and a rate of $443/MW-hr, resulting in expected initial annual revenues of approximately $6.2 million. Operating results from this project are now being reported in the Generation Group's renewable energy results.
St. Damase Wind Facility
Construction of the St. Damase Wind Facility is now complete and commercial operation was achieved on December 2, 2014. The facility has a 20 year PPA with Hydro Quebec. It is a 24 MW facility and is expected to generate $7.4 million in revenue in its first full year of operations.
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| 2014 Annual Report | 20 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
It is expected that the turbines and other components utilized in the first 24 MW phase of the Saint-Damase Wind Facility will qualify as CRCE, and therefore a significant portion of the Phase I capital cost will be eligible for a refundable Quebec CRCE Tax Credit. In June 2014, the government of Quebec released the 2014-2015 budget, which included a 20% reduction in value for a wide range of tax credits, including the Quebec CRCE Tax Credit. The estimated value of the Quebec CRCE tax credit for the St. Damase project is expected to be approximately $16.6 million. Phase II of the project will be constructed following evaluation of the wind resource at the site, completion of satisfactory permitting, and entering into appropriate energy sales arrangements. Operating results from this project are now being reported in the Generation Group's renewable energy results.
Projects in Construction
Morse Wind Project
The Morse Wind Project is comprised of three contiguous projects with 25 MW of aggregate installed generating capacity. The project is to be constructed near Morse, Saskatchewan, approximately 180 km west of Regina. It is contemplated that the project will have additional land under lease or option in order to facilitate future expansion.
Based on the award of 25 MW under Saskatchewan’s Green Options Partner Program, SaskPower has offered the Generation Group a 20 year contract for the procurement of 23 MW of wind generation to match the nameplate capacity of the proposed turbines.
The Generation Group executed an asset purchase agreement with a local developer, Kineticor, to acquire assets related to two adjacent 10 MW wind energy development projects in Saskatchewan and a further 5 MW was developed by the Generation Group independently. All of the individual projects comprising the Morse wind project were selected by SaskPower in accordance with the SaskPower Green Options Partners Program.
The turbine supply agreements have been executed with Siemens and the Balance of Plant Engineering, Procurement and Construction agreement has been signed. The turbine placement has been finalized and registered land leases have been executed with the landowners. Installation of access roads and foundations are completed, and turbine delivery commenced in January 2015. Seven of ten turbine have been erected, and the project is expected to be operational by March 31, 2015.
Bakersfield I Solar Project
The Generation Group has entered into an agreement for the continuing development of a 20 MWac solar powered generating station located in Kern County, California. Following commissioning, the Bakersfield Solar Project is expected to generate 53.3 GW-hrs of energy per year. All energy from the project will be sold to PG&E pursuant to a 20 year agreement with expected first full year revenues of U.S. $4.7 million. The Generation Group has entered into a partnership agreement with a third party (the “Tax Partner”) pursuant to which the Tax Partner will receive the majority of the tax attributes associated with the project. The Tax Partner will contribute U.S. $22.0 million to the project with the remaining of the total estimated cost of U.S. $58.5 million to be funded by the Generation Group.
Construction of the project commenced in the second quarter of 2014 and was placed in service on December 30, 2014. Testing to ensure the plant will be ready and available for commercial operations was conducted and confirmed by the Generation Group and independent engineers. Final construction efforts continue, with the project expected to reach full commercial operation in the first quarter of 2015.
Projects in Development
Odell Wind Project
The Odell Wind Project is a 200 MW wind development located in Cottonwood, Jackson, Martin, and Watonwan counties in Minnesota and is being constructed on approximately 23,000 acres of leased land. The project will utilize 100 Vestas V110-2.0 wind turbines. Pursuant to a 20-year PPA, all energy, capacity and renewable energy credits from the project will be sold to Northern States Power Company, a subsidiary of Xcel Energy Inc., which is a diversified utility operating in the midwest U.S. Construction is expected to begin in the second quarter of 2015, with total costs estimated at U.S. $322.8 million. It is anticipated that the Odell Project will qualify for U.S. federal production tax credits having satisfied the Internal Revenue Service 5% beginning of construction investment safe-harbor guidance. Accordingly, approximately 60% of the permanent project financing is expected to be funded by tax equity investors.
The Generation Group's participation in the project will be via a 50% equity interest in a new joint venture with a third party developer. The Company is accounting for the joint venture as an equity method investment since both partners have joint control of the new venture. The Generation Group holds an option to acquire the other 50% interest on commencement of operations, which is expected in late 2015 or early 2016.
Val-Éo Wind Project
Phase one of the Val-Éo Wind Project is located in the local municipality of Saint-Gideon de Grandmont, which is within the regional municipality of Lac-Saint-Jean-Est. The project proponents include the Val-Éo Wind cooperative formed by community
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| 2014 Annual Report | 21 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
based landowners and the Generation Group. The first 24 MW phase of the project is expected to be comprised of eight wind turbines, producing approximately 66.0GW-hr annually. Construction of the first 24 MW phase of the project is expected to begin in 2015 with commercial operations commencing in 2016. The second phase of the project would entail the development of an additional 101 MW. The permitting and the Environmental Impact Assessment are ongoing with a projected provincial minister’s decree in early 2015.
The Generation Group’s equity interest in the project is subject to final negotiations with the Val-Éo community cooperative but, in any event, will not be less than 25%. It is believed that the first 24 MW phase of the Val-Éo Wind Project will qualify as Canadian Renewable Conservation Expense and therefore the project will be entitled to a refundable tax credit equal to approximately $18.0 million.
Commission de Protection du Territoire Agricole Quebec ("CPTAQ") approval has been received for 8 turbine locations, roads, and the collection system. Land option agreements have all been secured, and the process of converting these options is currently underway. Proposals for the procurement of the substation and balance of plant have been received and evaluated. The final construction schedule is pending the signing of the turbine supply agreement.
Bakersfield II Solar Project
The Bakersfield II Solar Project is a 10 MW project adjacent to the Generation Group's 20 MW Bakersfield I Solar Project in Kern County, California, which is currently under construction.
The 10 MW Bakersfield II Solar Project executed a 20 year PPA on September 22, 2014 with a large California based electric utility. The project will be located on 64 acres of land adjacent to the 20 MW Bakersfield I Solar Project. Construction of Bakersfield I Solar is nearing completion, with commercial operations expected to occur in the first quarter of 2015.
The total project cost for Bakersfield II Solar of approximately U.S. $27.0 million will be funded with a combination of senior debt, common equity, and contributions from tax equity investors. Consistent with financing structures utilized for U.S. based renewable energy projects including Bakersfield I Solar, it is anticipated that Bakersfield II Solar will source financing in the amount of approximately 40% of the capital costs from certain tax equity investors.
Construction of Bakersfield II Solar is anticipated to commence in mid-2015 following receipt of local permits and finalization of necessary construction contracts, subject to approval by the APUC board of directors. Commercial operation is targeted to occur in the first half of 2016.
Amherst Island Wind Project
The Amherst Island Wind Project is located on Amherst Island near the village of Stella, approximately 15 kilometers southwest of Kingston, Ontario. In February 2011, the 75 MW project was awarded a FIT contract by the OPA as part of the second round of the OPA’s FIT program.
The Amherst Island Wind Project is currently contemplated to use Class III wind turbine generator technology. The available wind resource is forecast to produce approximately 235 GW-hrs of electrical energy annually, depending upon the final turbine selection for the project. Final negotiations on the turbine supply agreement is ongoing. Total capital costs for the facility are currently estimated to be $260 million, and engineering, procurement and construction contractor selection is underway. The financing of the project will be arranged and announced when all required permitting and all other pre-construction conditions have been satisfied.
The Renewable Energy Approval (“REA”) application was submitted in April 2013 and posted to the environmental registry in early January 2014 and has been undergoing technical review. Changes to the project design have been initiated to optimize construction and project performance, which will require a modification of the application documents. Once the REA is issued in final form, it may be appealed by interested parties within 15 days of its release. If the REA is appealed, the appeal process is expected to take up to 6 months. Other permitting processes are progressing according to schedule. The project has a planned construction time frame of 12 to 18 months with most of the construction expected to occur in 2016.
Chaplin Wind Project
In the first quarter of 2012, the Generation Group entered into a 25 year PPA with SaskPower for development of a 177 MW wind power project in the rural municipality of Chaplin, Saskatchewan, 150 km west of Regina, Saskatchewan.
The project will be split into two phases where Phase I will approximate 35 MW of the total project and is currently planned to be operational in 2017. The first phase will involve installing test turbines to prove the project viability. The second phase, the infill construction phase, will only commence provided the results of the first phase are successful.
The total facility will be constructed at an estimated capital cost of $340.0 million and consist of approximately 77 multi-megawatt wind turbines. In the total project's first full year of operation, the Generation Group expects to achieve EBITDA of $36.5 million. The 25 year PPA features a rate escalation provision of 0.6% throughout the term of the agreement. The project will take advantage of its favorable location by interconnecting with a nearby 138Kv line and will be compliant with SaskPower’s latest interconnection requirements.
|
| |
| 2014 Annual Report | 22 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
In March 2014, after review of the Project Proposal Environmental Assessment and Supplemental documentation (including the preliminary proposed layout), the project was deemed a development by the Environmental Assessment Branch. An additional detailed environmental review is currently being completed. It is anticipated that the Environmental Assessment documentation will be submitted to the government in the first quarter of 2015. The expected capital costs of the project are approximately $340 million. The Generation Group anticipates entering into a partnership and development agreement using a similar structure to what was utilized in the development of the Red Lily I Facility, in order to facilitate the development of the project and to optimize returns.
Ontario RFP Qualification
The Generation Group has qualified for participation in the anticipated 2015 Large Renewable Procurement I process with the IESO. The Generation Group may submit offers into the expected RFP for up to 100 MW of solar power and up to 100 MW of wind power. The IESO is expected to award up to 140 MW of solar projects and 300 MW of wind projects. RFP bids are due on September 1, 2015, with successful bidders being announced in December 2015.
DISTRIBUTION BUSINESS GROUP
The Distribution Group operates rate-regulated utilities providing distribution services to approximately 488,000 connections in the natural gas, electric, water and wastewater sectors. The Distribution Group's strategy is to grow its business organically and through business development activities while using prudent acquisition criteria. The Distribution Group believes that its business results are maximized by building constructive regulatory and customer relationships, and enhancing community connections.
|
| | | | | | | | | | | | | | |
| Utility System Type | | December 31, 2014 | | December 31, 2013 |
| (all dollar amounts in U.S. $ millions) | | Assets | | Connections | | Assets | | Connections |
| Electricity | | $ | 325.0 |
| | 93,000 |
| | $ | 276.6 |
| | 92,000 |
|
| Natural Gas | | 726.0 |
| | 292,000 |
| | 661.5 |
| | 292,000 |
|
| Water and Wastewater | | 261.2 |
| | 103,000 |
| | 233.0 |
| | 97,400 |
|
| Total | | $ | 1,312.2 |
| | 488,000 |
| | $ | 1,171.1 |
| | 481,400 |
|
| |
| |
| |
| |
|
| Accumulated Deferred Income Taxes | | $ | 79.6 |
| |
| | $ | 66.5 |
| |
|
The Distribution Group aggregates the performance of its utility operations by utility system type – electricity, natural gas, and water and wastewater systems.
The electric distribution systems are comprised of regulated electrical distribution utility systems and serve approximately 93,000 connections in the states of California and New Hampshire.
The natural gas distribution systems are comprised of regulated natural gas distribution utility systems and serve approximately 292,000 connections located in the states of New Hampshire, Illinois, Iowa, Missouri, Georgia, and Massachusetts.
The water and wastewater distribution systems are comprised of regulated water distribution and wastewater collection utility systems and serve approximately 103,000 connections located in the states of Arkansas, Arizona, Texas, Illinois, and Missouri.
|
| |
| 2014 Annual Report | 23 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
|
| | | | | | | | | | | | | | | | |
| | | Three months ended December 31, | | Three months ended December 31, |
| | | 2014 U.S. $ (millions) | | 2013 U.S. $ (millions) | | 2014 Can $ (millions) | | 2013 Can $ (millions) |
| Revenue | | | | |
| Utility electricity sales and distribution | | 47.8 |
| | 41.9 |
| | 54.4 |
| | 46.4 |
|
| Less: Cost of Sales – Electricity | | (29.9 | ) | | (25.2 | ) | | (34.2 | ) | | (26.5 | ) |
| Net Utility Sales - Electricity | | $ | 17.9 |
| | $ | 16.7 |
| | $ | 20.2 |
| | $ | 19.9 |
|
| | | | | | | | | |
| Utility natural gas sales and distribution | | 102.5 |
| | 83.5 |
| | 116.8 |
| | 88.0 |
|
| Less: Cost of Sales – Natural Gas | | (65.6 | ) | | (54.1 | ) | | (74.9 | ) | | (57.1 | ) |
| Net Utility Sales - Natural Gas | | $ | 36.9 |
| | $ | 29.4 |
| | $ | 41.9 |
| | $ | 30.9 |
|
| | | | | | | | | |
| Net Utility Sales - Water Distribution & Wastewater Treatment | | 15.0 |
| | 14.0 |
| | 18.6 |
| | 14.6 |
|
| Gas Transportation | | 6.8 |
| | 4.5 |
| | 7.7 |
| | 4.7 |
|
| Other Revenue | | 3.0 |
| | 1.2 |
| | 3.5 |
| | 1.3 |
|
| Net Utility Sales | | $ | 79.6 |
| | $ | 65.8 |
| | $ | 91.9 |
| | $ | 71.4 |
|
| | | | | | | | | |
| Operating expenses | | (39.7 | ) | | (34.0 | ) | | (46.2 | ) | | (35.6 | ) |
| Other income | | 0.8 |
| | 0.7 |
| | 0.9 |
| | 0.6 |
|
| Distribution Group operating profit | | $ | 40.7 |
| | $ | 32.5 |
| | $ | 46.6 |
| | $ | 36.4 |
|
2014 Fourth Quarter Operating Results
For the three months ended December 31, 2014, the Distribution Group reported an operating profit of U.S. $40.7 million, as compared to U.S. $32.5 million for the comparable period in the prior year. The increase is primarily due to implementation of higher rates at the Granite State Electric and Peach State Gas Systems and the acquisition of the New England Gas System on December 20, 2013. Detailed results are discussed in the following sections. Measured in Canadian dollars, the group's operating profit was $46.6 million, as compared to $36.4 million for the comparable period in the prior year. In addition to the factors described below, operating profit measured in Canadian dollars increased by $5.9 million due to a stronger U.S. dollar.
|
| |
| 2014 Annual Report | 24 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
|
| | | | | |
| Electric Distribution Systems | Three months ended December 31 |
| | 2014 | | 2013 |
| Average Active Electric Connections For The Period | | | |
| Residential | 80,000 |
|
| 78,000 |
|
| Commercial and Industrial | 12,000 |
|
| 12,000 |
|
| Total Average Active Electric Connections For The Period | 92,000 |
| | 90,000 |
|
| | | | |
| Customer Usage (GW-hrs) | | | |
| Residential | 134.9 |
|
| 146.4 |
|
| Commercial and Industrial | 230.5 |
|
| 222.5 |
|
| Total Customer Usage (GW-hrs) | 365.4 |
| | 368.9 |
|
For the three months ended December 31, 2014 the electric distribution systems' usage totalled 365.4 GW-hrs, as compared to 368.9 GW-hrs for the same period in 2013, a decrease of 3.5 GW-hrs. The decrease in residential usage can be primarily attributed to a lower number of heating degree days experienced at the CalPeco Electric System's service territory. A heating degree day is generally defined as the number of degrees that a day's average temperature is below 65 degrees Fahrenheit (18 degrees Celsius).
For the three months ended December 31, 2014, the electric distribution systems' revenue from utility electricity sales totalled U.S. $47.8 million, as compared to U.S. $41.9 million during the same period in 2013, an increase of U.S.$5.9 million, or 14.1%. For the three months ended December 31, 2014, fuel and purchased power costs for the electric distribution systems totalled U.S. $29.9 million, as compared to U.S. $25.2 million during the same period in 2013, an increase of U.S. 4.7 million, or 18.7%.
The purchase of electricity by the electric distribution systems is a significant revenue driver and component of operating expenses, however these costs are effectively passed through to its customers. As a result, ‘net utility sales' (see non-GAAP Financial Measures) are a more appropriate measure of the results. For the three months ended December 31, 2014, net utility sales for the electric distribution systems were U.S. $17.9 million, as compared to U.S. $16.7 million during the same period in 2013, an increase of U.S. $1.2 million, or 7%. The increase in net utility sales is primarily attributed to increased rates at the Granite State Electric System as a result of finalization of the general rate case in March 2014. Under the base rate revenue decoupling mechanism approved by the CPUC, which became effective on January 1, 2013, the CalPeco Electric System’s base rate revenues are not impacted by fluctuations in customer demand due to the variations in the weather conditions and changes in the number of customers. Instead, the CalPeco Electric System is required to record 1/12 of its annual base rate revenue requirement each month. The electricity commodity continues to be passed through to the CalPeco Electric System’s customers according to their consumption.
|
| | | | | |
| Natural Gas Distribution Systems | Three months ended December 31, |
| | 2014 | | 2013 |
| Average Active Natural Gas Connections For The Period | | | |
| Residential | 248,000 |
|
| 217,000 |
|
| Commercial and Industrial | 27,000 |
|
| 24,000 |
|
| Total Average Active Natural Gas Connections For The Period | 275,000 |
| | 241,000 |
|
| | | |
| Customer Usage (MMBTU) | | | |
| Residential | 3,918,000 |
|
| 3,376,000 |
|
| Commercial and Industrial | 2,885,000 |
|
| 2,779,000 |
|
| Total Customer Usage (MMBTU) | 6,803,000 |
| | 6,155,000 |
|
For the three months ended December 31, 2014, usage at the natural gas distribution systems totalled 6,803,000 MMBTU, as compared to 6,155,000 MMBTU during the same period in 2013, an increase of 648,000 MMBTU, or 10.5%. The increase in natural gas usage, as compared to the same period in 2013, can primarily be attributed to the acquisition of the
|
| |
| 2014 Annual Report | 25 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
New England Gas System on December 20, 2013, at which usage totalled 1,053,000 MMBTU, and a higher number of heating degree days experienced in the Peach State Gas System's service territory. The increase was partially offset by a lower number of heating degree days experienced in the EnergyNorth Gas System and the Midstates Gas Systems service territories, as compared to the same period in 2013.
For the three months ended December 31, 2014, revenue excluding transportation revenue from natural gas sales and distribution totalled U.S. $102.5 million, as compared to U.S. $83.5 million during the same period in 2013, an increase of U.S. $19.0 million or 22.8%. For the three months ended December 31, 2014, natural gas purchases totalled U.S. $65.6 million, as compared with U.S. $54.1 million for the same period in 2013, an increase of U.S. $11.5 million or 21.3%. The cost of natural gas is passed through to the natural gas systems' customers. As a result, ‘net utility sales’ (see non-GAAP Financial Measures) are a more appropriate measure of the results. For the three months ended December 31, 2014, net utility sales for the natural gas distribution systems, excluding transportation, totalled U.S. $36.9 million, as compared to U.S. $29.4 million during the same period in 2013, an increase of U.S. $7.5 million, or 25.5%. The increase in net utility sales can be primarily attributed to the acquisition of the New England Gas System on December 20, 2013, which contributed U.S. $4.3 million of the total increase, and a U.S. $3.1 million increase at the Peach State Gas System primarily due to increased rates as a result of the GRAM filing.
For the three months ended December 31, 2014, revenue from gas transportation sales totalled U.S. $6.8 million, as compared to U.S. $4.5 million during the same period in 2013, an increase of U.S. $2.3 million. The increase in gas transportation sales can be primarily attributed to the acquisition of the New England Gas System on December 20, 2013, which contributed U.S. $1.2 million of the total increase, and a U.S. $1.0 million increase at the EnergyNorth Gas System, primarily due to increased customer demand.
|
| | | | | |
| Water and Wastewater Distribution Systems | Three months ended December 31, |
| | 2014 | | 2013 |
| Average Active Connections For The Period | | | |
| Wastewater connections | 40,000 |
|
| 36,900 |
|
| Water distribution connections | 58,000 |
|
| 55,900 |
|
| Total Average Active Connections For The Period | 98,000 |
| | 92,800 |
|
| | | | |
| Gallons Provided | | | |
| Wastewater treated (millions of gallons) | 535 |
|
| 507 |
|
| Water sold (millions of gallons) | 1,940 |
|
| 2,080 |
|
| Total Gallons Provided | 2,475 |
| | 2,587 |
|
During the three months ended December 31, 2014, the water and wastewater distribution systems provided approximately 1,940 million gallons of water to its customers and treated approximately 535 million gallons of wastewater, as compared to 2,080 million gallons of water and 507 million gallons of wastewater during the same period in 2013. The decrease in the gallons of water provided to customers can be attributed to increased precipitation, primarily in the state of Arizona during the three months ended December 31, 2014, as compared to the comparable period in the prior year.
The increase in average active wastewater and water distribution connections can be primarily attributed to the acquisition of the White Hall Water System on May 30, 2014.
For the three months ended December 31, 2014, revenue from wastewater treatment and water distribution totalled U.S. $6.9 million and U.S. $8.1 million, respectively, as compared to U.S. $6.1 million and U.S. $7.9 million, respectively, during the same period in 2013. The increase in wastewater treatment and water distribution revenue was primarily due to an increase in rates at the LPSCo Water and Sewer System, effective May 1, 2014, and the acquisition of the White Hall Water System on May 30, 2014.
Other Revenue
For the three months ended December 31, 2014, other revenue totalled U.S. $3.0 million, as compared to $1.2 million during the same period in 2014. The other revenue consists of water heater rental service and a contract to supply gas to Fort Benning.
|
| |
| 2014 Annual Report | 26 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
Operating Expenses
For the three months ended December 31, 2014, operating expenses, excluding electricity purchases, totalled U.S. $39.7 million, as compared to U.S. $34.0 million during the same period in 2013, an increase of U.S. $5.7 million, or 17%. The major factors resulting in the increase in the Distribution Group's operating expenses in the three months ended December 31, 2014, as compared to the corresponding period in 2013, are set out as follows:
|
| | | |
| (all dollar amounts in U.S. $ millions) | Quarter ended December 31, 2014 |
| Comparative Prior Period Operating Expenses | $ | 34.0 |
|
| Significant Changes: | |
| Acquisition of New England Gas System | 6.3 |
|
| Decrease in operating expenses at Granite State Electric Utility and EnergyNorth Gas Utility | (1.4 | ) |
| Acquisition of White Hall Water System | 0.2 |
|
| Increase in operating expenses at CalPeco Electric System | 0.2 |
|
| Other | 0.4 |
|
| Current Period Operating Expenses | $ | 39.7 |
|
|
| | | | | | | | | | | | | | | | |
| | | Twelve months ended December 31, | | Twelve months ended December 31, |
| | | 2014 U.S. $ (millions) | | 2013 U.S. $ (millions) | | 2014 Can $ (millions) | | 2013 Can $ (millions) |
| Revenue | | | | | | | | |
| Utility electricity sales and distribution | | 186.8 |
| | 161.3 |
| | 206.7 |
|
| 166.2 |
|
| Less: Cost of Sales – Electricity | | (108.8 | ) | | (94.5 | ) | | (120.5 | ) |
| (97.4 | ) |
| Net Utility Sales - Electricity | | $ | 78.0 |
| | $ | 66.8 |
| | $ | 86.2 |
| | $ | 68.8 |
|
| | | | | | | | | |
| Utility natural gas sales and distribution | | 378.2 |
| | 236.0 |
| | 419.9 |
|
| 243.1 |
|
| Less: Cost of Sales – Natural Gas | | (234.8 | ) | | (144.5 | ) | | (261.1 | ) |
| (148.8 | ) |
| Net Utility Sales - Natural Gas | | $ | 143.4 |
| | $ | 91.5 |
| | $ | 158.8 |
| | $ | 94.3 |
|
| | | | | | | | | |
| Net Utility Sales - Water Distribution & Wastewater Treatment | | 58.7 |
| | 55.6 |
| | 66.4 |
|
| 57.4 |
|
| Gas Transportation | | 23.5 |
| | 16.8 |
| | 26.1 |
|
| 17.3 |
|
| Other Revenue | | 5.1 |
| | 1.2 |
| | 5.7 |
|
| 1.3 |
|
| Net Utility Sales | | $ | 308.7 |
| | $ | 231.9 |
| | $ | 343.2 |
| | $ | 239.1 |
|
| | | | | | | | | |
| Operating expenses | | (162.7 | ) | | (127.5 | ) | | (180.4 | ) |
| (131.6 | ) |
| Other income | | 3.0 |
| | 3.1 |
| | 3.4 |
|
| 3.2 |
|
| Distribution Group operating profit | | $ | 149.0 |
| | $ | 107.5 |
| | $ | 166.2 |
| | $ | 110.7 |
|
2014 Twelve Month Operating Results
For the twelve months ended December 31, 2014, the Distribution Group reported an operating profit of U.S. $149.0 million, as compared to U.S. $107.5 million for the comparable period in the prior year. The increase is primarily due to the acquisition of the New England Gas System on December 20, 2013, the acquisition of the Peach State Gas System on April 1, 2013, and higher rates at the Granite State Electric System. Detailed results are discussed in the following sections. Measured in Canadian dollars, the group's operating profit was $166.2 million, as compared to $110.7 million for the comparable period in the prior year. In addition to the factors discussed below, operating profit measured in Canadian dollars increased by $17.2 million due to a stronger U.S. dollar.
|
| |
| 2014 Annual Report | 27 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
|
| | | | | |
| Electric Distribution Systems | Twelve months ended December 31, |
| | 2014 | | 2013 |
| Average Active Electric Connections For The Period | | | |
| Residential | 79,000 |
|
| 78,000 |
|
| Commercial and Industrial | 12,000 |
|
| 12,000 |
|
| Total Average Active Electric Connections For The Period | 91,000 |
| | 90,000 |
|
| | | | |
| Customer Usage (GW-hrs) | | | |
| Residential | 557.4 |
|
| 585.9 |
|
| Commercial and Industrial | 933.4 |
|
| 905.5 |
|
| Total Customer Usage (GW-hrs) | 1,490.8 |
| | 1,491.4 |
|
For the twelve months ended December 31, 2014, the electric distribution systems' usage totalled 1,490.8 GW-hrs, as compared to 1,491.4 GW-hrs for the same period in 2013. The decrease in residential usage can be primarily attributed to a lower number of heating degree days experienced at the CalPeco Electric System's service territory.
For the twelve months ended December 31, 2014, the electric distribution systems revenue from utility electricity sales totalled U.S. $186.8 million, as compared to U.S. $161.3 million during the same period in 2013, an increase of U.S. $25.5 million, or 15.8%. For the twelve months ended December 31, 2014, fuel and purchased power costs for the electric distribution systems totalled U.S $108.8 million, as compared to U.S. $94.5 million for the same period in 2013, an increase of U.S. $14.3 million, or 15.1%.
The purchase of electricity by the electric distribution systems is a significant revenue driver and component of operating expenses, but these costs are effectively passed through to its customers. As a result, ‘net utility sales' (see non-GAAP Financial Measures) are a more appropriate measure of the results. For the twelve months ended December 31, 2014, net utility sales for the electric distribution systems were U.S. $78.0 million, as compared to U.S. $66.8 million for the same period in 2013, an increase of U.S. $11.2 million, or 16.8%. The increase in net utility sales can be primarily attributed to an increase in distribution rates to customers from finalization of the Granite State Electric System's general rate case, as well as U.S. $2.5 million in additional revenue recognized in the first quarter of 2014, which represented the difference from the interim rates previously granted to the Granite State Electric System and the final rates retroactive to July 1, 2013. Under the base rate revenue decoupling mechanism approved by the CPUC, which became effective on January 1, 2013, the CalPeco Electric System’s base rate revenues are not impacted by fluctuations in customer demand due to the variations in the weather conditions and changes in the number of customers. Instead, the CalPeco Electric System is required to record 1/12 of its annual base rate revenue requirement each month. The electricity commodity continues to be passed through to the CalPeco Electric System’s customers according to their consumption.
|
| |
| 2014 Annual Report | 28 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
|
| | | | | |
| Natural Gas Distribution Systems | Twelve months ended December 31, |
| | 2014 | | 2013 |
| Average Active Natural Gas Connections For The Period | | | |
| Residential | 248,000 |
|
| 204,000 |
|
| Commercial and Industrial | 26,000 |
|
| 23,000 |
|
| Total Average Active Natural Gas Connections For The Period | 274,000 |
| | 227,000 |
|
| | | | |
| Customer Usage (MMBTU) | | | |
| Residential | 18,915,000 |
|
| 12,401,000 |
|
| Commercial and Industrial | 12,673,000 |
|
| 8,706,000 |
|
| Total Customer Usage (MMBTU) | 31,588,000 |
| | 21,107,000 |
|
For the twelve months ended December 31, 2014, customer usage at the natural gas distribution systems totalled 31,588,000 MMBTU, as compared to 21,107,000 MMBTU during the same period in 2013, an increase of 10,481,000 MMBTU, or 49.7%. The increase in natural gas usage, as compared to the same period in 2013, can be primarily attributed to the acquisitions of the Peach State Gas System on April 1, 2013 and the New England Gas System on December 20, 2013; the New England Gas System usage totalled 5,273,000 MMBTU.
For the twelve months ended December 31, 2014, revenue from natural gas sales and distribution totalled U.S. $378.2 million, as compared to U.S. $236.0 million during the same period in 2013, an increase of U.S. $142.2 million. For the twelve months ended December 31, 2014, natural gas purchases totalled U.S. $234.8 million, as compared to U.S. $144.5 million for the same period in 2013, an increase of U.S. $90.3 million. The cost of natural gas is passed through to the natural gas distribution systems' customers. As a result, ‘net utility sales’ (see non-GAAP Financial Measures) are a more appropriate measure of results. For the twelve months ended December 31, 2014, net utility sales, excluding transportation, for the natural gas distribution systems totalled U.S. $143.4 million, as compared to U.S. $91.5 million during the same period in 2013, an increase of U.S. $51.9 million, or 57%. The increase is attributed as follows: U.S. $30.5 million increase from the New England Gas System, which was acquired on December 20, 2013; U.S. $4.5 million increase from the EnergyNorth Gas System, primarily due to the colder winter weather experienced during the first quarter of 2014, as compared to the first quarter of 2013; U.S. $15.1 million increase from the Peach State Gas System; primarily attributed to the inclusion of twelve months of operating results in 2014, as compared to nine months in 2013; increased rates as a result of the GRAM filing at the Peach State Gas System; and a U.S. $1.8 million increase from the Midstates Gas Systems due to the colder winter weather experienced during the first quarter of 2014, as compared to the first quarter of 2013.
For the twelve months ended December 31, 2014, revenue from gas transportation sales totalled U.S. $23.5 million, as compared to U.S. $16.8 million during the same period in 2013, an increase of U.S. $6.7 million. The increase in gas transportation sales can be primarily attributed to the acquisition of the New England Gas System on December 20, 2013, which contributed U.S. $6.1 million of the total increase.
|
| | | | | |
| Water and Wastewater Distribution Systems | Twelve months ended December 31, |
| | 2014 | | 2013 |
| Average Active Connections For The Period | | | |
| Wastewater connections | 39,000 |
|
| 36,600 |
|
| Water distribution connections | 58,000 |
|
| 55,800 |
|
| Total Average Active Connections For The Period | 97,000 |
| | 92,400 |
|
| | | | |
| Gallons Provided | | | |
| Wastewater treated (millions of gallons) | 2,127 |
|
| 2,034 |
|
| Water sold (millions of gallons) | 8,310 |
|
| 8,162 |
|
| Total Gallons Provided | 10,437 |
| | 10,196 |
|
|
| |
| 2014 Annual Report | 29 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
Average active wastewater and water distribution connections increased primarily due to the acquisition of the White Hall Water and Sewer System on May 30, 2014.
During the twelve months ended December 31, 2014, the water and wastewater distribution systems provided approximately 8,310 million gallons of water to its customers and treated approximately 2,127 million gallons of wastewater, as compared to 8,162 million gallons of water and 2,034 million gallons of wastewater during the same period in 2013. The increase in water sold can be primarily attributed to the acquisition of the White Hall Water System on May 30, 2014, and an additional month of operations from the Pine Bluff Water System in the first twelve months of 2014, as compared to the first twelve months of 2013. The increase in wastewater treated is primarily attributed to an increase in wastewater treated at our sewer utilities located in the state of Arizona.
For the twelve months ended December 31, 2014, revenue from wastewater treatment and water distribution totalled U.S. $26.1 million and U.S. $32.6 million, respectively, as compared to U.S. $24.3 million and U.S. $31.3 million, respectively, during the same period in 2013. Increased rates at the LPSCo Water and Sewer System, effective May 1, 2013, Rio Rico Water System, effective August 1, 2013, and Woodmark Waste System, effective October 1, 2013, are the primary drivers of the increase along with the acquisition of the White Hall Water System on May 30, 2014.
Other Revenue
For the twelve months ended December 31, 2014, other revenue totalled U.S. $5.1 million, as compared to U.S. $1.2 million during the same period in 2014. The other revenue consists of water heater rental service and a contract to supply gas to Fort Benning.
Operating Expenses
For the twelve months ended December 31, 2014, operating expenses, excluding electricity purchases, totalled U.S. $162.7 million, as compared to U.S. $127.5 million during the same period in 2013, an increase of U.S. $35.2 million, or 28%. The major factors resulting in the increase in DBG operating expenses in the twelve months ended December 31, 2014, as compared to the corresponding period in 2013, are set out as follows:
|
| | | |
| (all dollar amounts in U.S. $ millions) | Year to date December 31, 2014 |
| Comparative Prior Period Operating Expenses | $ | 127.5 |
|
| | |
| Significant Changes: | |
| Acquisition of New England Gas System | 26.3 |
|
| Increase in operating expenses at the Granite State Electric System and EnergyNorth Gas System | 4.6 |
|
| Increase in operating expenses at the Peach State Gas System | 2.2 |
|
| Increase in operating expenses at the Midstates Gas Systems | 0.8 |
|
| Acquisition of White Hall Water System | 0.5 |
|
| Other | 0.8 |
|
| Current Period Operating Expenses | $ | 162.7 |
|
The primary reason for the increase in operating expenses for the twelve months ended December 31, 2014, as compared to the corresponding period in 2013, was the acquisition of the New England Gas System on December 20, 2013. The full year of operating expenses, as compared to eleven days of operating expenses in 2013, contributed an additional U.S. $26.3 million.
Operating expenses at the Granite State Electric and EnergyNorth Gas Systems were U.S. $4.6 million higher than the prior fiscal year, primarily due to increased bad debt expense in the first nine months of the year, a property tax assessment related to a prior assessment year, and additional work for leak repairs.
The increase in operating expenses at the Peach State Gas System of U.S. $2.2 million was primarily due to twelve months of operation during the twelve months ended December 31, 2014, as compared to nine months of operation during the nine months ended December 31, 2013. The Peach State Gas System was acquired on April 1, 2013.
The increase in operating expenses at the Midstates Gas Systems of U.S. $0.8 million can be primarily attributed due to increased costs for billings services and communication expenses.
The acquisition of the White Hall Water System on May 30, 2014 resulted in an increase in operating expenses of U.S. $0.5 million during the twelve months ended December 31, 2014.
|
| |
| 2014 Annual Report | 30 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
Regulatory Proceedings
The following table summarizes the major regulatory proceedings within the Distribution Group currently underway:
|
| | | | |
| Utility | State | Regulatory Proceeding Type | Rate Request U.S. $ (millions) | Current Status |
| Completed Rate Cases | | | | |
| Granite State Electric System | New Hampshire | General Rate Case | $13,000 | Final Order issued on March 2014 approving a $9.8 million rate increase effective April 1, 2014. |
| Granite State Electric System | New Hampshire | General Rate Case - Step Adjustment | $1,200 | Final Order issued on March 2014 approving a $1.1 million in step increase for 2014 effective April 1, 2014 |
| Peach State Gas System | Georgia | GRAM | $4,900 | Final Order issued on May 2014 approving a $3.2 million rate increase retroactive to February 1, 2014, and the recovery of $1.7 million of carrying charges on deferred rate base in a future GRAM filing. |
| Peach State Gas System | Georgia | GRAM | $3,900 | Final Order issued on December 2014 approving a $3.7 million rate increase effective February 1, 2015. |
| LPSCo Water System | Arizona | General Rate Case | $3,000 | Final Order issued on April 2014 approving a $1.8 million rate increase effective May 1, 2014. |
| Missouri Gas System | Missouri | General Rate Case | $7,600 | Final Order issued on December 2014 approving a $4.9 million rate increase effective January 2, 2015. |
| Illinois Gas System | Illinois | General Rate Case | $5,700 | Final Order issued on February 11, 2015 approving a $4.6 million revenue increase effective February 20, 2015. |
| Pending Rate Cases | | | | |
| Pine Bluff Water System | Arkansas | General Rate Case | $2,500 | Application was filed on July 2, 2014; Order expected in Q2 2015 |
| EnergyNorth System | New Hampshire | General Rate Case | $16,100 | Application filed on August 1, 2014; a temporary rate increase was approved on November 21, 2014 allowing a $7.4M interim increase effective December 1, 2014, retroactive to November 1, 2014 upon approval of permanent rates. A final permanent rates decision is expected in Q3 2015. |
Completed Rate Cases
In the first quarter of 2013, the Granite State Electric System filed a rate case with the New Hampshire Public Utilities Commission ("NHPUC") seeking an increase in rates of U.S. $13.0 million, and an additional U.S. $1.2 million increase in 2014 subject to the completion of certain capital projects. On March 17, 2014, the commission approved a settlement of U.S. $9.8 million and U.S. $1.1 million step increase for 2014.
|
| |
| 2014 Annual Report | 31 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
On October 1, 2013, the Peach State Gas System filed an application for an increase in revenue of U.S. $4.9 million in its annual GRAM filing with the GPSC. In January 2014, the Distribution Group and the Staff of the GPSC agreed to a settlement which will provide an annual revenue increase of U.S. $3.2 million, and the recovery of U.S. $1.7 million of carrying charges on deferred rate base in a future GRAM filing. Commission approval was received in May 2014, with new rates effective as of June 1, 2014.
On October 1, 2014, the Peach State Gas System filed an application for an increase in revenue of U.S. $3.9 million in its annual GRAM filing with the GPSC. New rates to be effective February 1, 2015 for the period February 1, 2015, through January 31, 2016 were to reflect changes in revenue levels and cost of service. The GRAM uses a 12 month base period ending June 30, 2014 (Historic Test Year) with adjustments for the 12 months ending August 31, 2015 (Forward Looking Test Year). Commission approval was received on December 2, 2014.
On February 28, 2013, LPSCo Water System filed a general rate case with the Arizona Corporation Commission related to the LPSCo Water System sought, among other things, an increase in EBITDA by U.S. $3.0 million over the 2012 results if approved as filed. The application sought recognition of increased capital investment and increased operating expenses over current rates. In addition to a revenue increase, the application sought an accelerated infrastructure recovery surcharge, a purchased power pass-through mechanism to recover power price increases between test years, a property tax accounting deferral to defer increases in property taxes between test years, and a policy statement on rate design to begin the gradual shift of moving more revenue recovery to fixed charges versus commodity charges. In April 2014 the commission approved a $1.8 million increase in rates effective on May 1, 2014.
On February 6, 2014, the Midstates Gas System filed a rate case with the Missouri Public Service Commission ("MOPSC") seeking an increase in revenue of U.S. $7.6 million, consisting of U.S. $6.3 million in new, incremental revenue and U.S. $1.3 million through the ISRS surcharge (infrastructure system replacement surcharge). The filing is based on a test year ending September 30, 2013, with revenues, expenses and rate bases adjusted to reflect known and measurable changes through April 30, 2014. The case has concluded and an Order was issued on December 3, 2014, approving a U.S. $4.9 million revenue increase effective January 2, 2015.
On March 31, 2014, the Midstates Gas System filed a rate case with the Illinois Commerce Commission ("ICC") seeking an increase in EBITDA of U.S. $5.7 million. The filing is based on a test year that includes anticipated capital expenditures within 2014 and 2015. The case has concluded and an Order was issued on February 11, 2015, approving a U.S. $4.6 million revenue increase effective February 20, 2015.
Pending Rate Cases
On July 2, 2014, Pine Bluff Water System filed an application with the Arkansas Public Service Commission ("APSC") seeking an increase in revenue of U.S. $2.5 million based on a test year ending January 31, 2014, with pro forma changes to certain operating expenses and rate base capital additions. The previous test year ended September 30, 2009. An Order and new rates are expected in the second quarter of 2015.
On August 1, 2014, the EnergyNorth Natural Gas System in New Hampshire filed an application for an increase in revenue of U.S. $16.1 million, or approximately 9.6%. The application includes a revenue decoupling proposal and seeks recovery of capital costs related to the conversion of the system to the Distribution Group ownership. Expected implementation of the new permanent rates is in the third quarter of 2015. A temporary rate increase was approved on November 21, 2014 allowing a U.S. $7.4 million interim rate increase effective December 1, 2014, retroactive to November 2014 upon approval of permanent rates.
Acquisition Approval Applications
On September 19, 2014, the Distribution Group announced the entering into an agreement with Western Water Holdings, a wholly-owned investment of Carlyle Infrastructure, to acquire the regulated water distribution utility Park Water Company (“Park Water System”). Park Water System owns and operates three regulated water utilities engaged in the production, treatment, storage, distribution, and sale of water in Southern California and Western Montana. The three utilities collectively serve approximately 74,000 customer connections and have more than 1,000 miles of distribution mains.
The acquisition requires the approval of both the California Public Utilities Commission ("CPUC") and the Montana Public Service Commission ("MPSC"). An approval application was filed on November 24, 2014 with the CPUC seeking approval for APUC, through its wholly owned subsidiary Liberty Utilities Co., to acquire the two water utilities located in California owned by the Park Water Company, Park Central Basin and Apple Valley Ranchos Water. A decision on the California application is expected in the third quarter of 2015. An approval application was also filed on December 15, 2014 with the MPSC seeking approval for APUC, through its wholly owned subsidiary Liberty Utilities Co., to effectively acquire Mountain Water Company. A decision on the application is expected in the fourth quarter of 2015.
Mountain Water Company is the water utility in Western Montana owned by Park Water Company which serves the municipality of Missoula. Mountain Water Company is currently the subject of a condemnation proceeding by the city of Missoula (See “Regulatory Risk”).
|
| |
| 2014 Annual Report | 32 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
TRANSMISSION BUSINESS GROUP
In 2014, APUC created the Transmission Group which the Company believes complements the growth of the Generation and Distribution Groups. The Transmission Group is responsible for identifying, evaluating, and capitalizing upon natural gas pipeline and electric transmission asset opportunities in North America.
For its first major project on November 24, 2014, the Transmission Group announced an agreement to participate in a natural gas pipeline transmission project in partnership with Kinder Morgan, Inc. Specifically, Kinder Morgan Operating L.P. “A,” a wholly owned subsidiary of Kinder Morgan, Inc., and Liberty Utilities (Pipeline & Transmission) Corp., a wholly owned subsidiary of APUC, have agreed to form a new entity ("Northeast Expansion LLC") to undertake the development, construction and ownership of a 30-inch or 36-inch natural gas transmission pipeline to be located between Wright, NY and Dracut, MA (the “Project”), which will be operated by Tennessee Gas Pipeline Company, L.L.C. (“Tennessee”). The Project is scalable up to 2.2 billion cubic feet per day (Bcf/d), and the pipeline capacity will be contracted with local distribution utilities, and other customers, to help ease constraints on natural gas supply in the northeast U.S. and help ensure much needed reliability to the power-generation grid. It is anticipated that Tennessee will receive a FERC certificate in the fourth quarter of 2016, with construction anticipated to begin in January 2017 and commercial operations expected by Nov. 1, 2018.
Under the agreement, APUC will initially subscribe for a 2.5% interest in Northeast Expansion LLC. APUC also has an opportunity to increase its participation up to 10%. The total capital investment opportunity for APUC could be up to U.S. $400 million, depending on the final pipeline configuration and design capacity.
The U.S. $3-$4 billion infrastructure project consists of 188 miles of pipeline and six new compressor stations to be constructed through the states of New York, Massachusetts and New Hampshire. The pipeline is designed to provide up to 2.2 Bcf/day of firm gas deliveries to gas distribution utilities, gas fired generation, industrial customers and other New England consumers. Given the proposed route of the project, the Distribution Group will also look to economically expand its gas distribution utility footprint in New Hampshire as well to serve over twenty new communities with natural gas service.
Under the current September 15, 2014 application before the FERC under Docket No. PF 14 - 22, the project sponsor has proposed the following development calendar of events for proceeding with the project:
|
| |
1st Draft of the Environmental Review | March 6, 2015 |
2nd Draft of the Environmental Review
| June 5, 2015 |
FERC Section 7 Certificate Application Filed
| September, 2015 |
FERC Section 7 Certificate Approval Received
| October 31, 2016 |
Targeted In- Service of Core NED Project
| November 1, 2018 |
The project route has recently been modified to address a number of comments raised by various stakeholders and is shown as the orange solid line on the map below and has been filed with the FERC for further consideration.
Continued development of the project in 2015 will include ongoing environmental research, further outreach programs, development of procurement plans for long lead time items and continued marketing of available firm capacity prior to and following the September 2015 FERC application.
|
| |
| 2014 Annual Report | 33 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
APUC: CORPORATE AND OTHER EXPENSES
|
| | | | | | | | | | | | | | | |
| APUC: CORPORATE AND OTHER EXPENSES | Three months ended December 31, | | Year ended December 31, |
| (all dollar amounts in $ millions) | 2014 | | 2013 | | 2014 | | 2013 |
| Corporate and other expenses: | | | | | | | |
| Administrative expenses | $ | 10.5 |
| | $ | 5.2 |
| | $ | 34.7 |
| | $ | 23.5 |
|
| (Gain)/Loss on foreign exchange | 0.3 |
| | (0.1 | ) | | (1.1 | ) | | (0.6 | ) |
| Interest expense | 14.1 |
| | 14.4 |
| | 62.4 |
| | 53.4 |
|
Interest, dividend and other Income1 | 0.5 |
| | 0.7 |
| | 3.2 |
| | 2.5 |
|
| Write down of long lived assets | 0.3 |
| | — |
| | 8.5 |
| | — |
|
| Acquisition-related costs | 1.6 |
| | 0.6 |
| | 2.6 |
| | 2.1 |
|
| (Gain)/Loss on derivative financial instruments | 2.0 |
| | (2.7 | ) | | 1.4 |
| | (5.2 | ) |
| Income tax expense | 3.7 |
| | 5.2 |
| | 16.8 |
| | 9.2 |
|
|
| |
| 1 | Excludes income directly pertaining to the Generation and Distribution Groups (disclosed in the relevant sections). |
2014 Annual Corporate and Other Expenses
During the year ended December 31, 2014, administrative expenses totalled $34.7 million, as compared to $23.5 million in the same period in 2013. The expense increase for the period is primarily due to approximately $6.3 million of expenses previously classified as direct operating expenses that have been reclassified in 2014 as administrative expenses as certain functions are now being performed centrally as part of a shared services function across the entire company. The remaining $4.9 million increase primarily relates to additional costs incurred to administer APUC's operations as a result of the company's growth.
For the year ended December 31, 2014, interest expense totalled $62.4 million, as compared to $53.4 million in the same period in 2013. The increased interest expense is a result of new indebtedness incurred during the first half of 2014 used to partially finance new acquisitions and fund other growth initiatives.
For the year ended December 31, 2014, interest, dividend and other income totalled $3.2 million, as compared to $2.5 million in the same period in 2013, an increase of $0.7 million due to an incremental $2.5 million in rental income earned in 2014, partially offset by $1.8 million in decreased dividends from APUC’s share investment in the Kirkland and Cochrane Thermal Facilities.
For the year ended December 31, 2014, acquisition related costs totalled $2.6 million, as compared to $2.1 million in the same period in 2013. Acquisition related costs will vary from period to period depending on the level of activity and complexity associated with various acquisitions.
For the year ended December 31, 2014, loss on derivative financial instruments totalled $1.4 million, as compared to a gain of $5.2 million in the same period in 2013. The decrease was primarily driven by derivative losses on hedges to purchase electricity for resale at contracted rates that differ from the market rate.
An income tax expense of $16.8 million was recorded in the year ended December 31, 2014, as compared to an income tax expense of $9.2 million during the same period in 2013. The increase in income tax expense for the year ended December 31, 2014 is primarily due to increased earnings from operations, increased deferred taxes on HLBV income, a stronger U.S. dollar, and other items permanently non-deductible for tax purposes.
2014 Fourth Quarter Corporate and Other Expenses
During the quarter ended December 31, 2014, administrative expenses totalled $10.5 million, as compared to $5.2 million in the same period in 2013. The increase was primarily due to $3.9 million in additional costs incurred to administer APUC's operations as a result of the company's growth and $1.4 million of expenses previously classified as direct operating expenses that have been reclassified in 2014 as administrative expenses as certain functions are now being performed centrally as part of a shared services function across the entire company.
For the quarter ended December 31, 2014, interest expense totalled $14.1 million, as compared to $14.4 million in the same period in 2013. The decreased interest expense is a result of increased capitalization of interest expense due to the ongoing development projects during the end of period.
|
| |
| 2014 Annual Report | 34 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
For the quarter ended December 31, 2014, interest, dividend and other income totalled $0.5 million, as compared to $0.7 million in the same period in 2013. Interest, dividend and other income primarily consists of $0.7 million in rental income, partially offset by $0.3 million in decreased dividends from APUC’s share investment in the Kirkland and Cochrane Thermal Facilities.
For the quarter ended December 31, 2014, loss on derivative financial instruments totalled $2.0 million, as compared to a gain of $2.7 million in the same period in 2013. The decrease was primarily driven by derivative losses on hedges to purchase electricity for resale at contracted rates that differ from the market rate.
An income tax expense of $3.7 million was recorded in the three months ended December 31, 2014, as compared to an income tax expense of $5.2 million during the same period in 2013. The decrease in income tax expense for the quarter ended December 31, 2014 is primarily due to a reversal of an alternative minimum tax liability accrued in prior year, which is no longer a liability based on the amended legislation in the Internal Revenue Code, offset by increased earnings from operations, increased deferred taxes on HLBV income, and a stronger U.S. dollar.
NON-GAAP PERFORMANCE MEASURES
Reconciliation of Adjusted EBITDA to net earnings
The following table is derived from and should be read in conjunction with the audited 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 December 31, | | Year ended December 31, |
| (all dollar amounts in $ millions) | 2014 | | 2013 | | 2014 | | 2013 |
| Net earnings attributable to Shareholders | $ | 31.6 |
| | $ | 13.2 |
| | $ | 75.7 |
| | $ | 20.3 |
|
| Add (deduct): | | | | | | | |
| Net earnings / (loss) attributable to the non-controlling interest, exclusive of HLBV | 0.5 |
| | 3.4 |
| | 5.0 |
| | 9.6 |
|
| Loss from discontinued operations | 1.5 |
| | 6.7 |
| | 2.1 |
| | 42.0 |
|
| Income tax expense | 3.7 |
| | 5.2 |
| | 16.8 |
| | 9.2 |
|
| Interest expense | 14.1 |
| | 14.4 |
| | 62.4 |
| | 53.4 |
|
| Loss / (Gain) on sale of assets | (0.1 | ) | | 0.6 |
| | (0.4 | ) | | 0.8 |
|
| Non-cash write downs | 0.3 |
| | — |
| | 8.5 |
| | — |
|
| Acquisition costs | 1.6 |
| | 0.6 |
| | 2.6 |
| | 2.1 |
|
| (Gain) / Loss on derivative financial instruments | 2.0 |
| | (2.7 | ) | | 1.4 |
| | (5.2 | ) |
| Realized gain / (loss) on energy derivative contracts | (0.2 | ) | | 0.3 |
| | 3.6 |
| | 0.5 |
|
| (Gain) / Loss on foreign exchange | 0.3 |
| | (0.1 | ) | | (1.1 | ) | | (0.6 | ) |
| Depreciation and amortization | 29.0 |
| | 26.9 |
| | 114.0 |
| | 96.0 |
|
| Adjusted EBITDA | $ | 84.3 |
| | $ | 68.5 |
| | $ | 290.6 |
| | $ | 228.1 |
|
Hypothetical Liquidation at Book Value (“HLBV”) represents the value of net tax attributes earned by the Generation Group in the period from electricity generated by certain of its U.S. wind power generation facilities. The value of net tax attributes earned in the three and twelve months ended December 31, 2014 amounted to approximately $8.9 million and $27.2 million, respectively.
For the year ended December 31, 2014, Adjusted EBITDA totalled $290.6 million, as compared to $228.1 million during the same period in 2013, an increase of $62.5 million. For the quarter ended December 31, 2014, Adjusted EBITDA totalled $84.3 million, as compared to $68.5 million, an increase of $15.8 million compared to the same period in 2013.
The major factors impacting Adjusted EBITDA are set out below. A more detailed analysis of these factors is presented within the business unit analysis.
|
| |
| 2014 Annual Report | 35 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
|
| | | | | | | |
| (all dollar amounts in $ millions) | Quarter ended December 31, 2014 | | Year ended December 31, 2014 |
| Comparative Prior Period Adjusted EBITDA | $ | 68.5 |
| | $ | 228.1 |
|
| Significant Changes: | | | |
| Generation Business Group: | | | |
| Renewable | | | |
| Increase / (decreased) hydrology resource | 2.2 |
| | (2.0 | ) |
| Decreased/increased wind resources for the quarter/year to date, at the U.S. Wind Facilities offset by unfavorable periodic hedge settlements shortfalls at the Minonk, Sandy Ridge and Senate facilities | 3.2 |
| | 2.8 |
|
| Higher realized prices on sale of Renewable Energy Credits at the U.S. Wind Facilities | 1.1 |
| | 4.9 |
|
| Start of commercial operations for the Cornwall Solar Facility | 0.3 |
| | 4.8 |
|
| Increased wind resources at the St Leon wind facilities | 0.3 |
| | 3.1 |
|
| Unfavorable retail pricing at AES partially offset by gains from hedge settlements and increased customer load. | 1.2 |
| | (1.8 | ) |
| Thermal | | | |
| Increased market prices at the Sanger and Windsor Locks Thermal Facility | 0.3 |
| | 1.3 |
|
| Higher realized prices on sale of Renewable Energy Credits | (0.1 | ) | | 0.7 |
|
| Distribution Business Group: | | | |
| Increased delivery and treatment of water and wastewater systems | 0.7 |
| | 3.2 |
|
| Increased rates at the Granite State Electric System | 1.4 |
| | 10.2 |
|
| Changes in customer demand and higher operating expenses at the EnergyNorth and the Midstates Gas Systems | 1.8 |
| | 1.9 |
|
| 2013 Acquisition of the New England and Peach State Gas Systems | 2.5 |
| | 23.6 |
|
| Increase earnings due to acquisition of New England Gas System's water heater rental service and the Peach State Gas System's Fort Benning operation | 1.8 |
| | 3.8 |
|
| Administrative expense | (5.4 | ) | | (11.2 | ) |
| Increased results from the stronger U.S. dollar | 6.6 |
| | 18.4 |
|
| Other | (2.1 | ) | | (1.2 | ) |
| Current Period Adjusted EBITDA | $ | 84.3 |
| | $ | 290.6 |
|
|
| |
| 2014 Annual Report | 36 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
Reconciliation of adjusted net earnings to net earnings
The following table is derived from and should be read in conjunction with the audited 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.
The following table shows the reconciliation of net earnings to adjusted net earnings exclusive of these items:
|
| | | | | | | | | | | | | | | |
| | Three months ended December 31, | | Year ended December 31, |
| (all dollar amounts in $ millions) | 2014 | | 2013 | | 2014 | | 2013 |
| Net earnings attributable to Shareholders | $ | 31.6 |
| | $ | 13.2 |
| | $ | 75.7 |
| | $ | 20.3 |
|
| Add (deduct): | | | | | | | |
| (Gain) / Loss from discontinued operations, net of tax | 1.5 |
| | 6.7 |
| | 2.1 |
| | 42.0 |
|
| (Gain) / Loss on derivative financial instruments, net of tax | 1.2 |
| | (1.6 | ) | | 0.8 |
| | (3.1 | ) |
| Realized gain / (loss) on derivative financial instruments, net of tax | (0.5 | ) | | (0.2 | ) | | 0.7 |
| | (1.2 | ) |
| Write down long lived assets | 0.3 |
| | — |
| | 8.5 |
| | — |
|
| (Gain) / Loss on asset disposal, net of tax | (0.1 | ) | | 0.4 |
| | (0.3 | ) | | 0.5 |
|
| (Gain) / Loss on foreign exchange, net of tax | 0.2 |
| | (0.1 | ) | | (0.7 | ) | | (0.3 | ) |
| Acquisition costs, net of tax | 1.0 |
| | 0.4 |
| | 1.6 |
| | 1.3 |
|
| Adjusted net earnings | $ | 35.2 |
| | $ | 18.8 |
| | $ | 88.4 |
| | $ | 59.5 |
|
| Adjusted net earnings per share | $ | 0.14 |
| | $ | 0.08 |
| | $ | 0.37 |
| | $ | 0.26 |
|
For the year ended December 31, 2014, adjusted net earnings totalled $88.4 million, as compared to adjusted net earnings of $59.5 million, an increase of $28.9 million as compared to the same period in 2013. The increase in adjusted net earnings for the year ended December 31, 2014 is primarily due to higher income from operations partially offset by higher interest expense, and depreciation and amortization expense as compared to the same period in 2013.
For the three months ended December 31, 2014, adjusted net earnings totalled $35.2 million, as compared to adjusted net earnings of $18.8 million, an increase of $16.4 million as compared to the same period in 2013. The increase in adjusted net earnings for the three months ended December 31, 2014 is primarily due to increased earnings from operations partially offset by higher depreciation and amortization expense, and higher interest expense as compared to the same period in 2013.
|
| |
| 2014 Annual Report | 37 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
Reconciliation of adjusted funds from operations to cash flows from operating activities
The following table is derived from and should be read in conjunction with the audited Consolidated Statement of Operations and Statement of Cash Flows. This supplementary disclosure is intended to more fully explain disclosures related to adjusted funds from operations 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 funds from operations in accordance with GAAP.
The following table shows the reconciliation of funds from operations to adjusted funds from operations exclusive of these items:
|
| | | | | | | | | | | | | | | |
| | Three months ended December 31, | | Year ended December 31, |
| (all dollar amounts in $ millions) | 2014 | | 2013 | | 2014 | | 2013 |
| Cash flows from operating activities | $ | 96.5 |
| | $ | 28.4 |
| | $ | 192.7 |
| | $ | 98.9 |
|
| Add (deduct): | | | | | | | |
| Changes in non-cash operating items | (33.1 | ) | | 13.5 |
| | 0.5 |
| | 47.8 |
|
| Cash (provided)/used in discontinued operation | 0.9 |
| | 3.5 |
| | 1.7 |
| | 4.4 |
|
| Production Tax Credits received from non-controlling interests | — |
| | — |
| | 9.0 |
| | 1.7 |
|
| Acquisition costs | 1.6 |
| | 0.6 |
| | 2.6 |
| | 2.1 |
|
| Adjusted funds from operations | $ | 65.9 |
| | $ | 46.0 |
| | $ | 206.5 |
| | $ | 154.9 |
|
| Adjusted funds from operations per share | 0.27 |
| | 0.22 |
| | 0.92 |
| | 0.73 |
|
For the year ended December 31, 2014, adjusted funds from operations totalled $206.5 million, as compared to adjusted funds from operations of $154.9 million, an increase of $51.6 million as compared to the same period in 2013.
For the three months ended December 31, 2014, adjusted funds from operations totalled $65.9 million, as compared to adjusted funds from operations of $46.0 million, an increase of $19.9 million as compared to the same period in 2013.
SUMMARY OF PROPERTY, PLANT, AND EQUIPMENT EXPENDITURES |
| | | | | | | | | | | | | | | |
| | Three months ended December 31, | | Year ended December 31, |
| (all dollar amounts in $ millions) | 2014 | | 2013 | | 2014 | | 2013 |
| GENERATION GROUP | | | | | | | |
| Renewable | $ | 59.6 |
| | $ | 18.0 |
| | $ | 197.1 |
|
| $ | 46.9 |
|
| Thermal | 0.5 |
| | 1.3 |
| | 4.0 |
|
| 2.6 |
|
| Total Generation Business Group | $ | 60.1 |
| | $ | 19.3 |
| | $ | 201.1 |
|
| $ | 49.5 |
|
|
|
| |
|
| |
|
|
|
|
|
| DISTRIBUTION GROUP | $ | 77.4 |
| | $ | 43.4 |
| | $ | 176.8 |
|
| $ | 108.9 |
|
|
|
| |
|
| |
|
|
|
|
|
| Corporate | 4.3 |
| | — |
| | 54.5 |
|
| — |
|
| Total | $ | 141.8 |
| | $ | 62.7 |
| | $ | 432.4 |
|
| $ | 158.4 |
|
The company's consolidated capital expenditure plan for 2015 is approximately $261.0 million. The Generation Group expects to invest approximately $107.0 million primarily in connection with the development of its existing project pipeline. The Distribution Group expects to invest approximately $147.0 million primarily to improve the reliability and efficiency of its gas and electric utility distribution systems. The Transmission Group expects to invest approximately $7.0 million for the natural gas pipeline transmission project.
APUC anticipates that it can generate sufficient liquidity through internally generated operating cash flows, revolving credit facilities, as well as the debt and equity capital markets to finance its property, plant and equipment expenditures and other commitments.
|
| |
| 2014 Annual Report | 38 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
2014 Twelve Month Property Plant and Equipment Expenditures
During the twelve months ended December 31, 2014, the Generation Group incurred capital expenditures of $201.1 million, as compared to $49.5 million during the comparable period in 2013.
During the twelve months ended December 31, 2014, the Generation Group’s Renewable Energy Division spent $197.1 million in capital expenditures, as compared to $46.9 million in the comparable period in 2013. The capital expenditures primarily relate to the completion of the Cornwall Solar and St. Damase Wind Facilities, and the construction of the Bakersfield Solar and Morse Wind Projects. The Generation Group’s Thermal Energy Division net capital expenditures were $4.0 million, as compared to $2.6 million in the comparable period in 2013. The capital expenditures in the year were $1.2 million at Windsor Locks and $2.8 million at Sanger.
During the twelve months ended December 31, 2014, the Distribution Group invested $176.8 million in capital expenditures, as compared to $108.9 million during the comparable period in 2013. The capital expenditures primarily relate to the completion of a second supply line, reliability enhancements, and new business projects at the Granite State Electric System; improvement and replenishment opportunities at the CalPeco Electric System; leak prone pipe replacements, leak repairs and pipeline corrosion protection systems relating to enhancing safety and reliability at the EnergyNorth, Midstates, New England, and Peach State Gas Systems; and improvement, replenishment and new business projects at the water and wastewater utilities located in Arizona and at the Pine Bluff Water System.
2014 Fourth Quarter Property Plant and Equipment Expenditures
During the three months ended December 31, 2014, the Generation Group incurred capital expenditures of $60.1 million, as compared to $19.3 million during the comparable period in 2013. During the three months ended December 31, 2014, the Generation Group’s Renewable Energy Division spent $59.6 million in capital expenditures, as compared to $18.0 million in the comparable period in 2013. The capital expenditures primarily relate to completion of construction at the St. Damase Wind Facility and the continued construction at the Bakersfield Solar Project. The Generation Group’s Thermal Energy Division net capital expenditures were $0.5 million, as compared to $1.3 million in the comparable period in 2013. The 2014 thermal capital expenditures consist of $0.4 million relating to Windsor Locks Thermal Facility and $0.1 million relating to Sanger Thermal Facility.
During the three months ended December 31, 2014, the Distribution Group invested $77.4 million in capital expenditures, as compared to $43.4 million during the comparable period in 2013. The Distribution Group’s investment was primarily related to reliability enhancements, and new business projects at the Granite State Electric System; improvement and replenishment opportunities at the CalPeco Electric System; leak prone pipe replacements, leak repairs and pipeline corrosion protection systems relating to enhancing safety and reliability at the EnergyNorth, Midstates, New England, and Peach State Gas Systems; and improvement, replenishment and new business projects at the water and wastewater utilities located in Arizona and at the Pine Bluff Water System.
Quebec Dam Safety Act
As a result of the dam safety legislation passed in Quebec (Bill C-93), the Generation Group has completed technical assessments on its hydroelectric facility dams owned or leased within the Province of Quebec. Out of these, nine assessments have been submitted to and accepted by the Quebec government. The assessments have identified possible remedial work at seven facilities. Of these seven, remediation work has now been completed at three facilities, monitoring activities and options analysis are being performed for two facilities, and remedial work is being planned at two facilities.
The Generation Group currently estimates further capital expenditures of approximately $7.9 million related to compliance with the legislation. It is anticipated that these expenditures will be invested over a period of several years approximately as follows:
|
| | | | | | | | | | | |
| (all dollar amounts in $ millions) | Total | 2015 | 2016 | 2017 | 2018 |
| Future Estimated Bill C-93 Capital Expenditures | $ | 7.9 |
| 1.0 |
| 3.1 |
| 3.5 |
| 0.3 |
|
The majority of these capital costs are associated with the Belleterre, Rivière-du-Loup, and St. Alban Hydro Facilities.
The Generation Group is presently working with the provincial authorities to reclassify, decommission or remove several small dams upstream of the Belleterre Hydro Facility that are not required for power generation. The Generation Group anticipates completion of any required work on these dams by 2017.
Engineering for the Riviere-du-Loup Hydro Facility was completed in 2012. Following additional geotechnical investigation in 2014, the remediation work is now estimated at $1.1 million. Completion of the remedial work is anticipated in 2015.
|
| |
| 2014 Annual Report | 39 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
The dam safety study and a detailed condition assessment for the St. Alban Hydro Facility have been completed. The Generation Group anticipates engineering and regulatory review for the remediation of the main dam to be completed in 2015, with remedial work in 2016 to 2017.
On May 18, 2014, the Donnacona Hydro Facility experienced ice damage during the spring thaw and has been shut down. The Generation Group had previously planned capital expenditures for the Donnacona Hydro Facility in 2015 and 2016 in the amount of $7.8 million. It has been determined, in consultation with its 3rd party engineers, that a dam re-build is required to return the facility to operation. The Generation Group is currently evaluating environmental permitting and rebuild scenarios. Consequently, the Generation Group does not anticipate any near-term expenditures related to Bill C-93 compliance of the existing structure.
In addition to the Bill C-93 related dam remediation work, the Generation Group has implemented a dam condition monitoring program at some of the above facilities following recommendations specified in the dam safety reviews.
LIQUIDITY AND CAPITAL RESERVES
APUC has revolving operating facilities available for APUC, the Generation Group and the Distribution Group to manage the liquidity and working capital requirements of each division (collectively the “Facilities”).
Bank Credit Facilities
The following table sets out the amounts drawn, letters of credit issued and outstanding amounts available to APUC and its operating groups as at December 31, 2014 under the Facilities:
|
| | | | | | | | | | | | | | | | | | | |
| | As at December 31, 2014 | | As at Dec 31
2013 |
| (all dollar amounts in $ millions) | Corporate | | Generation Group | | Distribution Group | | Total | | Total |
| Committed Facilities | $ | 65.0 |
| | $ | 350.0 |
| | $ | 232.0 |
| | $ | 647.0 |
| | $ | 477.7 |
|
| Funds drawn on Facilities | — |
| | (23.4 | ) | | (23.9 | ) | | (47.3 | ) | | (210.2 | ) |
| Letters of Credit issued | (10.8 | ) | | (96.0 | ) | | (7.0 | ) | | (113.8 | ) | | (64.9 | ) |
| Funds available for draws on the Facilities | $ | 54.2 |
| | $ | 230.6 |
| | $ | 201.1 |
| | $ | 485.9 |
| | $ | 202.6 |
|
| Cash on Hand |
| |
| |
| | 9.3 |
| | 13.8 |
|
| Total liquidity and capital reserves | $ | 54.2 |
| | $ | 230.6 |
| | $ | 201.1 |
| | $ | 495.2 |
| | $ | 216.4 |
|
As at December 31, 2014, the Company's $65.0 million senior unsecured revolving credit facility (the "Corporate Credit Facility"), was undrawn and had $10.8 million of outstanding letters of credit. The facility matures on November 19, 2016 and is subject to customary covenants.
As at December 31, 2014, the $350.0 million Generation Credit Facility had drawn $23.4 million and had $96.0 million in outstanding letters of credit. On July 31, 2014, the Generation Group increased the credit available under its credit facility to $350 million from $200 million. The larger credit facility will be used to provide additional liquidity in support of the group's $1,225.0 million development portfolio to be completed over the next four years. In addition to the larger size, the maturity of the credit facility has been extended from three to four years extending to July 31, 2018.
As at December 31, 2014, the Distribution Group's $232.0 million (U.S. $200.0 million) senior unsecured revolving credit facility (the "Distribution Credit Facility") had drawn $23.9 million (U.S. $20.6 million) and had $7.0 million (U.S. $6.0 million)of outstanding letters of credit. The facility matures on September 30, 2018 and is subject to customary covenants
Long Term Debt
On January 17, 2104, the Generation Group issued $200.0 million 4.65% senior unsecured debentures with a maturity date of February 15, 2022 (the "Generation Debentures") pursuant to a private placement in Canada and the United States. The Generation Debentures were sold at a price of $99.864 per $100.00 principal amount resulting in an effective yield of 4.67%. Concurrent with the offering, the Generation Group entered into a fixed for fixed cross currency swap, coterminous with the Generation Debentures, to economically convert the Canadian dollar denominated debentures into U.S. dollars, resulting in an effective interest rate throughout the term of approximately 4.77%.
On December 31, 2014, the U.S. $19.2 million senior debt for the Sanger Thermal Facility was repaid.
As at December 31, 2014, the weighted average tenor of APUC's total long term debt is approximately 8.0 years with an average interest rate of 4.9%.
|
| |
| 2014 Annual Report | 40 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
Contractual Obligations
Information concerning contractual obligations as of December 31, 2014 is shown below:
|
| | | | | | | | | | | | | | | | | | | |
| (all dollar amounts in $ millions) | Total | | Due less than 1 year | | Due 1 to 3 years | | Due 4 to 5 years | | Due after 5 years |
| Long-term debt obligations | $ | 1,280.0 |
| | 9.1 |
| | 91.0 |
| | 218.8 |
| | 961.1 |
|
| Advances in aid of construction | $ | 81.1 |
| | 1.1 |
| | — |
| | — |
| | 80.0 |
|
| Interest on long-term debt obligations | $ | 438.3 |
| | 64.2 |
| | 125.3 |
| | 102.1 |
| | 146.7 |
|
| Purchase obligations | $ | 267.9 |
| | 267.9 |
| |
|
| |
|
| |
|
|
| Environmental obligation | $ | 72.6 |
| | 19.6 |
| | 36.6 |
| | 6.1 |
| | 10.3 |
|
| Derivative financial instruments: | | | | | | | | | |
| Cross currency swap | $ | 36.3 |
| | 1.5 |
| | 3.0 |
| | 2.4 |
| | 29.4 |
|
| Interest rate forward | $ | 4.7 |
| | — |
| | — |
| | 4.7 |
| | — |
|
| Interest rate swap | $ | 1.4 |
| | 1.4 |
| | — |
| | — |
| | — |
|
| Energy derivative contracts | $ | 2.9 |
| | 2.3 |
| | 0.6 |
| | — |
| | — |
|
| Purchased power | $ | 118.2 |
| | 118.2 |
| | — |
| | — |
| | — |
|
| Gas delivery, service and supply agreements | $ | 264.3 |
| | 52.8 |
| | 68.0 |
| | 55.3 |
| | 88.2 |
|
| Long term service agreements | $ | 637.3 |
| | 28.6 |
| | 64.7 |
| | 62.9 |
| | 481.1 |
|
| Capital projects | $ | 22.0 |
| | 22.0 |
| | — |
| | — |
| | — |
|
| Operating leases | $ | 121.1 |
| | 5.6 |
| | 9.6 |
| | 8.5 |
| | 97.4 |
|
| Other obligations | $ | 40.5 |
| | 9.9 |
| | 0.9 |
| | — |
| | 29.7 |
|
| Total obligations | $ | 3,388.6 |
| | $ | 604.2 |
| | $ | 399.7 |
| | $ | 460.8 |
| | $ | 1,923.9 |
|
Equity
The common shares of APUC are publicly traded on the Toronto Stock Exchange (“TSX”). As at December 31, 2014, APUC had 238,149,468 issued and outstanding common shares.
APUC may issue an unlimited number of common shares. The holders of common shares are entitled to dividends, if and when declared; to one vote for each share at meetings of the holders of common shares; and to receive a pro rata share of any remaining property and assets of APUC upon liquidation, dissolution or winding up of APUC. All shares are of the same class and with equal rights and privileges and are not subject to future calls or assessments.
On September 16, 2014, APUC completed the offering of 16,860,000 common shares at a price of $8.90 per share, for gross proceeds of approximately $150.0 million. On September 26, 2014, the underwriters exercised the over-allotment option granted with the offering and an additional 2,529,000 common shares were issued on the same terms and conditions of the offering. As a result, APUC issued 19,389,000 common shares under the offering for the total gross proceeds of approximately $172.6 million.
On December 11, 2014, APUC completed a public offering of 10,055,000 common shares at a price of $9.95 per share, for gross proceeds of approximately $100.0 million.
APUC is also authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board. As at December 31, 2014, APUC had outstanding:
| |
| • | 4,800,000 cumulative rate reset Series A preferred shares, yielding 4.5% annually for the initial six-year period ending on December 31, 2018; |
| |
| • | 100 Series C preferred shares that were issued in exchange for 100 Class B limited partnership units by St. Leon Wind Energy LP; and |
| |
| • | 4,000,000 cumulative rate reset Series D preferred shares, yielding 5.0% annually for the initial five-year period ending on March 31, 2019. |
APUC has a shareholder dividend reinvestment plan (the “Reinvestment Plan”) for registered holders of shares of APUC. As at December 31, 2014, 63.8 million common shares representing approximately 27% of total shares outstanding had been
|
| |
| 2014 Annual Report | 41 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
registered with the Reinvestment Plan and 2,262,885 shares were issued during the year ended December 31, 2014. During the quarter ended December 31, 2014, 665,172 common shares were issued under the Reinvestment Plan, and subsequent to the end of the quarter, on January 15, 2015, an additional 706,680 common shares were issued under the Reinvestment Plan.
Emera subscription receipts
For the year ended December 31, 2014, APUC did not issue any common shares to Emera.
On October 7, 2014, the Company issued 8,708,170 Subscription Receipts of APUC at a purchase price of $8.90 per Subscription Receipt for an aggregate subscription price of $77.5 million. The investment was made under the Strategic Investment Agreement between Emera and APUC, in support of the acquisition by APUC of the Odell Wind Project in Minnesota (the “Odell Acquisition”). The proceeds of the subscription are intended to be used by APUC to partially finance the Odell Acquisition and the completion of the Odell Wind Project. Subject to adjustments as provided in the applicable subscription agreement, Emera may convert the Subscription Receipts into common shares of APUC on a one-for-one basis on November 14, 2015 (the first anniversary of the closing of the Odell Acquisition) or the commercial operation date of the Odell Wind Project, whichever is first to occur.
On December 2, 2014, the Corporation issued 3,316,583 subscription receipts of APUC at a purchase price of $9.95 per subscription receipt for an aggregate subscription price of $33.0 million. The investment was made under the Strategic Investment Agreement between Emera and APUC, in support of the acquisition by APUC of the Park Water Company in Montana (the “Park Water Acquisition”). The proceeds of the subscription are intended to be used by APUC to partially finance the Park Water Acquisition. Subject to adjustments as provided in the applicable subscription agreement, Emera may convert the Subscription Receipts into common shares of APUC on a one-for-one basis on December 29, 2015 (the first anniversary of the closing of the subscription transaction) or the closing of the Park Water Acquisition, whichever is first to occur.
Conversion of the aforementioned Subscription Receipts into common shares is conditional on Emera’s holdings not exceeding 25% of the outstanding common shares of APUC at the time of conversion.
As at March 15, 2015, in total, Emera owns 50,126,766 APUC common shares representing approximately 21.0% of the total outstanding common shares of the Company, and there are 12,024,753 subscription receipts currently held by Emera. APUC believes issuance of shares to Emera is an efficient way to raise equity as it avoids underwriting fees, legal expenses and other costs associated with raising equity in the capital markets.
SHARE BASED COMPENSATION PLANS
For the three and twelve months ended December 31, 2014, APUC recorded $1.1 million and $3.2 million, respectively, in total share-based compensation expense, as compared to $0.6 million and $2.0 million, respectively, for the same period in 2013. No tax deduction was realized in the current year. The compensation expense is recorded as part of administrative expenses in the Consolidated Statement of Operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.
As at December 31, 2014, total unrecognized compensation costs related to non-vested options and share unit awards were $2.1 million and $2.4 million, respectively, and are expected to be recognized over a period of 1.71 and 1.61 years, respectively.
Stock Option Plan
APUC has a stock option plan that permits the grant of share options to key officers, directors, employees and selected service providers. Except in certain circumstances, the term of an option shall not exceed ten (10) years from the date of the grant of the option.
APUC determines the fair value of options granted using the Black-Scholes option-pricing model. The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on a straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date. During the year, the Company issued 969,998 options to employees of the Company.
As at December 31, 2014, a total of 5,537,127 options had been issued and outstanding under the plan.
Performance Share Units
APUC issues performance share units (“PSUs”) to certain members of management other than senior executives as part of APUC’s long-term incentive program. The PSUs provide for settlement in cash or shares at the election of APUC.
|
| |
| 2014 Annual Report | 42 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
During the year, the Company settled 11,406 vested PSUs for $0.2 million in cash. The plan provides for settlement in cash or shares at the election of the Company. At the annual general meeting held on June 18, 2014, the shareholders approved a maximum of 500,000 shares issuable from Treasury to settle PSUs. With the ability to issue shares from Treasury or purchase shares on the market, the Company expects to settle the remaining PSUs in shares. As a result, the PSUs continue to be accounted for as equity awards. During the year, the Company issued 407,962 PSUs to executives and employees of the Company.
As at December 31, 2014, a total of 440,086 PSU's have been granted and outstanding under the PSU plan.
Directors Deferred Share Units
APUC has a Deferred Share Unit Plan. Under the plan, non-employee directors of APUC may elect annually to receive all or any portion of their compensation in deferred share units (“DSUs”) in lieu of cash compensation. The DSUs provide for settlement in cash or shares at the election of APUC. As APUC does not expect to settle the DSU’s in cash, these DSUs are accounted for as equity awards. During the year, the Company issued 35,455 DSUs to the directors of the Company.
As at December 31, 2014, a total of 110,241 DSUs had been granted under the DSU plan.
Employee Share Purchase Plan
APUC has an Employee Share Purchase Plan (the “ESPP”) which allows eligible employees to use a portion of their earnings to purchase common shares of APUC. The aggregate number of shares reserved for issuance from treasury by APUC under this plan shall not exceed 2,000,000 shares. During the year, the Company issued 93,598 common shares to employees under the ESPP plan.
As at December 31, 2014, a total of 240,411 shares had been issued under the ESPP.
MANAGEMENT OF CAPITAL STRUCTURE
APUC views its capital structure in terms of its debt and equity levels, at its individual operating groups and at an overall company level.
APUC’s objectives when managing capital are:
| |
| • | To maintain its capital structure consistent with investment grade credit metrics appropriate to the sectors in which APUC operates; |
| |
| • | 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 appropriately sized revolving credit facilities available for ongoing investment in growth and 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 groups are using a capital structure which is appropriate for their respective industries.
RELATED PARTY TRANSACTIONS
Ian Robertson and Chris Jarratt (“Senior Executives”), respectively Chief Executive Officer and Vice-Chair of APUC, are indirect shareholders of Algonquin Power Management Inc. (“APMI”), the former manager of the Company and several related affiliates (collectively the “Parties”). Prior to 2010, there were several related party transactions and co-owned assets which existed pursuant to the external management structure before the internalization of management which occurred on December 21, 2009.
In 2011, the Board formed an independent committee (“Independent Board Committee”) and initiated a process to review all of the remaining business associations with the Parties in order to reduce and/or eliminate these relationships. The Independent Board Committee engaged independent consultants and advisors to assist with this process and to provide advice in respect thereof. Specifically, the independent advisors provided advice to the Independent Board Committee in relation to the valuations of the generating assets, tax and legal matters.
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| |
| 2014 Annual Report | 43 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
The process, initiated in 2011, was completed in November 2013 and all related party transactions, except as noted below, between APUC and the Parties have been addressed to the satisfaction of the Independent Board Committee and the Board as discussed below.
The following describes the business associations and resolution with APMI and Senior Executives:
Due to and from related parties
Effective December 31, 2013, APUC paid the Parties $1.8 million in connection with outstanding fees and the Parties paid APUC $0.8 million in connection with reimbursement of expenses. As at December 31, 2014, $0.047 million (2013 - $0.047 million) remains due from Algonquin Power Systems Ltd., a corporation partially owned by the Senior Executives.
Equity interests in Rattle Brook Hydro, Long Sault Hydro, and BCI Thermal Facilities
The Parties own interests in three power generation facilities in which APUC also has an interest. A brief description of the facilities is provided as follows:
| |
| • | Rattle Brook is a 4 MW hydroelectric generating facility (“Rattle Brook”) constructed in 1998 in which APUC owns a 45% interest and Senior Executives hold an equity interest in the remaining 55%. |
| |
| • | Long Sault Hydro Facility is an 18MW hydroelectric generating facility constructed in 1997. APUC acquired its interest in Long Sault Hydro Facility by way of subscribing to two notes from the original partners. One of the original partners, an affiliate of APMI, is entitled to receive 5% of the equity cash flows commencing in 2014. |
| |
| • | Brampton Cogeneration ("BCI Thermal Facility") is an energy supply facility which sells steam produced by EFW. In 2004, APMI acquired 50 Class B partnership units in BCI Thermal Facility entitling them to 50% of the cash flow above 15% return on the investment. |
Effective December 31, 2013, APUC acquired the Parties’ shares of Algonquin Power Corporation Inc. ("APC") which owns the partnership interest in the 18MW Long Sault Hydro Facility and the partnership interest in the BCI Thermal Facility plant for an amount equal to $3.8 million. As APUC already consolidates Long Sault Hydro Facility as a VIE, the acquisition of this partnership interest was treated as an equity transaction. The payment resulted in an adjustment to deferred tax liability of $10.7 million in regards to tax attributes acquired with the partnership interests and an adjustment of $14.6 million to equity of the shareholders of the Company as the partnership interests had a nominal carrying amount prior to the exchange.
In addition, APUC sold its 45% interest in the 4 MW Rattle Brook Hydro Facility to the Parties for gross proceeds $3.4 million for a loss on sale, net of tax of $0.4 million.
APUC earned a fee of $0.4 million from APC during the year ended December 31, 2013 related to settlement of the related party transactions.
St. Leon LP Units
Third party investors, including Senior Executives, previously held 100 Class B limited partnership units issued by the St. Leon Limited Partnership, which is the legal owner of the St. Leon Wind Facility.
On January 1, 2013, the Company issued 100 redeemable Series C preferred shares and exchanged such shares for the 100 Class B units (note 11) including 36 units held indirectly by Senior Management. The Series C preferred shares provide dividends identical to what is expected from the Class B units, as determined by independent consultants retained by the Independent Board Committee. As of January 1, 2013, no Senior Executives have any further direct or indirect ownership of the St. Leon Wind Facility.
Office Facilities
APUC has leased its head office facilities since 2001 on a triple net basis from an entity partially owned by the Senior Executives. Base lease costs for the year ended December 31, 2014 were $0.3 million (2013 ‑ $0.3 million). In the fourth quarter of 2014, APUC moved all head office employees into new premises and terminated the related party lease for nominal consideration. There is no further related party matter in relation to an office lease.
Chartered Aircraft
As part of its normal business practice, APUC has utilized chartered aircraft when it is beneficial to do so and had previously entered into an agreement to charter aircraft in which the Senior Executives have a partial ownership. During the year ended December 31, 2013, APUC reimbursed direct costs in connection with the use of the aircraft of $0.5 million. As at December 31, 2013, the Independent Board Committee and the Parties agreed that all future utilization of chartered aircraft would be undertaken through a third-party charter operator at fair market value and under arrangements in which the Senior Executives have no interest. Final arrangements in this regard had not been completed as at December 31, 2014. During the year ended December 31, 2014, APUC reimbursed direct costs in connection with the use of the aircraft of $0.7 million.
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| 2014 Annual Report | 44 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
Trafalgar
The Company owns debt on seven hydroelectric facilities owned by Trafalgar Power Inc. and an affiliate (“Trafalgar”). In 1997, Trafalgar went into default under its debt obligations and an affiliate of APMI moved to foreclose on the assets. Subsequently, Trafalgar went into bankruptcy. APUC and the affiliate of APMI have been jointly involved in litigation and in bankruptcy proceedings with Trafalgar since 2004. APMI initially funded $2.0 million in legal fees prior to 2004.
In 2004, the Board reimbursed APMI $1.0 million of the total third party legal fees (which to that point totalled $2.0 million), and APUC agreed to fund future legal fees, third party costs and other liabilities. It was agreed that any net proceeds from the lawsuits would be shared proportionally to the quantum of net costs funded by each party.
A member of the Board is an executive at Emera. Related Party Transactions between APUC and Emera are discussed below:
| |
| • | For the year ended December 31, 2014, the Company sold electricity to Maine Public Service Company (“MPS”), a subsidiary of Emera, amounting to U.S. $5.8 million (2013 - U.S. $6.0 million ). In 2011, APUC provided a corporate guarantee to MPS in an amount of U.S. $3.0 million and a letter of credit in an amount of U.S. $0.1 million, primarily in conjunction with a three year contract to provide standard offer service to commercial and industrial customers in Northern Maine. For the year ended December 31, 2014, the Company purchased natural gas amounting to U.S. $5.0 million (2013 - U.S. $1.3 million) from Emera for its gas utility customers. Both the sale of electricity to Emera and the purchase of natural gas from Emera followed a public tender process, the results of which were approved by the regulator in the relevant jurisdiction. |
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| • | In 2011, APUC provided a corporate guarantee in an amount of U.S. $1.0 million to a subsidiary of Emera providing lead market participant services for fuel capacity and forward reserve markets to ISO NE for the Windsor Locks Thermal Facility. There has not been any transaction under this contract in the last three years. |
The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.
Other
A spouse of one of the Senior Executives provided market research consulting services to certain subsidiaries of the Company. During the year ended December 31, 2014, APUC paid $0.192 million (2013 - $0.045 million) in relation to these services.
ENTERPRISE RISK MANAGEMENT
An enterprise risk management ("ERM") framework is embedded across the organization that systematically and broadly identifies, assesses, and mitigates the key strategic, operational, financial, and compliance risks that may impact the achievement of our objectives. APUC’s ERM policy details the risk management processes, risk appetite, and risk governance structure which clearly establishes accountabilities for managing risk across the organization.
As part of the risk management processes, risk registers have been developed across the organization through ongoing risk identification and risk assessment exercises facilitated by APUC’s internal ERM team. Key risks and associated mitigation strategies are reviewed by the Executive Risk Steering Committee on a monthly basis and presented to the Board of Directors on a quarterly basis. The key risk categories assessed include: safety, environment, natural disasters, security (physical and cyber), operations, organizational effectiveness, contracts, budget, capital projects, return on M&A activity, markets, liquidity, financial reporting, strategic, and regulatory.
Risks are assessed consistently across the organization using a common risk matrix to assess impact and likelihood. Financial, reputation and safety implications are considered when determining the impact of a potential risk. Risk treatment priorities are established based upon these risk assessments and incorporated into the development of APUC’s strategic plans.
The development and execution of risk treatment plans are actively monitored by the ERM team through a centralized risk register software application. APUC’s internal audit team is responsible for conducting audits to validate and test the effectiveness of controls for the key risks. Audit findings are discussed with business owners and reported to the Board audit committee on a quarterly basis. All material changes to exposures, controls or treatment plans of key risks are reported to the ERM team, Executive Risk Steering Committee, and the Board of Directors for consideration.
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| 2014 Annual Report | 45 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
APUC’s ERM framework follows the guidance of ISO 31000;2009. The Board oversees management to ensure the risk governance structure and risk management processes are robust, and that APUC’s risk appetite is thoroughly considered in decision-making across the organization.
The risks discussed below are not intended as a complete list of all exposures that APUC is encountering or may encounter. A further assessment of APUC and its subsidiaries’ business risks is also set out in the most recent AIF.
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| 2014 Annual Report | 46 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
Treasury Risk Management
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 78% of EBITDA in 2014 and 77% 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 a net impact on U.S. operations of approximately $22.8 million ($0.10 per share) on an annual basis.
In light of the currency profile of its operations, APUC changed the currency of its dividend to U.S. dollars in the third quarter of 2014. APUC further manages currency risk through the matching of U.S. long term debt to finance its U.S. operations, thereby creating a natural hedge for the operating profit vis a vis financing cost. APUC’s policy is not to utilize derivative financial instruments for trading or speculative purposes. APUC may from time to time enter into short term foreign currency derivative contracts to hedge exposure of anticipated transactions denominated in a foreign currency.
Market Price Risk
The Distribution Business Group is not exposed to market price risk as rates charged to customers are stipulated by the respective regulatory bodies.
The Generation Group predominantly enters into long term PPAs for its generation assets and hence is not exposed to market risk for this portion of its portfolio. Where a generating asset is not covered by a power purchase contract, the Generation Group may seek to mitigate market risk exposure by entering into financial or physical power hedges requiring that a specified amount of power be delivered at a specified time in return for a fixed price. There is a risk that the Company is not able to generate the specified amount of power at the specified time resulting in production shortfalls under the hedge that then requires the Company to purchase power in the merchant market. To mitigate the risk of production shortfalls under hedges, the Generation Group generally seeks to structure hedges to cover less than 100% of the anticipated production, thereby reducing the risk of not producing the minimum hedge quantities. Nevertheless, due to unpredictability in the natural resource or due to mechanical failures, production shortfalls may be such that the Generation Group may still be forced to purchase power in the merchant market at prevailing rates to settle against a hedge.
Hedges currently put in place by the group along with residual exposures to the market are detailed below:
On May 15, 2012, the Generation Group entered into a financial hedge, which expires December 31, 2016, with respect to its Dickson Dam Hydro Facility located in the Western region. The financial hedge is structured to hedge 75% of the facility's expected production volume against exposure to the Alberta Power Pool’s current spot market rates. The annual unhedged production based on long term projected averages is approximately 16,000 MW-hrs annually. Therefore, each U.S. $10.00 per MW-hr change in the market prices in the Western region would result in a change in revenue of U.S. $0.2 million on an annualized basis.
The July 1, 2012 acquisition of Sandy Ridge Wind Facility included a financial hedge, which commenced on January 1, 2013 for a 10 year period. The financial hedge is structured to hedge 72% of the Sandy Ridge Wind Facility’s expected production volume against exposure to PJM Western Hub current spot market rates. The annual unhedged production based on long term projected averages is approximately 44,000 MW-hrs annually. Therefore, each U.S. $10 per MW-hr change in the market prices would result in a change in revenue of about U.S. $0.4 million for the year.
The December 10, 2012 acquisition of Senate Wind Facility included a physical hedge, which commenced on January 1, 2013 for a 15 year period. The physical hedge is structured to hedge 64% of the Senate Wind Facility’s expected production volume against exposure to ERCOT North Zone current spot market rates. The annual unhedged production based on long term projected averages is approximately 188,000 MW-hrs annually. Therefore, each U.S. $10 per MW-hr change in the market prices would result in a change in revenue of about U.S. $1.9 million for the year.
The December 10, 2012 acquisition of the Minonk Wind Facility included a financial hedge, which commenced on January 1, 2013 for a 10 year period. The financial hedge is structured to hedge 73% of the Minonk Wind Facility’s expected production volume against exposure to PJM Northern Illinois Hub current spot market rates. The annual unhedged production based on long term projected averages is approximately 186,000 MW-hrs annually. Therefore, each U.S. $10 per MW-hr change in market prices would result in a change in revenue of about U.S. $1.9 million for the year.
Under each of the above noted hedges, if production is not sufficient to meet the unit quantities under the hedge, the shortfall must be purchased in the open market at market rates. The effect of this risk exposure cannot be quantified as it is dependent on both the amount of shortfall and the market price of electricity at the time of the shortfall.
In addition to the above noted hedges, from time to time the Generation Group enters into short-term derivative contracts (with terms of one to three months) to further mitigate market price risk exposure due to production variability. As at December 31, 2014, the Generation Group had not entered into any such hedges.
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| 2014 Annual Report | 47 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
The January 1, 2013 acquisition of the Shady Oaks Wind Facility included a power sales contract, which commenced on January 1, 2013 for a 20 year period. The power sales contract is structured to hedge the preponderance of the Shady Oaks Wind Facility’s production volume against exposure to PJM ComEd Hub current spot market rates. For the unhedged portion of production based on expected long term average production, each U.S. $10 per MW-hr change in market prices would result in a change in revenue of about U.S. $0.5 million for the year.
Credit/Counterparty Risk
APUC and its subsidiaries are subject to credit risk through its long term power purchase contracts, trade receivables, derivative financial instruments and short term investments. APUC has processes in place to monitor and evaluate this risk on an ongoing basis including background credit checks and security deposits from new customers.
APUC does not believe the credit risk of default by counterparties to its long term power purchase contracts to be significant, as approximately 84.7% of the Generation Group's revenues are earned from large utility customers having a credit rating of Baa1 or better by Moody's Rating Services or BBB+ or higher by S&P Rating Services. The following chart sets out the Generation Group’s significant customers, their credit ratings and percentage of total revenue associated with the customer:
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| | | | | | | | | |
| Counterparty | | Credit Rating 1 | | Approximate Annual Revenues | | Percent of Divisional Revenue |
| Generation Group - Renewable Energy | | | | | | |
| PJM Interconnection LLC | | Aa3 | | 49.0 |
| | 33.6 | % |
| Manitoba Hydro | | Aa1 | | 31.1 |
| | 21.4 | % |
| Hydro Quebec | | Aa2 | | 22.6 |
| | 15.5 | % |
| Ontario Electricity Financial Corporation | | Aa2 | | 17.8 |
| | 12.2 | % |
Emera Maine 2 | | N/A | | 8.0 |
| | 5.5 | % |
| Total – Renewable Energy | | | | $ | 128.5 |
| | 88.2 | % |
| Generation Group - Thermal Energy | | | | | | |
| Pacific Gas and Electric Company | | Baa1 | | 19.8 |
| | 46.1 | % |
| Connecticut Light and Power | | Baa1 | | 23.2 |
| | 53.9 | % |
| Total – Thermal Energy | | | | $ | 43.0 |
| | 100.0 | % |
| Total – Generation Group | | | | $ | 171.5 |
| | 84.7 | % |
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| 1 | Ratings by Moody’s or Standard & Poor’s as of February 2015. |
| 2 | Maine Public Service is a subsidiary of Emera which has a corporate rating of BBB+. |
The remaining revenue is primarily earned by the Distribution Group. In this regard, the credit risk attributed to the Distribution Group's accounts receivable balances at the water and wastewater distribution systems total U.S. $5.9 million which is spread over approximately 97,000 connections, resulting in an average outstanding balance of approximately $60 dollars per connection.
The natural gas distribution systems accounts receivable balances related to the natural gas utilities total U.S. $62.0 million, while electric distribution systems accounts receivable balances related to the electric utilities total U.S. 24.3 million. The natural gas and electrical utilities, respectively, derive over 91% and 87% of their revenue from residential customers.
In addition to the counterparty risk related to customer sales outlined above, the Generation and Distribution Groups utilize derivative instruments as hedges of certain financial risks as discussed elsewhere in this MD&A. APUC is exposed to credit risk related to counterparties to the extent those derivative instruments are in an asset position at a point in time. The company manages counterparty risk by entering into these instruments with counterparties having a credit rating of BBB- or better.
Interest Rate Risk
The majority of debt outstanding in APUC and its subsidiaries is subject to a fixed rate of interest and as such is not subject to interest rate risk. Borrowings subject to variable interest rates are as follows:
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| • | The Corporate Credit Facility is subject to a variable interest rate. The APUC Facility has no amounts outstanding as at December 31, 2014. As a result, a 100 basis point change in the variable rate charged would not impact interest expense. |
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| 2014 Annual Report | 48 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
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| • | The Generation Credit Facility had $23.4 million outstanding as at December 31, 2014. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.2 million annually. |
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| • | The Distribution Credit Facility had $23.9 million outstanding as at December 31, 2014. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.2 million annually. |
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| • | The Generation Group is party to an interest rate swap whereby the group pays a fixed interest rate of 4.47% on a notional amount of $60.5 and receives floating interest at 90 day CDOR, up to the expiry of the swap in September 2015. This interest rate swap is not being accounted for as a hedge and, consequently, changes in fair value are recorded in earnings as they occur. As a result, a 100 basis point change in the variable rate would impact derivative gains/losses by $0.01 million. |
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| • | The Shady Oaks Senior Debt Facility had $88.2 million outstanding as at December 31, 2014. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.9 million annually. |
APUC does not actively manage interest rate risk on its variable interest rate borrowings due to the primarily short term and revolving nature of the amounts drawn. The interest rate swap, although not designated as a hedge, serves to partially offset interest rate movements against the variable pay portion of the Company's debt.
To mitigate refinancing risk, from time to time APUC may seek to fix interest rates on expected future financings. In the fourth quarter, the Generation Group entered into a hedge to fix the underlying interest rate for the anticipated refinancing of its $135.0 million bond maturing in July 2018. Hedge accounting treatment will apply to this transaction. Consequently, changes in fair value, to the extent deemed effective, will be recorded into Other Comprehensive Income.
Tax Risk and Uncertainty
Although APUC is of the view that all expenses being claimed by APUC are reasonable and that the cost amount of APUC’s depreciable properties have been correctly determined, there can be no assurance that the Canada Revenue Agency or the Internal Revenue Service will agree. A successful challenge by either agency regarding the deductibility of such expenses or the correctness of such cost amounts could impact the return to shareholders.
Unit Exchange Transaction
On October 27, 2009, unitholders of Algonquin Power Income Fund exchanged their trust units on a one for one basis for common shares of Algonquin Power & Utilities Corp (the “Unit Exchange Transaction”). As a result of the Unit Exchange Transaction, APUC recorded certain additional tax attributes to the extent management believed they were more likely than not to be realized. The excess of the carrying amount of the tax attributes assumed over the consideration paid was recorded as a deferred credit of $55.6 million on the date of the Unit Exchange Transaction (the “Transaction Date”). The deferred credit has been recognized into income as a deferred income tax recovery in relative proportion to the amount of the related tax attributes that have been utilized since the Transaction Date.
Subsequent to the Balance Sheet date, APUC received a proposal letter from the Canada Revenue Agency (“CRA”) which outlines its intention to challenge the tax consequences of APUC’s 2009 Unit Exchange. CRA is seeking to apply the acquisition of control rules or the general anti-avoidance rules of the Income Tax Act (Canada) the effect of which would be to deny APUC of the benefit of the tax attributes assumed as part of the Unit Exchange Transaction.
Should APUC receive a Notice of Reassessment covering the 2009, 2010, 2011, 2012 and 2013 taxation years, APUC will be required to make a deposit payment of 50% of the tax liability (including interest and any applicable penalties) claimed by the CRA in order to appeal the expected reassessment. Based on the tax amounts related to the 2009 to 2013 taxation years, that payment amount would be approximately $17.5 million. Additionally, assuming the 2014 taxation year will be similarly reassessed, a further payment of approximately $3.1 million would also be required. APUC would also be required to make a deposit payment of 50% of the taxes the CRA claims are owed in any future tax year if the CRA were to issue a similar notice of reassessment for such years and APUC were to appeal it.
Should APUC be successful in defending its position, all such payments plus applicable interest, will be refunded to APUC. If the CRA is successful, APUC will be required to pay the balance of the taxes assessed (plus applicable interest and any applicable penalties).
APUC has 90 days from the date of any Notice of Reassessment to prepare and file a Notice of Objection, which would be reviewed by the CRA’s appeals division. If the CRA appeals division does not allow APUC’s initial appeal, APUC has the option to file its case with the Tax Court of Canada. APUC anticipates that legal proceedings through the various tax courts could take approximately two to four years.
APUC remains confident in the appropriateness of its tax filing position and the expected tax consequences of the Unit Exchange Transaction and intends to vigorously defend such position. APUC strongly believes that the acquisition of control or the general anti-avoidance rules do not apply to the Unit Exchange Transaction and intends to file its future tax returns on a basis consistent with its previous tax returns. As a result, the probability of any potential final cash payment and impact on net earnings cannot be estimated at this time, but could range from $nil to $45.0 million.
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| 2014 Annual Report | 49 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
The impact of the proposal on APUC’s tax provision has been considered by management; however, management continues to believe that the most likely outcome has not changed and it is more likely than not, that APUC will be successful in defending its position. On this basis, APUC’s 2014 financial statements do not include the impact of a potential reassessment. Until the matter is resolved with CRA, or should new facts arise that would result in a change to management’s assessment of the most likely outcome, any future deposit tax payments made by APUC will be recorded to the balance sheet and will not impact either adjusted funds from operations or net earnings.
On a consolidated basis, APUC and its Canadian subsidiaries have tax attributes that are available to reduce or eliminate cash taxes. Should the CRA ultimately be successful in the appeal process, APUC will seek to refile prior year tax returns and accelerate the use of such tax attributes to minimize any actual cash taxes that would otherwise be owed as a result of the reassessment of the tax consequences of the Unit Exchange.
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.
Both the Generation Group and the Distribution Group have established financing platforms to access new liquidity from the capital markets as requirements arise. APUC continually monitors the maturity profile of its debt and adjusts accordingly to ensure sufficient liquidity exists to meet liabilities when due.
As at December 31, 2014, APUC and its subsidiaries had a combined $485.9 million of committed and available revolving credit facilities remaining and $9.3 million of cash resulting in $495.2 million of total liquidity and capital reserves.
APUC currently pays a dividend of U.S. $0.35 per common 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 its judgment, ensures APUC’s long-term success. Based on the level of common share dividends paid during the year ended December 31, 2014, cash provided by operating activities exceeded common share dividends declared by 2.2 times and Adjusted Cash From Operations exceeds common share dividends by 3.4 times.
The current and long term portion of debt totals approximately $1,280.0 million with maturities set out in the Contractual Obligation table. In the event that APUC was required to replace the Facilities and project debt with borrowings having less favorable terms or higher interest rates, the level of cash generated for dividends and reinvestment may be negatively impacted.
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 regard 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
The Generation Group’s exposure to commodity prices is primarily limited to exposure to natural gas price risk. The Distribution Groups is exposed to energy and natural gas price risks at its electric and natural gas systems. In this regard, a discussion of this risk is set out as follows:
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| • | The Sanger Thermal 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 net revenue by approximately $0.2 million on an annual basis. |
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| • | The Windsor Locks Thermal Facility’s Energy Services Agreement includes provisions which reduce its exposure to natural gas price risk but has exposure to market rate conditions for sales above those to its primary customer. In this regard, a $1.00 increase in the price of natural gas per MMBTU, based on expected production levels, would result in a decrease in net revenue by approximately $0.1 million on an annual basis. |
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| • | The Maritime region provides short-term energy requirements to various customers at fixed rates. The energy requirements of these customers are estimated at approximately 174,000 MW-hrs in fiscal 2015, of which 90,000 MW-hrs is presently contracted. While the Tinker Hydro Facility is expected to provide the majority of the energy required to service these customers, the Maritime region anticipates having to purchase approximately 80,000 MW-hrs of its energy requirements at the ISO-NE summer spot rates to supplement self-generated energy should the Maritime region be able to reach the estimated 174,000 MW-hrs. The risk associated with the expected market purchases of 80,000 MW-hrs is mitigated through the use of short-term financial energy hedge contracts which cover approximately 90% of the Maritime region's anticipated purchases during the price-volatile winter months at an average rate of approximately $65 per MW-hr. For the amount of anticipated purchases not covered by hedge contracts, each $10.00 change per MW-hr in the market prices in ISO-NE would result in a change in expense of $0.5 million on an annualized basis. |
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| 2014 Annual Report | 50 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
The CalPeco Electric System provides electric service to the Lake Tahoe California basin and surrounding areas at rates approved by the CPUC. The CalPeco Electric System purchases the energy, capacity, and related service requirements for its customers from NV Energy via a PPA at rates reflecting NV Energy’s system average costs.
The CalPeco Electric System's tariffs allow for the pass-through of energy costs to its rate payers on a dollar for dollar basis, through the energy cost adjustment clause (“ECAC”) mechanism, which allows for the recovery or refund of changes in energy costs that are caused by the fluctuations in the price of fuel and purchased power. On a monthly basis, energy costs are compared to the CPUC approved base tariff energy rates and the difference is deferred to a balancing account. Annually, based on the balance of the ECAC balancing account, if the ECAC revenues were to increase or decrease by more than 5%, the CalPeco Electric System's ECAC tariff allows for a potential adjustment to the ECAC rates which would eliminate the risk associated with the fluctuating cost of fuel and purchased power. The CalPeco Electric System also benefits from a revenue decoupling mechanism and a vegetation management memorandum account. The revenue decoupling mechanism decouples base revenues from fluctuations caused by weather and economic factors reducing volumetric risk for the utility. The vegetation management memorandum account allows for the tracking and pass through of vegetation management expenses, one of the largest expenses of the utility, reducing the potential for expenses to exceed the amounts allowed for in general rates.
The Granite State Electric System is an open access electric utility allowing for its customers to procure commodity services from competitive energy suppliers. For those customers that do not choose their own competitive energy supplier, Granite State Electric System provides a Default Service offering to each class of customers through a competitive bidding process. This process is undertaken semi-annually for all customers. The winning bidder is obligated to provide a full requirements service based on the actual needs of the Granite State Electric System’s Default Service customers. Since this is a full requirements service, the winning bidder take on the risk associated with fluctuating customer usage and commodity prices. The supplier is paid for the commodity by the Granite State Electric System which in turns receives pass-through rate recovery through a formal filing and approval process with the NHPUC on a semi-annual basis. The Granite State Electric System is only committed to the winning Default Service supplier(s) after approval by the NHPUC so that there is no risk of commodity commitment without pass-through rate recovery.
The EnergyNorth Natural Gas System purchases pipeline capacity, storage and commodity from a variety of counterparties. The EnergyNorth Natural Gas System's portfolio of assets and its planning and forecasting methodology are approved by the NHPUC bi-annually through an Integrated Resource Plan filing. In addition, EnergyNorth Natural Gas System files with the NHPUC for recovery of its transportation and commodity costs through a semi-annual basis through the Cost of Gas ("COG") filing and approval process. The EnergyNorth Natural Gas System establishes rates for its customers based on the NHPUC approval of its filed COG. These rates are designed to fully recover its anticipated transportation and commodity costs. In order to minimize commodity price fluctuations, the EnergyNorth Natural Gas System locks in a fixed price basis for approximately 14% of its normal winter period purchases under a NHPUC approved hedging program. All costs associated with the fixed basis hedging program are allowed to be pass-through to customers through the COG filing and the approved rates in said filing. Should commodity prices increase or decrease relative to the initial semi-annual COG rate filing, the EnergyNorth Natural Gas System has the right to automatically adjust its rates going forward in order to minimize any under or over collection of its gas costs. In addition, any under collections may be carried forward with interest to the next year’s period COG filing, i.e. winter to winter and summer to summer.
The purchases pipeline capacity, storage and commodity from a variety of counterparties, and files with the three individual State Commissions for recovery of its transportation and commodity costs through an annual Purchase Gas Adjustment (“PGA”) filing and approval process. The Midstates Gas Systems establishes rates for its customers within the PGA filing and these rates are designed to fully recover its anticipated transportation and commodity costs. In order to minimize commodity price fluctuations, the Company has implemented a commodity hedging program designed to hedge approximately 25-50% of its non-storage related commodity purchases. All gains and losses associated with the hedging program are allowed to be pass-through to customers through the PGA filing and are embedded in the approved rates in said filing. Rates can be adjusted on a monthly or quarterly basis in order to account for any commodity price increase or decrease relative to the initial PGA rate, minimizing any under or over collection of its gas costs.
OPERATIONAL RISK MANAGEMENT
Mechanical and Operational Risks
APUC's profitability could be impacted by, among other things, equipment failure, the failure of a major customer to fulfill its contractual obligations under its PPA, reductions in average energy prices, a strike or lock-out at a facility, and expenses related to claims or clean-up to adhere to environmental and safety standards.
The Generation Group's hydro assets utilize dams to pond water for generation and if the dams burst potentially catastrophic amounts of water would flood downriver from the facility. The dams can be subjected to drought conditions and lose the ability to generate during peak load conditions, causing the facilities to fall short of either hedged or PPA committed production levels. The risks of the hydro facilities are mitigated by regular dam inspections and a maintenance program of the facility to lessen the risk of dam failure.
The Generation Group's wind assets could on catch on fire and, depending on the season, could ignite significant amounts of forest or crop downwind from the wind farms. The wind units could also be affected by large atmospheric conditions (e.g. El
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| 2014 Annual Report | 51 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
Nina), which will lower wind levels below our PPA and hedge minimum production levels. Production risks associated with the wind turbine generators is mitigated by properly maintaining the units using long term maintenance agreements with the turbine O&M’s, which provide for regular inspections and maintenance of property and liability insurance policies. Icing can be mitigated by shutting down the unit as icing is detected at the site.
The Generation Group's Thermal Energy Division uses natural gas and oil, and produce exhaust gases, which if not properly treated and monitored could cause hazardous chemicals to be released into the atmosphere. The units could also be restricted from purchasing gas/oil due to either shortages or pollution levels, which could hamper output of the facility. The mechanical and operational risks at the Thermal Energy Division are mitigated through the regular maintenance of the boiler system, and by continual monitoring of exhaust gases. Fuel restrictions can be hedged somewhat by long term purchases.
All of the Generation Group's renewable and thermal generating stations are subject to mechanical breakdown. The risk of mechanical breakdown is mitigated by properly maintaining the units and by regular inspections.
The Distribution Group's water and wastewater distribution systems operate under pressurized conditions within pressure ranges approved by regulators. Should a water distribution network become compromised or damaged, the resulting release of pressure could result in serious injury or death to individuals or damage to other property.
The Distribution Group's electric distribution systems are subject to storm events, usually winter storm events, whereby power lines can be brought down with the attendant risk to individuals and property. In addition, in forested areas, power lines brought down by wind can ignite forest fires which also bring attendant risk to individuals and property.
The Distribution Group's natural gas distribution systems are subject to risks which may lead to fire and/or explosion which may impact life and property. Risks include third party damage, compromised system integrity, type/age of pipelines, and severe weather events.
These risks are mitigated through the diversification of APUC’s operations, both operationally (the Generation and Distribution Groups) and geographically (Canada and U.S.), the use of regular maintenance programs, including pipeline safety programs and compliance programs, and maintaining adequate insurance and the establishment of reserves for expenses.
Regulatory Risk
Profitability of APUC businesses is in part dependent on regulatory climates in the jurisdictions in which it operates. In the case of some Generation Group's hydroelectric facilities, water rights are generally owned by governments who reserve the right to control water levels which may affect revenue.
The Distribution Group’s facilities are subject to rate setting by State regulatory agencies. The time between the incurrence of costs and the granting of the rates to recover those costs by State regulatory agencies 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. As a strategy to mitigate, the Distribution Group seeks to obtain approval for regulatory constructs in the states in which it operates to allow for timely recovery of operating expense. A fundamental risk faced by any regulated utility is the disallowance of costs to be placed into its revenue requirement by the utility's regulator. To the extent proposed costs are not allowed into rates, the utility will be required to find other efficiencies or cost savings to achieve its allowed returns.
The Distribution Group regularly works with its governing authorities to manage the affairs of the business employing both local state level and corporate resources.
Condemnation Expropriation Proceedings
The Distribution Group's electricity and natural gas distribution systems could be subject to condemnation or other methods of taking by government entities under certain conditions. Any taking by government entities would legally require just and fair compensation be paid to the Distribution Group and the Distribution Group believes such compensation would reflect fair market value for any assets that are taken. Notwithstanding the determination of such fair and just compensation will be undertaken pursuant to a legal proceeding and therefore there is no assurance that the value received for assets taken will be in excess of book value. In 2014, the Company entered into an agreement to acquire the regulated water distribution utility Park Water Company. The Park Water Company owns and operates three regulated water utilities engaged in the production, treatment, storage, distribution, and sale of water in Southern California and Western Montana. Mountain Water Company is the water utility in Western Montana serving the municipality of Missoula owned by Park Water Company. Mountain Water Company is currently the subject of a condemnation proceeding by the city of Missoula. It is not known when the condemnation proceeding will conclude or whether the city of Missoula will be successful in its condemnation efforts. If the city of Missoula is successful in its condemnation efforts, the quantum of compensation to be paid by the city of Missoula for such taking will be subsequently determined by a valuation hearing by the courts. In respect of such potential valuation hearing, expert reports have been prepared by Mountain Water Company which indicate a fair value of Mountain Water Company of between US$116.0 million and US$141.0 million.
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| 2014 Annual Report | 52 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
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 ability to quantify such expense, the timing of incurring the potential expenses, as well as other factors which may be considered in evaluating if such obligations exist and in estimating the fair value of such obligations.
The Distribution Group’s facilities are operated with the assumption that their services will be required in perpetuity and there are no contractual decommissioning requirements. In order to remain in compliance with the applicable regulatory bodies, the Distribution Group has regular programs at each facility to ensure its equipment is properly maintained and replaced on a cyclical basis. These costs can generally be included in the facility’s rate base and thus the Distribution Group expects to be allowed to earn a return on such investment.
In conjunction with recent acquisitions and developed projects, the Company assumed certain asset retirement obligations. The asset retirement obligations mainly relate to legal requirements for: (i) removal of wind facilities upon termination of land leases; (ii) cut (disconnect from the distribution system), purge (clean of natural gas and PCB contaminants), and cap gas mains within the gas distribution and transmission system when mains are retired in place, or dispose of sections of gas main when removed from the pipeline system; (iii) clean and remove storage tanks containing waste oil and other waste contaminants; and (iv) remove asbestos upon major renovation or demolition of structures and facilities.
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 an adequate insurance program, which includes property, equipment breakdown, environmental, and liability policies.
The Generation Group’s ongoing operations and historic activities are subject to various environmental laws and regulations and are regulated by federal agencies such as the United States Environmental Protection Agency, Federal Energy Regulatory Commission ("FERC"), NERC, Environment Canada, Fisheries and Oceans Canada; and State/Provincial Agencies, such as the New York State Department of Environmental Conservation (“NYSDEC”), California Air Resource Board, Connecticut Department of Environmental Protection (“CDEP”), Illinois Department of Environmental Protection (“IDEP’), Pennsylvania Game Commission (“PGC”), Alberta Environment, Manitoba Conservation, Ontario Ministry of the Environment, Ontario Ministry of Natural Resources, among others. Power generation facilities generate air emissions, noise, potential for flooding, spill risk, possible disruption of protected wildlife, along with the generation of industrial wastewater and certain amounts of hazardous wastes.
The Distribution Group faces environmental risks that are normal aspects of operating within its business segment. The primary environmental risks associated with the operation of an electrical distribution system are related to potential accidental release of mineral oil to the environment from non-operational events and the management of hazardous and universal waste in accordance with the various Federal, State and local environmental laws. Like most other industrial companies, the Distribution Group generates some hazardous wastes as a result of its operations. Under Federal and State Superfund laws, potential liability for historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred.
In order to monitor and mitigate these risks and to remain within the regulatory requirements appropriate for these assets, the Generation and Distribution Groups investigate promptly all reported accidental releases to take all required remedial actions and manages hazardous waste and universal waste streams in accordance with the applicable Federal and State Legislation.
The primary risks associated with the operation of gas distribution systems are related to uncontrolled natural gas releases, equipment damage by construction equipment/third parties or severe weather events. The gas distribution assets are regulated by the Pipeline Hazardous Material Safety Administration (PHMSA) under the United States Department of Transportation and their respective State regulations in which the assets are located. Natural Gas Distribution Systems are subject to detailed inspections by State Regulatory Agencies to ensure adherence to applicable regulations. State Regulator Agencies review the Company’s policies in reference to operation and maintenance, construction, training, emergency response, reporting, contractor management and measurements. The Distribution Group monitors all aspects of pipeline safety and quickly mitigates any identified concerns.
The primary risks associated with the operation of power generation facilities are related to uncontrolled contaminant releases (or above the permitted limits), not being in continued compliance with permits and licenses obligations such as, continuous emissions monitoring, periodic reporting/source testing, general performance/operating conditions, operations adjustments (wind projects) resulting from post construction wildlife mortality monitoring, dam safety, potential accidental release of mineral oil or other hazardous materials to the environment.
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| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
The Distribution Group’s ongoing operations and historic activities are subject to various federal, state and local environmental laws and regulations and are regulated by agencies such as the United States Environmental Protection Agency, the New Hampshire Department of Environmental Services (“NHDES”). Similar to other industrial companies, the gas and electric distribution utilities generate certain hazardous wastes. Under federal and state Superfund laws, potential liability for historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred. In the case of regulated utilities these costs are often allowed in rate case proceedings to be recovered from rate payers over a specified period.
Prior to their acquisition by the Distribution Group, the EnergyNorth Gas Utility, the Granite State Electric Utility, and the New England Gas System were named as potentially responsible parties for remediation of several sites at which hazardous waste is alleged to have been disposed as a result of historic operations of Manufactured Gas Plants (“MGP”) and related facilities. The Distribution Group is currently investigating and remediating, as necessary, those MGP and related sites where it is the lead project manager in accordance with plans submitted to the NHDES. The Distribution Group believes that obligations imposed on it because of those sites will not have a material impact on its results of operations or financial position.
The Distribution Group estimates the remaining undiscounted and unescalated cost of these MGP-related environmental cleanup activities will be $72.6 million which, at discount rates ranging from 2.1% to 3.4%, represents $72.3 million on a discounted basis, as the Distribution Group’s estimate of costs for known issues that has been accrued at December 31, 2014. By rate orders, the Regulator provided for the recovery of site investigation and remediation costs and accordingly, at December 31, 2014 the Company has reflected a regulatory asset of $102.7 million for the remediation of the MGP and related sites.
APUC’s policy is to record estimates of environmental liabilities when they are known or considered probable and the related liability is estimable.
Cycles and Seasonality
Generation Group
The Generation Group's hydroelectric operations are impacted by seasonal fluctuations and year to year variability of the available hydrology. These assets are primarily “run-of-river” and as such fluctuate with natural water flows. During the winter and summer periods, flows are generally lower while during the spring and fall periods flows are generally higher. The ability of these assets to generate income may be impacted by changes in water availability or other material hydrologic events within a watercourse. Year to year the level of hydrology varies impacting the amount of power that can be generated in a year.
The Generation Group's wind generation facilities are impacted by seasonal fluctuations and year to year variability of the wind resource. During the spring and fall periods, winds are generally stronger than during the summer periods. The ability of these facilities to generate income may be impacted by naturally occurring changes in wind patterns and wind strength.
The Generation Group's solar generation facilities are impacted by seasonal fluctuations and year to year variability in the solar radiance. For instance, there are more daylight hours in the summer than there are in the winter resulting in higher production in the summer months. The ability of these facilities to generate income may be impacted by naturally occurring changes in solar radiance.
The Company attempts to mitigate the above noted natural resource fluctuation risks by acquiring or developing generating stations in different geographic locations.
Distribution Group
The Distribution Group’s demand for water is affected by weather conditions and temperature. Demand for water during warmer months is generally greater than cooler months due to requirements for irrigation, swimming pools, cooling systems and other outside water use. If there is above normal rainfall or rainfall is more frequent than normal the demand for water may decrease adversely affecting revenues.
The Distribution Group’s demand for energy from its electric distribution systems is primarily affected by weather conditions and conservation initiatives. The Distribution Group provides information and programs to its customers to encourage the conservation of energy. In turn, demand may be reduced which could have short term adverse impacts to revenues.
The Distribution Group's primary demand for natural gas from its natural gas distribution systems is driven by the seasonal heating requirements of its residential, commercial, and industrial customers. The colder the weather the greater the demand for natural gas to heat homes and businesses. As such, the natural gas distribution systems demand profiles typically peaks in the winter months of January and February and declines in the summer months of July and August. Year to year variability also occurs depending on how cold the weather is in any particular year.
The Company attempts to mitigate the above noted risks by seeking regulatory mechanisms during rate case proceedings. Certain jurisdictions have approved constructs to mitigate demand fluctuations. For example, at the Peach State Gas System in Georgia, a weather normalization adjustment is applied to customer bills during the months of October through May that adjusts commodity rates to stabilize the revenues of the utility for changes in billing units attributable to weather patterns. Not all regulatory jurisdictions in which the Distribution Group operates have approved mechanisms to mitigate demand fluctuations.
Development and Construction Risk
The Generation Group actively engages in the development and construction of new power generation facilities. The current pipeline of projects either currently in construction or in development is $1.2 billion and are mainly renewable solar and wind projects. There is always a risk that material delays and/or cost overruns could be incurred in any of the projects planned or currently in construction affecting the company’s overall performance. Examples of inherent risks pertaining to power generation facility development can include: technical issues with the interconnection utility, unfavorable permitting results or delays emanating from State, Provincial or Federal agency interface, construction delays or cost overruns, equipment performance outside of expectations, and land owner disputes. The Generation Group mitigates these risk through its due diligence processes, sound project management principals and appropriate contingency plans and reserves.
The strength and consistency of the wind resource will vary from the estimate set out in the initial wind studies that were relied upon to determine the feasibility of the wind facility. If weather patterns change or the historical data proves not to
accurately reflect the strength and consistency of the actual wind, the assumptions underlying the financial projections as to the amount of electricity to be generated by the facility may be different and cash could be impacted.
The amount of solar radiance will vary from the estimate set out in the initial solar studies that were relied upon to determine the feasibility of the solar facility. If weather patterns change or the historical data proves not to accurately reflect the strength and consistency of the solar radiance, the assumptions underlying the financial projections as to the amount of electricity to be generated by the facility may be different and cash could be impacted.
For certain of its development projects, the Generation Group relies on financing from third party Tax Equity Investors. These investors typically provide funding upon commercial operation of the facility. Should certain facilities not meet the conditions required for tax equity funding, expected returns from the facilities may be impacted.
Obligations to Serve
The Distribution Group may have facilities located within areas of the United States experiencing growth. These utilities may have an obligation to service new residential, commercial and industrial customers. While expansion to serve new customers will likely result in increased future cash flows, it may require significant capital commitments in the immediate term. Accordingly, the Distribution Group may be required to solicit additional capital or obtain additional borrowings to finance these future construction obligations.
Litigation Risks and Other Contingencies
APUC and certain of its subsidiaries are involved in various litigations, claims and other legal proceedings that arise from time to time in the ordinary course of business. Any accruals for contingencies related to these items are recorded in the financial statements at the time it is concluded that a material financial loss is likely and the related liability is estimable. Anticipated recoveries under existing insurance policies are recorded when reasonably assured of recovery.
Trafalgar Proceedings
Trafalgar commenced an action in 1999 in U.S. District Court against APUC, and various other entities related to them in connection with, among other things, the sale of the Trafalgar Class B Note by Aetna Life Insurance Company to APUC and in connection with the foreclosure on the security for the Trafalgar Class B Note which includes interests in the Trafalgar entities and in the hydroelectric generating facilities in New York (the “Trafalgar Hydro Facilities”). In 2001, Trafalgar and other entities also filed for Chapter 11 reorganization in bankruptcy court and also filed a multi-count adversary complaint against certain subsidiary entities of APUC, which complaint was then transferred to the District Court. In 2006, the District Court decided that Aetna had complied with the provisions concerning the sale of the Trafalgar Class B Note, that APUC was therefore the holder and owner of the Trafalgar Class B Note, and that all other claims by Trafalgar with respect to the transfer of the Trafalgar Class B Note were without merit. Further, on November 6, 2008, the claims that were remaining in the District Court against APUC were dismissed by summary judgment. On October 22, 2009, Trafalgar filed an appeal from the November 6, 2008 summary judgment to the United States Court of Appeals for the Second Circuit. As discussed further below, as the proceedings continued, the United States Second Circuit Court of Appeals, among other things, (i) on November 2, 2010 dismissed the claims against APUC in the civil proceedings; and (ii) on January 30, 2013, held that Algonquin has a security interest in Trafalgar's engineering malpractice claim and its proceeds.
With respect to the civil proceedings, the United States Second Circuit Court of Appeals dismissed all the claims against APUC in the civil proceedings and remanded one issue to the District Court. On April 3, 2012, the District Court granted APUC summary judgment on its counter-claims against Trafalgar. The District Court found that Trafalgar was in default of the indenture and the loan agreements and that APUC was entitled to proceed to enforce its rights against its collateral. Trafalgar filed a notice of appeal of the Memorandum-Decision and Order. The appeal was argued on March 21, 2013. On March 25, 2013, the United States Second Circuit Court of Appeals affirmed the decision of the District Court giving APUC judgment on its claims. Trafalgar asked the United States Second Circuit Court of Appeals for reconsideration of its decision or to certify a legal question to the Connecticut Supreme Court. On May 21, 2013, the United States Second Circuit Court of Appeals denied Trafalgar’s petition and the matter was sent back to the District Court for further proceedings with respect to the enforcement of APUC’s remedies under the loan documents, including the calculation of the debt and the disposition of collateral. The District Court entered judgment in favor of APUC with regard to the default and APUC’s entitlement to recourse to the collateral, but without determining the amount due under the note. The District Court then closed the case.
With respect to the bankruptcy proceedings, on January 30, 2013, the United States Second Circuit Court of Appeals held that Algonquin did have a security interest in Trafalgar’s engineering malpractice claim and its proceeds. On February 20, 2013, Trafalgar filed a petition for a rehearing with the United States Second Circuit Court of Appeals, and in the alternative, sought to have the Second Circuit certify a legal question to the New York State Court of Appeals. The Second Circuit denied the petition and certification request which petition was denied on June 17, 2013. On September 16, 2013, Trafalgar filed a Petition for a Writ of Certiorari with the United States Supreme Court. Algonquin filed a brief in opposition to the Petition on October 18, 2013. On December 2, 2013, the United States Supreme Court denied Trafalgar’s petition for a Writ of Certiorari. Algonquin filed and served a motion seeking an order terminating the automatic stay and directing the distribution of the funds held in the escrow account to Algonquin. Algonquin’s motion for relief from the automatic stay has been denied
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| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
without prejudice to re-filing the motion after the court determines the amount of Algonquin’s claim and the validity of any defenses to the claim. Algonquin and Trafalgar have each filed motions with the Court seeking a determination of those issues. Those motions are under consideration by the Court.
The Court has approved the sale of all seven of the Trafalgar facilities. Of the seven, one has closed while the other six is anticipated to close upon obtaining regulatory approval. The parties are attempting to resolve this matter through good faith settlement negotiations.
Côte Ste-Catherine Water Lease Dues
On December 19, 1996, the Attorney General of Québec (the “Québec AG”) filed suit in Québec Superior Court against Algonquin Dévelopment (Côte Ste-Catherine) Inc. (Dévelopment Hydromega), a predecessor company to an a subsidiary entity of APUC. The Québec AG at trial claimed $5.4 million for amounts that Algonquin Dévelopment Côte Ste-Catherine Inc. had been paying to Seaway Management under the water lease relating to the Côte Ste-Catherine hydroelectric generating facility. Algonquin Dévelopment (Côte Ste-Catherine) Inc. brought the Attorney General of Canada into the proceedings. On March 27, 2009, the Superior Court dismissed the claim of the Québec AG. Québec AG appealed this decision on April 24, 2009, and the appeal was heard in January 2011.
On October 21, 2011, the Québec Court of Appeal ordered Algonquin Dévelopment (Côte Ste-Catherine) Inc. to pay approximately $5.4 million (including interest) to the government of Québec relating to water lease payments that Algonquin Dévelopment (Côte Ste-Catherine) Inc. has been paying to the Seaway Management under the water lease in prior years. The water lease with Seaway Management contains an indemnification clause which management believes mitigates this claim and management intends to vigorously defend its position. The potential unrecoverable loss, if any, for the related prior periods could be up to $6.0 million. The parties are attempting to resolve this matter through good faith negotiations.
Long Sault global adjustment claim
In December 2012, N-R Power and Energy Corporation, Algonquin Power (Long Sault) Partnership, and N-R Power Partnership (“Long Sault”) commenced proceedings (together with the other similarly affected non-utility generators) against the OEFC relating to the OEFC’s interpretation of certain provisions of a PPA between Long Sault and the OEFC, in relation to the use of the global adjustment (“GA”) as a price escalator. As a result of the OEFC’s application of the new GA calculation to the calculation of total market cost of electricity (“TMC”) of and, in turn, an index derived from TMC, the rate OEFC has paid to Long Sault under the PPA beginning with the application of OEFC’s new TMC calculation in July 2011 has not escalated as contemplated in the PPA and term sheet. A Notice of Application was issued at the end of December 2012 with supporting materials filed at the end of April 2013. The Application was heard in May 2014. On March 12, 2015, the Ontario Superior Court of Justice ruled that the methodology that the OEFC used from January 1, 2011 onward to calculate payments under Long Sault's PPA, and those of other producers, did not comply with the terms of those PPAs. The decision further requires the OEFC to revert to its pre-2011 methodology for calculating payments and to pay producers the difference between the payments calculated by the OEFC since 2011 and the amount of the payments they would have received using the pre-2011 methodology, plus interest and costs. The OEFC has until April 13, 2015 to appeal this decision.
Dimos and Katsekas Breach of Contract Claim
On September 30, 2013, Dimos and Katsekas previous owners of the Clement Dam Hydroelectric, LLC. (“Clement Dam Hydro Facility”), filed a demand for arbitration with Algonquin Power Fund (America) Inc. ("APFA") alleging breach of the Purchase Agreement and Royalty Agreement. The claim is for $1,345,257 for alleged breach of such agreements and $155,821 for alleged unpaid royalties. The plaintiffs have demanded arbitration pursuant to such agreements. An arbitration hearing date is scheduled for May, 2015.
The Royalty Agreement obligations were guaranteed by the Clement Dam Hydro Facility pursuant to a guaranty. On December 14, 2014, Dimos and Katsekas filed a complaint against the Clement Dam Hydro Facility which seeks to enforce certain obligations under a guaranty. In the event the claimants prevail against APFA in the aforementioned arbitration, and APFA does not pay any judgment rendered against it, claimants will pursue their claims against the Clement Dam Hydro Facility. APFA is defending the Clement Dam in this matter pursuant to the sale agreement with the purchaser of the Clement Dam Hydro Facility. At present, the litigation has been stayed pending the outcome of the arbitration proceeding.
Synergics Energy Services, LLC, Breach of Contract Claim
On September 4, 2013, the plaintiff, previous owners of the Great Falls Hydro Facility, filed a complaint for alleged breach of the 2000 purchase and sale agreement and failure to pay a transfer payment thereunder in the event of the sale of the hydro facility. The claim is for $3,000,000 for alleged breach of the 2000 purchase and sale agreement. The case has been settled.
Conex Energy-Canada, LLC and Conex Energy, Inc. Breach of Contract Claim
On October 31, 2013, the plaintiffs filed a complaint for, among other things, alleged breach of a confidential agreement in relation to the development and construction of the 10-megawatt solar photovoltaic Cornwall Solar Facility. On March 3, 2014, Algonquin brought a motion to dismiss the case. The Court has since dismissed the case.
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| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
Bryson School District in Texas Property Taxes Claim
On February 10, 2014, the Generation Group received correspondence from the Bryson School District (the "School District") in Texas regarding Senate Wind LLC’s property taxes claiming the Senate Wind Facility owes an additional $2.2 million of property taxes based on an indemnity in the 2010 agreement with the School District. Senate Wind LLC and the District have settled this matter.
QUARTERLY FINANCIAL INFORMATION
The following is a summary of unaudited quarterly financial information for the eight quarter ended December 31, 2014:
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| | | | | | | | | | | | | | | | |
| (all dollar amounts in $ millions except per share information) | | 1st Quarter 2014 | | 2nd Quarter 2014 | | 3rd Quarter 2014 | | 4th Quarter 2014 |
| Revenue | | $ | 343.5 |
| | $ | 189.3 |
| | $ | 151.9 |
| | $ | 259.3 |
|
| Adjusted EBITDA | | 97.5 |
| | 66.4 |
| | 41.4 |
| | 84.3 |
|
| Net earnings / (loss) attributable to shareholders from continuing operations | | 35.6 |
| | 15.3 |
| | (6.1 | ) | | 33.1 |
|
| Net earnings / (loss) attributable to shareholders | | 35.9 |
| | 14.6 |
| | (6.3 | ) | | 31.6 |
|
| Net earnings / (loss) per share from continuing operations | | 0.16 |
| | 0.06 |
| | (0.04 | ) | | 0.13 |
|
| Net earnings / (loss) per share | | 0.17 |
| | 0.06 |
| | (0.04 | ) | | 0.13 |
|
| Adjusted net earnings | | 36.8 |
| | 16.5 |
| | (0.4 | ) | | 35.2 |
|
| Adjust net earnings per share | | 0.17 |
| | 0.07 |
| | (0.01 | ) | | 0.14 |
|
| Total Assets | | 3,652.7 |
| | 3,561.9 |
| | 3,808.5 |
| | 4,113.7 |
|
Long term debt1 | | 1,409.4 |
| | 1,389.3 |
| | 1,413.5 |
| | 1,280.0 |
|
| Dividend declared per common share | | 0.09 |
| | 0.09 |
| | 0.10 |
| | 0.10 |
|
| | | 1st Quarter
2013 | | 2nd Quarter
2013 | | 3rd Quarter
2013 | | 4th Quarter
2013 |
| Revenue | | $ | 193.3 |
| | $ | 148.8 |
| | $ | 127.9 |
| | $ | 205.3 |
|
| Adjusted EBITDA | | 62.8 |
| | 56.5 |
| | 40.2 |
| | 68.5 |
|
| Net earnings / (loss) attributable to shareholders from continuing operations | | 20.3 |
| | 15.8 |
| | 6.3 |
| | 19.8 |
|
| Net earnings/(loss) attributable to shareholders | | 19.2 |
| | (18.1 | ) | | 6.0 |
| | 13.2 |
|
| Net earnings / (loss) per share from continuing operations | | 0.09 |
| | 0.08 |
| | 0.02 |
| | 0.09 |
|
| Net earnings/(loss) per share | | 0.09 |
| | (0.09 | ) | | 0.02 |
| | 0.06 |
|
| Adjusted net earnings | | 19.6 |
| | 15.4 |
| | 6.9 |
| | 18.8 |
|
| Adjust net earnings per share | | 0.09 |
| | 0.08 |
| | 0.03 |
| | 0.08 |
|
| Total Assets | | 3,476.5 |
| | 3,201.8 |
| | 3,156.4 |
| | 3,476.5 |
|
Long term debt1 | | 1,255.5 |
| | 1,091.5 |
| | 1,092.0 |
| | 1,255.6 |
|
| Dividend declared per common share | | 0.08 |
| | 0.09 |
| | 0.09 |
| | 0.09 |
|
|
| |
| 1 | Long term debt includes current and long term portion of debt and convertible debentures |
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 $127.9 million and $343.5 million over the prior two year period. A number of factors impact quarterly results including acquisitions, seasonal fluctuations, hydrology and winter and summer rates built into the PPAs. In addition, a factor impacting revenues year over year is the fluctuation in the strength of the Canadian dollar relative to the U.S. dollar which can result in significant changes in reported revenue from U.S. operations.
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| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
Quarterly net earnings attributable to shareholders have fluctuated between net earnings attributable to shareholders of $35.9 million and a net loss of $18.1 million over the prior two year period. Earnings have been significantly impacted by non-cash factors such as deferred tax recovery and expense, impairment of intangibles, property, plant and equipment and mark-to-market gains and losses on financial instruments.
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| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
ISSUANCE OF FOURTH QUARTER AND YEAR END FINANCIAL RESULTS
Shortly before the originally scheduled release of its 2014 financial results, APUC became aware of certain anonymous, unproven allegations regarding certain APUC personnel. APUC shared the allegations with its auditors, and delayed releasing its financial results in order to consider, together with the auditors, whether certain of the allegations which related to Algonquin’s financial reporting and related practices could impact its financial results. This assessment, which was led by a committee of independent directors with the assistance of independent legal and accounting advisors was completed and on March 16, 2015 APUC released its financial results, having determined that the allegations did not impact APUC’s financial results. The committee’s investigation into the allegations which are not related to APUC’s financial reporting and related practices is continuing to be dealt with in a confidential manner in accordance with APUC’s complaint-handling policies.
DISCLOSURE CONTROLS
At the end of the fiscal year ended December 31, 2014, APUC carried out an evaluation, under the supervision of and with the participation of APUC’s management, including the Chief Executive Officer (“CEO”) and the Chief Financial Officer (“CFO”), of the effectiveness of the design and operations of APUC’s disclosure controls and procedures (as defined in Rule 13a – 15(e) and Rule 15d – 15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on that evaluation, the CEO and the CFO have concluded that as of December 31, 2014, APUC’s disclosure controls and procedures are effective.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
APUC’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of APUC; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of APUC are being made only in accordance with authorizations of management and directors of APUC; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of APUC’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
During the year ended December 31, 2014, there has been no change in APUC’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, APUC’s internal control over financial reporting. On May 14, 2013, the Committee of Sponsoring Organizations of the Treadway Commission (COSO) published
an updated Internal Control - Integrated Framework (2013) and related illustrative documents. The company adopted the new framework in 2014.
Management conducted an evaluation of the design and operation of APUC’s internal control over financial reporting as of December 31, 2014 based on the criteria set forth in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls, and a conclusion on this evaluation. Based on this evaluation, management has concluded that APUC’s internal control over financial reporting was effective as of December 31, 2014.
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
The preparation of consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, related amounts of revenues and expenses, and disclosure of contingent assets and liabilities. Significant areas requiring the use of management estimates relate to the useful lives and recoverability of
depreciable assets, recoverability of deferred tax assets, rate-regulation, unbilled revenue, pension and post-employment benefits, fair value of derivatives and fair value of assets and liabilities acquired in a business combination. Actual results may differ from these estimates.
APUC’s significant accounting policies are discussed in Note 1 to the consolidated financial statements. Management believes the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the Audit Committee of the Board of Directors of APUC.
Estimated useful lives and recoverability of Long-Lived Assets, Intangibles and Goodwill
The provisions for depreciation of property and equipment for financial reporting purposes are made on the straight-line method based on the estimated service lives of the assets. Depreciation rates on utility assets are subject to regulatory review and approval, and depreciation expense is recovered through rates set by ratemaking authorities. The recovery of those costs is dependent on the ratemaking process. Non-regulated property and equipment are depreciated on a straight-line basis over useful lives of the related assets. Management believes the lives and methods of determining depreciation are reasonable, however, changes in economic conditions affecting the industries could result in a reduction of the estimated useful lives of those non-regulated assets or in an impairment write-down of the carrying value of these properties.
The carrying value of long-lived assets, including identifiable intangibles and goodwill, is reviewed whenever events or changes in circumstances indicate that such carrying values may not be recoverable. Some of the factors APUC considers as indicators of impairment include whether a facility is operating, its plan for return to service, external influences such as natural disasters, energy pricing and profitability and changes in regulation. Changes in circumstances, market conditions and estimates of future cash flows could negatively affect the recovery of APUC’s assets and result in an impairment charge.
Valuation of Deferred Tax Assets
Income taxes are accounted for using the asset and liability method. Under this method, deferred income taxes are recognized, at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities, as well as operating loss and tax credit carryforwards. The amount of deferred tax assets recognized is limited to the amount of the benefit that is more likely than not to be realized.
In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. Although management believes the assumptions, judgments and estimates are reasonable, changes in tax laws and changes in operations could significantly impact the amounts provided for income taxes in our financial statements.
Accounting for Rate Regulation
Accounting guidance for regulated operations provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. This accounting guidance is applied to the Distribution Group’s operations. Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet as regulatory assets or liabilities and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded when it is probable that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders and industry practice. If events were to occur that would make the recovery of these assets and liabilities no longer probable, these regulatory assets and liabilities would be required to be written off or written down.
Unbilled Energy Revenues
Revenues related to natural gas, electricity and water delivery are generally recognized upon delivery to customers. The determination of customer billings is based on a systematic reading of meters throughout the month. At the end of each month, amounts of natural gas, energy or water provided to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recorded. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns compared to normal, total volumes supplied to the system, line losses, economic impacts, and composition of customer classes. Estimates are reversed in the following month and actual revenue is recorded based on subsequent meter readings.
Derivatives
APUC uses derivative instruments to manage exposure to changes in commodity prices, foreign exchange rates, and interest rates. Management’s judgment is required to determine if a transaction meets the definition of a derivative and, if it does,
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| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
whether the normal purchases and sales exception applies or whether individual transactions qualify for hedge accounting treatment. Management’s judgment is also required to determine the fair value of derivative transactions. APUC determines the fair value of derivative instruments based on forward market prices in active markets adjusted for nonperformance risk. A significant change in estimate could affect APUC’s results of operations if the hedging relationship was considered no longer effective.
Pension and Post-employment Benefits
In conjunction with recent utilities acquisitions, the Company assumed defined benefit pension and post-employment benefit plans for qualifying employees in the related acquired businesses. The obligations and related costs are calculated using actuarial concepts, which include critical assumptions related to the discount rate, expected rate of return on plan assets and medical cost trend rates. These assumptions are important elements of expense and/or liability measurement and are updated on an annual basis, or upon the occurrence of significant events. The Company used the new mortality tables (RP-2014) and the mortality improvement scale (MP-2014) that were recently released by the Society of Actuaries in the current year assumptions. This change resulted in an increase to the pension and post-employment obligations of approximately U.S. $16.5 million.
Business Combinations
The Company has completed a number of business acquisitions in the past few years. Management's judgment is required to estimate the purchase price, to identify and to fair value all assets and liabilities acquired. The determination of the fair value of assets and liabilities acquired is based upon management’s estimates and certain assumptions generally included in a present value calculation of the related cash flows. A significant change in estimate could affect APUC’s results of operations.
Additional disclosure of APUC’s critical accounting estimates is also available on SEDAR at www.sedar.com and on the APUC website at www.AlgonquinPowerandUtilities.com.
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| 2014 Annual Report | 59 |
| Algonquin Power & Utilities Corp. - Management's Discussion & Analysis |
