Algonquin Power & Utilities 40F 2013 Annual report | AQN Filing

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, 2013. The Management Discussion & Analysis (“MD&A”) should be read in conjunction with APUC’s audited consolidated financial statements for the years ended December 31, 2013 and 2012. 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 28, 2014.

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.



2013 Annual Report	1
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Use of Non-GAAP Financial Measures

Adjusted EBITDA

EBITDA is a non-GAAP metric used by many investors to compare companies on the basis of ability to generate cash from operations. APUC uses these calculations to monitor the amount of cash generated by APUC as compared to the amount of dividends paid by APUC. APUC uses Adjusted EBITDA to assess the operating performance of APUC without the effects of (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 metric used by many investors to compare net earnings from operations without the effects of certain volatile primarily non-cash items that generally have no current economic impact 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 metric 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 metric 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 metric 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



2013 Annual Report	2
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

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 $0.085 per share or $0.34 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 conducts its business primarily through two autonomous subsidiaries: Algonquin Power Co. (“APCo”) which owns and operates a diversified portfolio of non-regulated renewable and thermal electric generation utility assets; and Liberty Utilities Co. (“Liberty Utilities”), a diversified rate regulated utility which owns and operates a portfolio of North American electric, natural gas and water distribution and wastewater collection utility systems.

Algonquin Power Co.

APCo 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. APCo seeks to deliver continuing growth through development of new Greenfield power generation projects and accretive acquisitions of additional electrical energy generation facilities.

APCo owns or has interests in hydroelectric facilities with a combined generating capacity of approximately 125 MW. APCo also owns or has interests in wind powered generating stations with a combined generating capacity of 650 MW. Approximately 82% of the electrical output from the hydroelectric and wind generating facilities is sold pursuant to long term contractual arrangements which have a weighted average remaining contract life of 14 years.

APCo owns or has interests in thermal energy facilities with approximately 350 MW of installed generating capacity. Approximately 93% of the electrical output from the owned thermal facilities is sold pursuant to long term Power purchase agreements (“PPA”) with major utilities and which have a weighted average remaining contract life of 6 years.

APCo also has a pipeline of development projects that between 2014 and 2016 will add approximately 323 MW of generation capacity from wind powered generating stations and approximately 30 MW from photovoltaic solar powered generation stations with an average contract life of 22 years.

Liberty Utilities Co.

Liberty Utilities is a diversified rate regulated utility providing electricity, natural gas, water distribution and wastewater collection utility services to approximately 480,000 connections. Liberty Utilities 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, Liberty Utilities delivers continued growth in earnings through accretive acquisition of additional utility systems.

The utility systems owned by Liberty Utilities operate under rate regulation, generally overseen by the public utility commissions of the states in which they operate. Liberty Utilities reports the performance of its utility operations through three regions – West, Central, and East.

The Liberty Utilities (West) region is comprised of regulated electrical and water distribution and wastewater collection utility systems. The regulated electrical distribution utility and related generation assets (the “CalPeco Electric System”) serve approximately 47,800 electric connections in the State of California. Liberty Utilities (West) region’s regulated water and wastewater utility systems serve approximately 68,000 water and wastewater connections located in the State of Arizona.

The Liberty Utilities (Central) region is comprised of regulated natural gas and water distribution and wastewater collection utility systems. The regulated natural gas utilities serve approximately 85,600 natural gas connections located in the States of Missouri, Illinois, and Iowa. Liberty Utilities (Central) region’s regulated water distribution and wastewater collection utilities serve approximately 29,400 water and wastewater customers located in the States of Arkansas, Illinois, Missouri, and Texas.



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Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Liberty Utilities (East) region is comprised of regulated natural gas and electric distribution utility systems located in the State of New Hampshire, and regulated natural gas distribution utility systems located in the States of Georgia and Massachusetts. Liberty Utilities provides regulated local electrical utility services to approximately 43,800 electric connections in the state of New Hampshire; and regulated local gas distribution utility services to approximately 206,200 natural gas connections located in the states of Georgia, New Hampshire and Massachusetts.

Major Highlights

2013 Corporate Highlights

Dividend Increased to $0.34 per Common Share Annually

APUC has completed several acquisitions and has advanced a number of other initiatives 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 May 9, 2013, the Board approved a dividend increase of $0.03 per share annually bringing the total annual dividend to $0.34, paid quarterly at the rate of $0.085 per common share.

Management believes that the increase in the 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.

Credit Rating Upgrade

In the fourth quarter of 2013, Standard & Poor's Ratings Services raised its long-term corporate credit rating on APUC, APCo and Liberty Utilities to 'BBB' from 'BBB-'. As well, Standard & Poor's raised its global scale and Canada scale preferred stock ratings on APUC to 'BB+' and 'P-3 (High)' from 'BB' and 'P-3', respectively.

According to Standard & Poor's, the upgrade reflects a significant increase in regulated cash flow from Liberty Utilities owing to a number of acquisitions in the past 18 months, as well as an expectation that adjusted funds from operations-to-debt levels will continue to increase in the near-to-medium term. Standard & Poor's has also provided a stable outlook for the company owing to the assessment of relatively stable cash flows, supported by regulated cash flow from Liberty's regulated utility business, and APCo's largely contracted power asset portfolio.

The Company expects the rating to further improve access to the debt capital markets, reduce credit charges and a lower the overall cost of capital of the Company.

Related party transactions

In 2011, the Board formed an independent committee (“Independent Board Committee”) and initiated a process to review all of the remaining historic business associations with APUC's Chief Executive Officer ("CEO") and Vice-Chair with an objective to reduce and/or eliminate these relationships.

The process initiated in 2011 has now been completed and all related party transactions between APUC and the CEO and Vice Chair have been resolved to the satisfaction of the Independent Board Committee and the Board. The resolution of the related party matters is described in more detail later in this MD&A under "Related Party Transactions".

Strengthened Balance Sheet

Issuance of $100 million Preferred Shares

Subsequent to year-end, on March 5, 2014, APUC issued 4.0 million cumulative rate resent preferred shares, Series D (the "Series D Shares") at a price of $25 per share, for aggregate gross proceeds of $100 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 will be used to partially finance certain of APUC’s previously disclosed growth opportunities, reduce amounts outstanding on APUC’s credit facilities and for general corporate purposes.

Emera Share Subscription

Pursuant to previously committed subscription receipts, on February 7, 2013, APUC issued 2.6 million shares at a price of $5.74 per share to Emera Incorporated (“Emera”). Additionally, on February 14, 2013, APUC issued 5.2 million shares at a price of $5.74 per share and 3.4 million shares at a price of $4.72 per share to Emera. On March 26th APUC issued 4.0 million common shares at a price of $7.40 per share for total cash proceeds of $29.3 million pursuant to a subscription agreement with 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.



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Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

As a result, as at December 31, 2013, Emera owns 50.1 million APUC common shares representing approximately 24.2% of the total outstanding common shares of the Company.

Conversion and Redemption of Series 3 Convertible Debentures to Equity

On January 2, 2013, APUC completed a redemption of the outstanding Series 3 Debentures by issuing and delivering 150,816 APUC common shares for the remaining $1.0 million Series 3 Debentures.

APUC Credit Facility

2013 Liberty Utilities Highlights

Acquisition of the New England Gas System

On February 11, 2013, Liberty Utilities entered into an agreement with The Laclede Group, Inc. (“Laclede”) to assume Laclede’s rights to purchase the assets of the New England Gas Company (“New England Gas System”) from an affiliate of Southern Union Company. The New England Gas System is a natural gas distribution utility serving over 55,000 connections in Massachusetts. The acquisition closed in the fourth quarter of 2013. The results of the New England Gas System are reported in the Liberty Utilities (East) region.

Total purchase price for the New England Gas System is approximately U.S. $59.1 million, subject to certain working capital and other closing adjustments. The acquisition was funded using a targeted 52% equity, 48% debt capital structure including the assumption of U.S. $19.5 million of existing debt.

Acquisition of the Peach State Gas System

On April 1, 2013 Liberty Utilities completed the acquisition of regulated natural gas distribution utility systems serving Columbus and Gainesville, Georgia (“Peach State Gas System”, formerly known as Columbus/Gainseville Gas System). The total purchase price for the Peach State Gas System adjusted for certain working capital and other closing adjustments, is approximately U.S. $153.0 million. The regulated natural gas distribution utilities provide natural gas service to approximately 60,000 total connections in Georgia.

Acquisition of the Pine Bluff Water System

On February 1, 2013, Liberty Utilities completed the acquisition of issued and outstanding shares of United Water Arkansas Inc. (“Pine Bluff Water System”), a regulated water distribution utility from United Waterworks Inc. The Pine Bluff Water System is located in Pine Bluff, Arkansas and serves approximately 17,700 water distribution connections. Total purchase price for the Pine Bluff Water System, adjusted for certain working capital and other closing adjustments, is approximately U.S. $27.9 million.

Acquisition of Remaining Interest in the CalPeco Electric System

On February 14, 2013, APUC issued 3.4 million common shares to Emera representing the balance of the subscription receipts outstanding pursuant to the acquisition in 2012 of the remaining 49.999% ownership in California Pacific Utility Ventures LLC, which owns 100% of the CalPeco Electric System.

U.S. Debt Private Placements

On July 31, 2013, Liberty Utilities issued U.S. $125.0 million of debt through a private placement in the U.S. The financing is the third series of notes issued pursuant to Liberty Utilities’ master indenture. The notes are senior unsecured with an average life maturity of approximately ten years and a weighted average coupon of 3.81%. The proceeds of the private placement financing were used to repay a U.S. $100.0 million short term acquisition facility used in connection with the acquisition of the Peach State Gas System, reduce the drawn amount on Liberty’s revolving credit facility and for general corporate purposes.

On March 14, 2013 Liberty Utilities completed a U.S. $15.0 million private placement debt financing. The notes are senior unsecured with a 10 year term and a coupon of 4.14%.

Liberty Utilities Credit Facility

On September 30, 2013, Liberty Utilities increased the credit available under the senior unsecured revolving credit facility (the "Liberty Facility") to U.S. $200.0 million from U.S. $100.0 million. The larger credit facility provides Liberty Utilities with the additional liquidity required resulting from the various acquisitions completed in 2013 and on execution of near term organic growth opportunities. In addition to a larger credit facility, the tenor has been increased from three years to five years and several other terms under the facility, including pricing, have improved. The amended facility will now expire on September 30, 2018.



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Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Granite State Electric System Rate Proceedings

On March 29, 2013, the Granite State Electric System with the 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. The filing is based on a 2012 test year, with revenues and expenses adjusted to reflect known and measurable changes. Among other things, Granite State Electric System requested and received approval to continue the current cost-recovery tracking mechanism related to the Reliability Enhancement and Vegetation Management Plan and was granted an annual rate increase of U.S. $0.4 million starting July 1, 2013. The Granite State Electric System also requested a modification to allow for recovery of pre-staging personnel and equipment for qualifying storms. On June 27, 2013, the NHPUC approved a settlement agreement authorizing a temporary annual rate increase of U.S. $6.5 million effective July 1, 2013, and provides recognition for Liberty to request an increase to its storm recovery adjustment factor (“SRAF”). On January 22, 2014, the Granite State Electric System entered a settlement with the New Hampshire PUC Staff, which will provide for a rate increase of U.S. $10.9 million consisting of U.S. $9.8 million in base rates and an additional U.S. $1.1 million for incremental capital expended after the test year. In addition, the settlement allows for one time recovery of rate case expenses of U.S. $0.4 million. It is anticipated that the settlement will be approved in late in Q1 2014.

2013 Algonquin Power Co. Highlights

Agreement to Acquire the Remaining 40% of a 400 MW Wind Power Portfolio

On November 28, 2013, APCo entered into an agreement to acquire the remaining 40% of the 400 MW wind power portfolio (the “U.S. Wind Portfolio”) in the United States from Gamesa Wind US, LLC (“Gamesa”) for total consideration of approximately U.S. $117.0 million.

APCo currently holds a 60% controlling interest in the U.S. Wind Portfolio which were originally acquired through a newly formed partnership whose original members included APCo, Gamesa and certain tax equity investors. The 400 MW wind portfolio consists of three facilities, Minonk (200MW), Senate (150MW), and Sandy Ridge (50MW) located in the states of Illinois, Texas, and Pennsylvania, respectively.

APCo has been the majority owner and manager of the U.S. Wind Portfolio since 2012 when commercial operation was achieved, therefore no additional ongoing management or administrative costs are expected to be incurred. Gamesa will continue to provide operations, warranty and maintenance services for the wind turbines and balance of plant facilities under 20 year contracts. The acquisition will be funded primarily from the proceeds from the APCo $200.0 million debentures issued early in 2014.

Acquisition of the 20 MWac Bakersfield Solar Project

On November 28, 2013, APCo entered into an agreement to purchase and complete construction of a 20 MWac Bakersfield Solar Facility (“Bakersfield Solar Project”) 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. APCo plans to enter 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. It is anticipated that the total expected capital costs for the project of U.S. $58.5 million will be funded as to 55% by APCo and the balance by the Tax Partner. Subject to receipt of final permits and approvals and reaching satisfactory agreement with the Tax Partner, construction of the project is anticipated to commence in the second quarter of 2014 with a commercial operations date expected to occur in late 2014.

Acquisition of Shady Oaks Wind Facility

On January 1, 2013, APCo acquired a 109.5 MW contracted wind powered generating station (“Shady Oaks Wind Facility") by assuming long-term debt of U.S. $150.0 million and for no additional cash, subject to final closing adjustments for working capital, energy generated by the projected and basis differences between node and hub prices.

The Shady Oaks Wind Facility is located in Northern Illinois, approximately 80 km west of Chicago, Illinois and achieved commercial operation in June 2012.

The facility is comprised of 68 Goldwind GW82 1.5MW and 3 Goldwind GW100 2.5MW permanent magnet direct-drive wind turbines; these turbines are well suited for the wind regime, and offer significant technological advantages providing proven reliability, enhanced energy production efficiency and lower long term maintenance costs. Through its affiliate, Goldwind International SO Limited has assumed all operations, maintenance, and capital repair responsibilities for the Shady Oaks Wind Facility pursuant to a 20 year fixed price agreement for the turbines and balance of plant facilities.

Total annual energy production is expected to be 364 GW-hrs per year. The Shady Oaks Wind Facility has entered into a 20 year inflation indexed power purchase agreement with the largest electric utility in the state of Illinois, Commonwealth Edison (BBB flat stable: Moody’s, S&P) for 310 GW-hrs of energy per year. All energy produced in excess of that sold under the power purchase agreement will be sold into the energy market in which the facility is located.



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Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Energy From Waste Facility

During the second quarter of 2013, the Company concluded that its Energy from Waste (“EFW”) and Brampton Cogeneration Inc. (“BCI”) Thermal Facilities were no longer considered strategic to its ongoing operations, commenced a process to divest of the facilities and wrote the net assets of the facilities down to its estimated fair value, less cost of sale which resulted in a write down of $35.7 million, net of tax. On February 7, 2014 the Company entered into an agreement to sell the EFW and BCI Thermal Facilities. Accordingly, the determination of the fair values of the net assets of EFW and BCI Themal Facilities were revised to reflect the estimated selling price under the agreement, which resulted in a further write down of the net assets of $6.8 million net of tax as at December 31, 2013. The final selling price is subject to customary closing adjustments. Closing of the transaction is subject to certain regulatory approvals which are expected to be received by the end of the first quarter or early in the second quarter of 2014.

Completion of Cornwall Solar Project

During the second quarter APCo began construction of the 10 MWac solar projected located near Cornwall, Ontario. The facility is the first solar project in APCo’s portfolio and is expected to add 13,900 MW-hrs of production annually. Completion of construction is expected late in the first quarter of 2014 at an estimated total capital cost of $45.0 million.

Sale of Small U.S. Hydro Facilities

On March 14, 2013, APCo entered into an agreement to sell ten small U.S. hydroelectric generating facilities that were no longer considered strategic to the ongoing operations of the Company for gross proceeds of U.S. $27.0 million. APCo closed the sale of nine of the ten facilities on June 28, 2013 for total proceeds of approximately U.S. $23.4 million with the tenth facility expected to be sold in the second quarter of 2014. The operating results from these facilities for current and prior periods are therefore disclosed as discontinued operations on the consolidated statements of operations.

APCo $200 million Senior Unsecured Debentures

On January 17, 2014, APCo issued $200.0 million 4.65% senior unsecured debentures with a maturity date of February 15, 2022 (the "APCo Debentures") pursuant to a private placement in Canada and the United States. The APCo 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, APCo entered into a fixed for fixed cross currency swap, coterminous with the APCo 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 will be 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 its bank credit facility and for general corporate purposes.



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Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

2013 Annual Results from Operations

APUC recorded significant growth in both its regulated and non-regulated utility businesses in 2013. The results for the year reflect the full year of operation from four newly acquired U.S. wind generation facilities and the full year of operation of U.S. gas and electric utilities acquired in 2012 and the additional acquisition of U.S. gas distribution and water distribution utilities in 2013.

Key Selected Annual Financial Information



	Year ended December 31
(millions of dollars except per share information)	2013		2012		2011
Revenue	$	675.3	$	348.8	$	247.5
Adjusted EBITDA ¹	226.9		88.1		94.4
Cash provided by operating activities	98.9		63.0		69.7
Adjusted funds from operations¹	153.5		66.8		63.6
Net earnings attributable to Shareholders from continuing operations	62.3		13.5		22.9
Net earnings attributable to Shareholders	20.3		14.5		23.4
Adjusted net earnings ¹	60.9		18.9		37.0
Dividends declared to Common Shareholders	68.3		50.2		32.4
Weighted Average number of common shares outstanding	204,350,689		158,304,340		116,712,934
Per share
Basic net earnings from continuing operations	$	0.28	$	0.08	$	0.20
Basic net earnings	$	0.07	$	0.09	$	0.20
Adjusted net earnings ^{1, 2}	$	0.27	$	0.11	$	0.32
Diluted net earnings	$	0.07	$	0.09	$	0.20
Cash provided by operating activities ^{1, 2}	$	0.48	$	0.40	$	0.60
Adjusted funds from operations^{1, 2}	$	0.72	$	0.42	$	0.54
Dividends declared to Common Shareholders	$	0.33	$	0.30	$	0.27
Total assets	3,472.6		2,779.0		1,282.3
Long term liabilities³	1,255.6		770.8		455.0



1	APUC uses adjusted EBITDA, adjusted net earnings and adjusted funds from operations to enhance assessment and understanding of the operating performance of APUC without the effects of certain accounting adjustments which are derived from a number of non-operating factors, accounting methods and assumptions. (see "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	Long term debt includes current and long term portion of debt and convertible debentures.

For the year ended December 31, 2013, APUC experienced an average U.S. exchange rate of approximately $1.0301 as compared to $0.999 in the same period in 2012. 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, 2013, APUC reported total revenue of $675.3 million as compared to $348.8 million during the same period in 2012, an increase of $326.5 million or 93.6%. The major factors resulting in the increase in APUC revenue for the year ended December 31, 2013 as compared to the corresponding period in 2012 are set out as follows:



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Algonquin Power & Utilities Corp. - Management's Discussion & Analysis



	Year to date December 31, 2013
	(millions)
Comparative Prior Period Revenue	$	348.8

Significant Changes:
Liberty Utilities:
West – Implementation of decoupling mechanism and increased customer demand	4.1
Central – Revenue increase due to the Midstates Gas Systems, and the Pine Bluff Water System acquisitions	59.0
East – Increased revenue resulting from the acquisitions of: the EnergyNorth Gas System, the Granite State Electric System, the Peach State Gas System, and the New England Gas System	176.1

APCo:
Renewable:
Acquisition of the Sandy Ridge, Minonk, Senate and Shady Oaks Wind Facilities (collectively, the "U.S. Wind Facilities")	50.5
Sale of Renewable Energy Credits generated from the U.S. Wind Facilities	5.7
Increased demand for retail sales at AES	2.1
St Leon II Wind Facility – Revenue increase from expansion	1.9
Effect of hydrology resource compared to comparable period in prior year	4.5
Thermal:
Sanger Facility - Increase due to planned shutdown in 2012	4.6
Impact of the stronger U.S. dollar	18.8
Other	(0.8		)
Current Period Revenue	$	675.3

A more detailed discussion of these factors is presented within the business unit analysis.

Adjusted EBITDA in the year ended December 31, 2013 totalled $226.9 million as compared to $88.1 million during the same period in 2012, an increase of $138.8 million or 157.5%. The increase in Adjusted EBITDA was primarily due to acquisitions completed in 2012 and 2013, impact of rate case settlements, increased hydrology and increased customer demand at the CalPeco Electric System. 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, 2013, net earnings from continuing operations attributable to Shareholders totalled $62.3 million as compared to $13.5 million during the same period in 2012, an increase of $48.8 million. The increase was due to $112.3 million in increased earnings from operating facilities, $0.5 million in increased interest, dividend and other income, $5.5 million in decreased acquisition costs, $5.0 million in increased gains from derivative instruments, and $18.2 million in decreased allocations of earnings to non-controlling interests as compared to the same period in 2012. These items were partially offset by $46.8 million increased depreciation and amortization expense, $3.9 million in increased administration charges, $17.7 million in higher interest expense, $0.8 million in increased losses on sale of assets, and $23.5 million in increased income tax expense (tax explanations are discussed in APUC: Corporate and Other Expenses).

For the year ended December 31, 2013, net earnings (including discontinued operations) attributable to Shareholders totalled $20.3 million as compared to $14.5 million during the same period in 2012, an increase of $5.8 million. Net earnings per share totalled $0.07 for the year ended December 31, 2013, as compared to $0.09 during the same period in 2012.

During the year ended December 31, 2013, cash provided by operating activities totalled $98.9 million or $0.48 per share as compared to cash provided by operating activities of $63.0 million, or $0.40 per share during the same period in 2012. During the year ended December 31, 2013, adjusted funds from operations, a non-GAAP measure, totalled $153.5 million or $0.72 per share as compared to adjusted funds from operations of $66.8 million, or $0.42 per share during the same period in 2012 an increase of 86.7 million.



2013 Annual Report	9
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

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.

2013 Three month results from operations

Key Selected Fourth Quarter Financial Information



	Quarter ended December 31
(millions of dollars except per share information)	2013		2012
Revenue	$	205.3	$	138.9
Adjusted EBITDA ¹	67.6		24.0
Cash provided by operating activities	31.3		17.1
Adjusted funds from operations¹	45.9		24.6
Net earnings attributable to Shareholders from continuing operations	19.8		6.8
Net earnings attributable to Shareholders	13.1		6.4
Adjusted net earnings¹	18.5		6.5
Dividends declared to Common Shareholders	17.6		15.5
Weighted Average number of common shares outstanding	206,219,121		169,860,332
Per share
Basic net earnings/(loss) from continuing operations	$	0.09	$	0.04
Basic net earnings/(loss)	$	0.06	0.03
Adjusted net earnings^{1, 2,}	$	0.08	$	0.03
Diluted net earnings/(loss)	$	0.06	$	0.05
Cash provided by operating activities ^{1, 2,}	$	0.15	$	0.10
Adjusted funds from operations^{1, 2}	$	0.22	$	0.14
Dividends declared to Common Shareholders	$	0.09	$	0.08



1	APUC uses adjusted EBITDA, adjusted net earnings and adjusted funds from operations to enhance assessment and understanding of the operating performance of APUC without the effects of certain accounting adjustments which are derived from a number of non-operating factors, accounting methods and assumptions. (see "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, 2013, APUC experienced an average U.S. exchange rate of approximately $1.050 as compared to $0.991 in the same period in 2012. 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, 2013, APUC reported total revenue of $205.3 million as compared to $138.9 million during the same period in 2012, an increase of $66.4 million. The major factors resulting in the increase in APUC revenue in the three months ended December 31, 2013 as compared to the corresponding period in 2012 are set out as follows:



2013 Annual Report	10
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis



	Quarter ended December 31, 2013
	(millions)
Comparative Prior Period Revenue	$	138.9

Significant Changes:
Liberty Utilities:
West – Implementation of decoupling mechanism and increased customer demand	0.3
Central – Revenue increase due to the acquisition of the Pine Bluff Water System and increased customer demand in the Midstates Gas Systems.	5.0
East – Revenue increase due to the acquisition of the Peach State Gas System and the New England Gas System and increased customer demand at the Granite State Electric System and the EnergyNorth Gas System	32.4

APCo:
Renewable
Acquisition of the Minonk, Senate and Shady Oaks Wind Facilities	12.1
Sale of Renewable Energy Credits generated from the U.S. Wind Facilities	2.2
Effect of hydrology resource compared to comparable period in prior year	1.1
Increased rates at AES	1.7
St. Leon Wind Facilities - Increased average realized rates	0.9
Thermal
Increased average price at the Sanger Facility	0.5
Impact of the stronger U.S. dollar	12.0
Other	(1.8		)
Current Period Revenue	$	205.3

A more detailed discussion of these factors is presented within the business unit analysis.

Adjusted EBITDA in the three months ended December 31, 2013 totalled $67.6 million as compared to $24.0 million during the same period in 2012, an increase of $43.6 million or 181.7%. The increase in Adjusted EBITDA was primarily due to acquisitions completed in 2012 and 2013, impact of rate case settlements, increased hydrology and increased customer demand at the CalPeco Electric System. 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, 2013, net earnings attributable to Shareholders from continued operations totalled $19.8 million as compared to $6.8 million during the same period in 2012, an increase of $13.0 million. The increase was due to $28.3 million increased earnings from operating facilities, $0.2 million in decreased administration charges, $0.6 million in decreased acquisition costs, $2.3 million in increased gains from derivative instruments, and $9.7 million decrease in allocations of earnings to non-controlling interests as compared to the same period in 2012. These items were partially offset by $10.5 million increased depreciation and amortization expense, $1.4 million due to a decrease in foreign exchange gain, $3.2 million in higher interest expense, $0.7 million decrease in interest, dividend and other income, $0.6 increased losses on sale of assets, and $11.7 million in increased income tax expense (tax explanations are discussed in APUC: Corporate and Other Expenses) as compared to the same period in 2012.

For the three months ended December 31, 2013, net earnings (including discontinued operations) attributable to Shareholders totalled $13.1 million as compared to net earnings attributable to Shareholders of $6.4 million during the same period in 2012, an increase of $6.7 million. Net earnings per share totalled $0.06 for the three months ended December 31, 2013, as compared to net earnings per share of $0.03 during the same period in 2012.

During the three months ended December 31, 2013, cash provided by operating activities totalled $31.3 million or $0.15 per share as compared to cash provided by operating activities of $17.1 million, or $0.10 per share during the same period



2013 Annual Report	11
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

in 2012. During the three months ended December 31, 2013, adjusted funds from operations totalled $45.9 million or $0.22 per share as compared to adjusted funds from operations of $24.6 million, or $0.14 per share during the same period in 2012. The change in adjusted funds from operations in the three months ended December 31, 2013, is primarily due to increased earnings from operations, as compared to the same period in 2012.



2013 Annual Report	12
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

APCo: Renewable Energy Division



		Three months ended December 31							Year ended December 31
	Long Term Average Resource	2013			2012			Long Term Average Resource	2013			2012
Performance (GW-hrs sold)
Hydro Facilities:
Ontario Region⁷	33.8	39.3			7.3			141.0	90.4			95.4
Quebec Region	73.1	68.0			70.0			275.9	277.6			263.4
Maritime Region (incl TPI)	45.6	37.9			31.6			177.7	203.1			133.1
Western Region	12.6	12.1			11.5			65.0	66.6			64.8
	165.1	157.3			120.4			659.6	637.7			556.7
Wind Facilities:
Manitoba Region	121.4	116.5			106.6			430.2	398.0			405.0
Saskatchewan Region¹	24.1	22.8			20.7			88.0	79.1			82.7
Pennsylvania Region²	43.6	38.7			34.8			158.3	138.8			55.9
Illinois Region³	296.2	271.5			46.8			1,037.4	938.8			46.8
Texas Region⁴	140.0	133.8			33.9			520.4	524.5			33.9
	625.3	583.3			242.8			2,234.3	2,079.2			624.3
Total	790.4	740.6			363.2			2,893.9	2,716.9			1,181.0

Revenue⁵		(millions)			(millions)				(millions)			(millions)
Energy sales		$	40.3		$	22.9			$	145.6		$	84.2
Less:
Cost of Sales – Energy⁶		(3.8		)	(1.7		)		(8.8		)	(8.9		)
Net Energy Sales		$	36.5		$	21.2			$	136.8		$	75.3

Renewable Energy Credits		2.3			0.2				5.7			0.2
Other Revenue		0.3			0.6				1.4			1.7
Total Net Revenue		$	39.1		$	22.0			$	143.9		$	77.2
Expenses
Operating expenses		(11.3		)	(5.3		)		(40.1		)	(21.4		)
Interest and Other income		0.5			0.5				1.9			2.0
HLBV income/(loss)		6.8			(9.5		)		20.4			(10.7		)
Division operating profit		$	35.1		$	7.7			$	126.1		$	47.1



2013 Annual Report	13
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis



1	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.
2	Represents the operations of the Sandy Ridge Wind Facility which was acquired on July 1, 2012.
3	Represents the operations of the Minonk and the Shady Oaks Wind Facilities which were acquired on December 10, 2012 and January 1, 2013, respectively. Production at the Shady Oaks was 88.7 GWhrs in the 3 month period and 317.1 GWhrs in the 12 month period ended December 31, 2013. Production at Shady Oaks can be subject to congestion related curtailment by the independent system operator but in this case compensation is expected to be received for lost energy sales.
4	Represents the operations of the Senate Wind Facility which was acquired on December 10, 2012.
5	While most of APCo’s PPAs include annual rate increases, a change to the weighted average production levels resulting in higher average production from facilities 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.
6	Cost of Sales - Energy consists of energy purchases by Algonquin Energy Services (“AES”) which is resold to its retail and industrial customers. Under GAAP, in APUC’s year-end consolidated Financial Statements, these amounts are included in operating expenses.
7	APCo's Long Sault hydro facility was offline during most of the first nine months of 2013 but with lost revenue covered by insurance. See below for additional commentary

2013 Annual Operating Results

Production data, revenue and expenses have been adjusted to remove the results of the New York and New England Hydro Facilities which are now disclosed as discontinued operations. See Financial Statement note 20 for details.

For the twelve months ended December 31, 2013, the Renewable Energy Division produced 2,716.9 GW-hrs of electricity, as compared to 1,181.0 GW-hrs produced in the same period in 2012, an increase of 130.1%. The increased generation is primarily due to the acquisition of Sandy Ridge, Minonk, Senate, and Shady Oaks Wind Facilities. This level of production represents sufficient renewable energy to supply the equivalent of 201,200 homes on an annualized basis with renewable power. Using new standards of thermal generation, as a result of renewable energy production, the equivalent of 1,992,400 tons of CO₂ gas was prevented from entering the atmosphere in the twelve months ended 2013.

Adjusting for the effect of the unplanned outage at APCo’s Long Sault Hydro Facility generating station, during the twelve months ended December 31, 2013, the division generated electricity equal to 95.3% of long-term projected average resources (wind and hydrology) as compared to 92.8% during the same period in 2012. As a result, the division's operating profit for the twelve months ended December 31, 2013 is $11.0 million lower than what would have been generated had the facilities achieved their expected long term average production. In the twelve months of 2013, the Maritime region’s operating facilities produced 14% above long-term average resources; while the Quebec, Western, and Texas regions produced 1% to 5% higher than long-term average resources. The Ontario, Manitoba, Saskatchewan, Pennsylvania, and Illinois regions experienced resources lower than long-term average resources, producing 10% to 15% below long-term average resources.

For the twelve months ended December 31, 2013, revenue from energy sales in the Renewable Energy Division totalled $145.6 million, as compared to $84.2 million during the same period in 2012, an increase of $61.4 million. As the purchase of energy by the Algonquin Energy Services ("AES) Business is a significant revenue driver and component of variable operating expenses, the division compares ‘net energy sales’ (see non-GAAP Financial Measures) as a more appropriate measure of the division’s sales results. For the twelve months ended December 31, 2013, net energy sales in the Renewable Energy Division totalled $136.8 million, as compared to $75.3 million during the same period in 2012.

Revenue from generation at APCo’s hydro facilities located in the Ontario (excluding Long Sault), Quebec and Western regions increased by $3.1 million primarily as a result of better hydrology in the Quebec Region and Dickson Dam. Lost production from the unplanned shutdown at the Long Sault generating facility in Ontario was largely covered by business interruption insurance claim proceeds and hence did not have a significant impact on 2013 results. Revenue from APCo’s hydro facility located in the Maritime region increased by $0.4 million primarily due to a $2.0 million increase in production due to better hydrology, offset by a $1.6 million decrease in weighted average energy rates, as compared to the same period in 2012.

Revenue from APCo’s wind facilities located in the Manitoba region increased $1.6 million due primarily to $1.9 million from the expansion of St. Leon Wind Facility, offset partially by $0.3 million due to lower wind resources. Revenues from APCo’s Sandy Ridge Wind Facility located in the Pennsylvania region increased $3.7 million as compared to the same period in 2012 as the facility was acquired on July 1, 2012. Revenues from APCo's wind facilities located in the Texas and Illinois regions increased by $48.4 million given that these facilities were acquired in December 2012 and January 2013.



2013 Annual Report	14
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Revenue at AES increased $2.3 million or 11% primarily due to increased customer load served. Revenue at AES primarily consists of 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 Facility and other revenue.

For the twelve months ended December 31, 2013, energy purchase costs by AES totalled $8.8 million as compared to $8.9 million during the same period in 2012, a decrease of $0.1 million. AES’ energy purchase costs for the twelve months ended December 31, 2013 was primarily due to a lower volume of energy purchases from external suppliers due to increased power supplied from the Tinker facility, partially offset by higher average prices. During this period, AES purchased approximately 91.6 GW-hrs of energy at market and fixed rates averaging U.S. $93.4 per MW-hr. During the twelve months, the Maritime region generated approximately 67% of the energy required to service its customers as well as AES’ customers, as compared to 44% in the same period in 2012.

For the twelve months ended December 31, 2013, Renewable Energy Credits ("REC") revenue totalled $5.7 million as compared to $0.2 million in the same period in 2012, representing an increase of $5.5 million. REC units are generated at a ratio of one REC unit per one MWHr generated and are sold in the market in which the REC is generated. For the twelve months ended December 31, 2013, REC units and related revenue units were generated at the Sandy Ridge, Minonk, Senate and Shady Oaks Wind Facilities.

The Red Lily I Wind Facility located in Saskatchewan produced 79.1 GW-hrs of electricity for the twelve months ended December 31, 2013. APCo’s economic return from its investment in Red Lily I Wind Facility 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, APCo has the right to exchange these contractual and debt interests in Red Lily I Wind Facility for a direct 75% equity interest in 2016. For the twelve months ended December 31, 2013, APCo earned fees of $1.2 million (which is classified as other revenue) and interest income of $1.6 million from Red Lily I.

For the twelve months ended December 31, 2013, operating expenses excluding energy purchases totalled $40.1 million, as compared to $21.4 million during the same period in 2012, an increase of $18.7 million. The higher expenses were primarily due to the newly acquired Sandy Ridge, Senate, Minonk, and Shady Oaks Wind Facilities partially offset by lower lease and water usage costs at the Long Sault and Cote St. Catherine Hydro Facilities.

For the twelve months ended December 31, 2013 , interest and other income totalled $1.9 million, as compared to $2.0 million in the same period in 2012. 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 APCo’s earnings from its investment in Red Lily I Wind Facility, as discussed above.

Hypothetical Liquidation at Book Value (“HLBV”) income represents the value of the net tax attributes generated by APCo 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, 2013 amounted to an approximate HLBV income of $20.4 million as compared to an HLBV loss of $10.7 million during the same period in 2012. The prior year HLBV loss was primarily a result of the accelerated depreciation election that was available in the first year of operations.

For the twelve months ended December 31, 2013, the Renewable Energy Division’s operating profit totalled $126.1 million , as compared to $47.1 million during the same period in 2012, representing an increase of $79.0 million. As a result of the stronger U.S. dollar, operating profit increased by $1.4 million.

2013 Fourth Quarter Operating Results

For the quarter ended December 31, 2013, the Renewable Energy Division produced 740.6 GW-hrs of electricity, as compared to 363.2 GW-hrs produced in the same period in 2012, an increase of 103.9%. The increased generation is primarily due to the acquisition of the Minonk, Senate and Shady Oaks Wind Facilities. This level of production represents sufficient renewable energy to supply the equivalent of 164,400 homes on an annualized basis with renewable power. Using new standards of thermal generation, as a result of renewable energy production, the equivalent of 407,330 tons of CO₂ gas was prevented from entering the atmosphere in the fourth quarter 2013.

Adjusting for the effect of the unplanned outage at APCo’s Long Sault generating station during the quarter ended December 31, 2013, the division generated electricity equal to 92.6% of long-term projected average resources (wind and hydrology) as compared to 89.5% during the same period in 2012. As a result, the division's operating profit for the quarter ended December 31, 2013 is $6.3 million lower than what would have been generated had the facilities achieved their expected long term average production. In the fourth quarter of 2013, the Texas and Ontario regions operating facility produced 4% above long-term average resources; while Quebec and Western regions produced 4% to 7% lower than long-term average resources. The Maritime, Saskatchewan, Manitoba, Pennsylvania and Illinois regions were 12% to 19% below long-term average resources.

For the quarter ended December 31, 2013, revenue from energy sales in the Renewable Energy Division totalled $40.3 million , as compared to $22.9 million during the same period in 2012, for an increase of $17.4 million. As the purchase of energy by AES is a significant revenue driver and component of variable operating expenses, the division compares ‘net



2013 Annual Report	15
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

energy sales’ (see non-GAAP Financial Measures) as a more appropriate measure of the division’s sales results. For the quarter ended December 31, 2013, net energy sales in the Renewable Energy Division totalled $36.5 million, as compared $21.2 million during the same period in 2012.

Revenue from generation at APCo’s hydro facilities located in the Ontario (excluding Long Sault), Quebec and Western regions totalled $6.7 million which was consistent with the same period in 2012. The Long Sault generating facility in Ontario, returned to full operation in the third quarter resulting in an increase of $3.0 million from generation as compared to $1.8 million received from business interruption insurance in the same period in 2012. Revenue from APCo’s hydro facility located in the Maritime region increased $0.2 million primarily due to increase in weighted average energy rates.

Revenue from APCo’s wind facilities located in the Manitoba region increased $0.8 million due to higher wind resources at St. Leon Wind Facility. Revenues from APCo’s Sandy Ridge Wind Facility located in the Pennsylvania region increased $0.3 million as compared to the same period in 2012. Revenue from APCo's wind facilities located in the Texas and Illinois regions increased $12.5 million as the facilities were acquired in the fourth quarter of 2012 and first quarter of 2013.

For the three month ended December 31, 2013, revenue at AES increased $1.8 million or 46% primarily due to increased customer load served. Revenue at AES primarily consists of 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 Facility and other revenue.

For the quarter ended December 31, 2013, energy purchase costs by AES totalled $3.8 million as compared to $1.7 million during the same period in 2012, an increase of $2.1 million. AES’ increased energy purchase costs for the quarter ended December 31, 2013 was primarily due to a higher volume of energy purchases from external suppliers, at higher average prices. During this period, AES purchased approximately 40.8 GW-hrs of energy at market and fixed rates averaging U.S. $88 per MW-hr. During the quarter, the Maritime region generated approximately 44% of the load required to service its customers as well as AES’ customers, as compared to 52% in the same period in 2012.

For the quarter ended December 31, 2013, REC revenue totalled $2.3 million as compared to $0.2 million in the same period in 2012, representing an increase of $2.1 million. REC units are generated at a ratio of one REC unit per one MWHr generated and are sold in the market in which the REC is generated. For the quarter ended December 31, 2013, REC units and related revenues were generated at the Sandy Ridge, Minonk, Senate and Shady Oaks Wind Facilities.

The Red Lily I Wind Facility located in Saskatchewan produced 22.8 GW-hrs of electricity for the quarter ended December 31, 2013. APCo’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, APCo has the right to exchange these contractual and debt interests in Red Lily I Wind Facility for a direct 75% equity interest in 2016. For the quarter ended December 31, 2013, APCo earned fees of $0.2 million (which is classified as other revenue) and interest income of $0.4 million from Red Lily I Wind Facility.

For the quarter ended December 31, 2013, operating expenses excluding energy purchases totalled $11.3 million, as compared to $5.3 million during the same period in 2012, an increase of $6.0 million. The increase was primarily driven by the increase in costs as a result of the newly acquired Senate, Minonk, and Shady Oaks Wind Facilities.

For the quarter ended December 31, 2013, interest and other income totalled $0.5 million, consistent with the same period in 2012. 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 APCo’s earnings from its investment in Red Lily I Wind Facility, as discussed above.

Hypothetical Liquidation at Book Value (“HLBV”) income represents the value of net tax attributes generated by APCo in the period from certain of its U.S. wind power generation facilities. The value of net tax attributes generated in the quarter ended December 31, 2013, amounted to an approximate HLBV income of $6.8 million as compared to HLBV loss of $9.5 million. The prior year HLBV loss was primarily a result of the accelerated depreciation election that was available in the first year of operations.

For the quarter ended December 31, 2013, the Renewable Energy Division’s operating profit totalled $35.1 million, as compared to $7.7 million during the same period in 2012, representing an increase of $27.4 million. As a result of the stronger U.S. dollar operating profit increased by $0.7 million.



2013 Annual Report	16
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

APCo: Thermal Energy Division



	Twelve months ended December 31, 2013									Twelve months ended December 31, 2012
	Windsor Locks			Sanger			Total			Windsor Locks			Sanger			Total
Performance(GW-hrs sold)	115.3			137.2			252.5			190.2			100.2			290.4
Performance(steam sales – billion lbs)	623.0			—			623.0			602.2			—			602.2

(all amounts in millions)
Revenue
Energy/steam sales	$	17.7		$	16.9		$	34.6		$	17.7		$	12.4		$	30.1
Less:
Cost of Sales – Fuel	(11.2		)	(6.0		)	(17.2		)	(11.7		)	(2.9		)	(14.6		)
Net Energy Sales	$	6.5		$	10.9		$	17.4		$	6.0		$	9.5		$	15.5
Other revenue	0.5			1.9			2.4			0.3			1.4			1.7
Total net revenue	$	7.0		$	12.8		$	19.8		$	6.3		$	10.9		$	17.2
Expenses
Operating expenses	(3.7		)	(4.9		)	(8.6		)	(4.5		)	(4.1		)	(8.6		)
Facility operating profit	$	3.3		$	7.9		$	11.2		$	1.8		$	6.8		$	8.6
Interest and other income							0.2									0.5
Divisional operating profit							$	11.4								$	9.1

APCo’s Sanger and Windsor Locks Thermal Facilities generation 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 facility and regional changes in the average landed cost for natural gas may result in one facility showing increasing costs per unit while the other shows decreasing costs, as 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.

2013 Annual Operating Results

Production data, revenue and expenses have been adjusted to remove the results of the EFW Facility which are now disclosed as discontinued operations. See Financial Statement note 20 for details.

For the twelve months ended December 31, 2013, the Thermal Energy Division produced 252.5 GW-hrs of energy as compared to 290.4 GW-hrs of energy in the comparable period of 2012. The decrease in energy production was due primarily to the installation of the new Titan turbine at Windsor Locks Thermal Facility which is a smaller, more efficient turbine, sized to optimize the energy and steam requirements of the steam host, and to minimize exposure of the facility to the ISO NE electricity market, compared to the larger Frame 6 turbine that was operating in previous years. This is partially offset by an increased production at Sanger as a result of a planned outage during the first quarter of 2012.

For the twelve months ended December 31, 2013, the Thermal Energy Division’s operating profit was $11.4 million, as compared to $9.1 million during the same period in 2012. The Windsor Locks Thermal Facility contributed $3.3 million, while the Sanger Thermal Facility contributed $7.9 million of operating profit during the twelve months ended December 31, 2013 as compared to $1.8 million and $6.8 million, respectively, during the same period in the prior year. Interest and other income for twelve months ended December 31, 2013 was $0.2 million as compared to $0.5 million during the same period in the prior year a decrease of $0.3 million resulting from lower equity income received from the Valley Power Thermal Facility. As a result of the stronger U.S. dollar, operating profit increased by $0.4 million. Detailed results of each facility are described below.

Windsor Thermal Locks Facility

For the twelve months ended December 31, 2013, the Windsor Locks Thermal Facility sold 623.0 billion lbs of steam as compared to 602.2 billion lbs of steam in the comparable period of 2012.



2013 Annual Report	17
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Energy/Steam sales at the Windsor Locks Thermal Facility were $17.7 million which was consistent with the same period in 2012. The increase in energy/steam sales is attributed to a higher average price for gas and higher steam production driven by increased customer demand, partially offset by the lower electrical energy production as a result of the newly installed, smaller, more efficient Titan turbine. Natural gas costs for the period were $11.2 million as compared to $11.7 million in the same period in 2012. The decrease in natural gas costs is due to a $2.9 million decrease in the volume of gas consumed as a result of the newly installed, smaller Titan turbine offset by a $2.4 million increase in the average landed cost of natural gas.

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, 2013, net energy sales at the Windsor Locks Thermal Facility totalled $6.5 million, as compared to $6.0 million during the same period in 2012, an increase of $0.5 million.

Operating expenses, excluding natural gas costs were $3.7 million as compared to $4.5 million in the same period in 2012. The decrease in operating expenses was primarily due to the reduced electricity purchases. In 2012, during the planned shutdown, the Windsor Locks Thermal Facility was required to purchase all the electricity requirements for its customer; this additional expense was not required in the current year. The Windsor Locks Thermal Facility’s resulting net operating income for the twelve months ended December 31, 2013 was $3.3 million as compared to $1.8 million in the same period in 2012, an increase of $1.5 million.

Sanger Thermal Facility

The Sanger Thermal Facility’s operating profit was driven by energy/steam sales of $16.9 million as compared to $12.4 million in the same period in 2012, an increase of $4.5 million. The increase in energy/steam sales is primarily a result of the Sanger Thermal Facility being offline due to a planned outage for three months during the same period in the prior year. The return to operation resulted in an increase of $1.5 million due to increased electrical energy production, and $3.0 million in increased billing rates, as compared to the same period in 2012. Capacity revenues remained unchanged at $8.3 million. Gas costs for the period were $6.0 million as compared to $2.9 million in the same period in 2012. The increase in gas costs is due to an increase in the volume of natural gas consumed, and a 48% increase in the average cost of natural gas per MMBTU.

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, 2013, net energy sales at the Sanger facility totalled $10.9 million, as compared to $9.5 million during the same period in 2012, an increase of $1.4 million.

Operating expenses, excluding natural gas costs were $4.9 million as compared to $4.1 million in the same period in 2012. The increase in operating expenses was due to the Sanger Thermal Facility operating for the twelve months ended December 31, 2013, as opposed to being offline for three months during the same period in 2012. The Sanger facility’s resulting net operating income for the twelve months ended December 31, 2013 was $7.9 million, as compared to $6.8 million during the same period in 2012, an increase of $1.1 million.



2013 Annual Report	18
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis



	Three months ended December 31, 2013									Three months ended December 31, 2012
	Windsor Locks			Sanger			Total			Windsor Locks			Sanger			Total
Performance(GW-hrs sold)	28.8			35.6			64.4			35.3			35.3			70.6
Performance(steam sales – billion lbs)	161.3			—			161.3			175.3			—			175.3

(all amounts in millions)
Revenue
Energy/steam sales	$	4.6		$	3.9		$	8.5		$	5.0		$	3.3		$	8.3
Less:
Cost of Sales – Fuel	(3.1		)	(1.5		)	(4.6		)	(3.2		)	(1.2		)	(4.4		)
Net Energy/Steam Sales	$	1.5		$	2.4		$	3.9		$	1.8		$	2.1		$	3.9
Other revenue	0.2			0.6			0.8			0.2			0.4			0.6
Total net revenue	$	1.7		$	3.0		$	4.7		$	2.0		$	2.5		$	4.5
Expenses
Operating expenses	(0.8		)	(1.2		)	(2.0		)	(0.8		)	(1.3		)	(2.1		)
Facility operating profit	$	0.9		$	1.8		$	2.7		$	1.2		$	1.2		$	2.4
Interest and other income							0.1									0.3
Divisional operating profit							$	2.8								$	2.7

2013 Fourth Quarter Operating Results

Production data, revenue and expenses have been adjusted to remove the results of the EFW Facility which is now disclosed as discontinued operations. See Financial Statement note 20 for details.

For the three months ended December 31, 2013, the Thermal Energy Division produced 64.4 GW-hrs of electrical energy as compared to 70.6 GW-hrs of electrical energy in the comparable period of 2012. The decrease in electrical energy production at the Windsor Locks facility was primarily due to the installation of the new Titan turbine which is a smaller, more efficient turbine, sized to optimize the electricity and steam requirements of the steam host, and to minimize exposure of the facility to the ISO NE electricity market, compared to the larger Frame 6 turbine that was operating in previous years.

For the three months ended December 31, 2013, the Thermal Energy Division’s operating profit was $2.8 million as compared to $2.7 million in the same period in 2012, an increase of $0.1 million. The Windsor Locks Thermal Facility contributed $0.9 million, while the Sanger Thermal Facility contributed $1.8 million of operating profit during the three months ended December 31, 2013 as compared to $1.2 million and $1.2 million, respectively during the same period in the prior year. Interest and other income for three months ended December 31, 2013 was $0.1 million as compared to $0.3 million during the same period in the prior year a decrease of $0.2 million resulting from lower equity income received from the Valley Power Thermal Facility. As a result of the stronger U.S. dollar operating profit increased by $0.2 million. Detailed results of each facility are described below.

Windsor Locks

For the three months ended December 31, 2013, the Windsor Locks Thermal Facility sold 161.3 billion lbs of steam as compared to 175.3 billion lbs of steam in the comparable period of 2012.

The Windsor Locks Thermal Facility’s operating profit was driven by energy/steam sales of $4.6 million which was consistent with the same period in 2012. Gas costs for the period were $3.1 million as compared to $3.2 million in the same period in 2012. The decrease in gas costs is a result of a 4.4% increase on the average landed cost of natural gas per MMBTU offset by a 14.0% decrease in the volume of natural gas consumed, as compared to the same period in 2012.

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, 2013, net sales at the Windsor Locks Thermal Facility totalled $1.5 million, as compared to $1.8 million during the same period in 2012, a decrease of $0.3 million.



2013 Annual Report	19
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Operating expenses, excluding natural gas costs were $0.8 million which was consistent with the same period in 2012. The Windsor Locks Thermal Facility’s resulting net operating income for the three months ended December 31, 2013 was $0.9 million as compared to $1.2 million in the same period in 2012, a decrease of $0.3 million.

Sanger

The Sanger Thermal Facility’s operating profit was driven by energy/steam sales of $3.9 million as compared to $3.3 million in the same period in 2012, an increase of $0.6 million. The increase in energy/steam sales is attributed to $0.6 million in increased gas prices which is a pass through to customers as compared to the same period in 2012. Capacity revenues remained unchanged at $1.7 million. Gas costs for the period were $1.5 million as compared to $1.2 million in the same period in 2012. The increase in gas costs is due to an increase in the volume of natural gas consumed, and a 25% increase in the average cost of natural gas per MMBTU as compared to the same period in 2012.

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, 2013, net energy sales at the Sanger Thermal Facility totalled $2.4 million, as compared to $2.1 million during the same period in 2012, an increase of $0.3 million.

Operating expenses, excluding natural gas costs were $1.2 million as compared to $1.3 million in the same period in 2012. The Sanger Thermal Facility’s resulting net operating income for the three months ended December 31, 2013 was $1.8 million as compared to $1.2 million in the same period in 2012, an increase of $0.6 million.

APCo: 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 APCo’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. APCo’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 power purchase agreement, obtaining the required financing commitments to develop the project, completion of environmental permitting, and fixing the cost of the major capital components of the project. It is not until all major aspects of a project are secured that APCo will begin construction or execute an acquisition agreement.

Projects Currently in Development

APCo’s Development Division has successfully advanced a number of projects and has been awarded or acquired a number of power purchase agreements. The projects are as follows:



Project Name	Location	Size (MW)	Estimated Capital Cost		Commercial Operation	PPA Term	Production GW-hrs
Chaplin Wind ¹	Saskatchewan	177	$	340.0	2016	25	720.0
Amherst Island ²	Ontario	75	$	230.0	2015	20	247.0
Val Eo - Phase I ^{1, 6, 7}	Quebec	24	$	70.0	2015	20	66.0
Morse Wind ^{3, 4}	Saskatchewan	23	$	81.3	2015	20	108.0
Bakersfield Solar^{1, 8}	California	20	$	62.2	2015	20	53.3
St. Damase - Phase I ^{1, 5, 7}	Quebec	24	$	65.0	2014	20	78.7
Cornwall Solar ^{1, 2}	Ontario	10	$	45.0	2014	20	14.4
Total		353	$	893.5			1,287.4



2013 Annual Report	20
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis



1	PPA signed
2	FIT contract awarded
3	Two 10 MW PPAs; one 5MW PPA
4	Comprised of three projects that are connected geographically and will be built simultaneously. All three projects were awarded PPAs under the province’s Green Options Partner Program (“GOPP”).
5	The St. Damase project is being developed in two phases: Phase I of the project (24MW) will be erected in 2014 and the 101MW 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.
6	The Val Eo project is being developed in two phases: Phase I of the project (24MW) will be erected in 2015 and the 101 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.
7	Size, Estimated Capital Costs, Commercial Operation Date, PPA Term and Production refer solely to Phase I of the St. Damase and Val-Eo wind projects.
8	Total cost the project is expected to be U.S $58.5 million.

Chaplin Wind Project

In the first quarter of 2012, APCo 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 has a targeted commercial operation date of December, 2016. The facility will be constructed at an estimated capital cost of $340 million and consist of approximately 77 multi-megawatt wind turbines. The project is expected to generate first full year 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 favourable location by interconnecting with a nearby 138Kv line and will be compliant with SaskPower’s latest interconnection requirements.

The Environmental Impact Assessment was submitted in third quarter of 2013 to the Environmental Assessment Branch, Saskatchewan Environment. Screening was completed, and a proposed layout was requested in order to provide a final determination. A supplemental report was submitted in the fourth quarter of 2013 to address the questions identified during the screening process and the project is awaiting a response from the Environment Assessment Branch. As a result of continuing development work, the expected capital costs of the project have been reduced to $340 million from the original estimate of $355 million. To optimize the returns associated with the project, APCo intends to enter into a partnership agreement using a similar structure to what was utilized in the development of the Red Lily I facility.

Amherst Island Wind Project

The Amherst Island wind project is located on Amherst Island near the village of Stella, approximately 15 kilometres 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. APCo forecasts that the available wind resource could produce approximately 247 GW-hrs of electrical energy annually, depending upon the final turbine selection for the project. Total capital costs for the facility are currently estimated to be $230 million. The financing of the project will be arranged and announced when all required permitting and all other pre-construction conditions have been satisfied. Environmental studies and engineering are underway.

The Renewable Energy Approval (“REA”) application was submitted in April 2013 and was posted to the environmental registry in early January 2014. The REA is now anticipated to be received at the beginning of the third quarter of 2014. Subject to receipt of the REA approval as expected, construction is expected to commence shortly thereafter; with a planned construction time frame of 12 to 18 months. Completion is targeted to occur in late 2015 or early 2016.

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 25MW under Saskatchewan’s Green Options Partner Program, SaskPower has offered APCo a 20 year contract for the procurement of 23MW of wind generation to match the nameplate capacity of the proposed turbines.

APCo 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 APCo 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 total annual energy production for the Morse Wind Project has increased from 93.0 GW-hrs to 108.0 GW-hrs due to final turbine selection and increased hub height. Accordingly, the capital cost to construct the Morse wind project has also increased and is currently estimated to be $81.3 million, inclusive of acquisition costs. The contract rate is set at $104.02 per MW-hr for the first full year of operations, which APCo expects to occur in 2015, with an annual escalation provision of 2% over the expected 20 year term.

The provincial environmental assessment of the site was completed in the first quarter of 2012 and submitted to the provincial Environmental Assessment agency. In April 2012, the project was deemed a “non-development” by the Provincial Environmental Assessment Branch thereby not requiring further environmental assessment review.

Quebec Community Wind Projects

In December 2010, APCo, in partnership with Société en Commandite Val-Éo, a community cooperative with a development project located in the Lac Saint-Jean region of Quebec, and in partnership with the community of Saint-Damase, were awarded PPAs for the construction of two wind power projects in the Province of Quebec using ENERCON wind turbines. Both projects will represent phase one in the potential development of a larger second phase.

Saint-Damase

Phase one of the Saint-Damase wind project is located in the local municipality of Saint-Damase, which is within the regional municipality of les Maskoutains. The project is a 24MW facility located near St. Damase, Quebec in a partnership with the Municipality of Saint-Damase. The Saint-Damase wind project has signed a 20 year PPA with Hydro Quebec and has projected capital costs of $65 million. On June 25, 2013, the partnership executed an interconnection agreement with Hydro Quebec. The permitting and the environmental impact assessment are ongoing and the construction of the first project phase is planned for the early second quarter of 2014, with commercial operation for the project expected to commence in late 2014.

APCo’s interest in the project will not be less than 50%. The project’s social acceptance is strong, and about 50 jobs will be created during construction. The environmental impact assessment for the project has been reviewed and has received the provincial minister’s decree allowing the project to proceed with construction. APCo has entered into an agreement for the supply of wind turbines with Enercon Canada Inc. It is believed that the first 24MW phase of the Saint-Damase wind project will qualify as Canadian Renewable conservation expense and therefore the project will be entitled to a refundable tax credit equal to approximately $20.5 million. It is contemplated that a request for a PPA in respect of Phase II of the project will be submitted to Hydro Quebec pursuant to its current request for proposals and if successful would proceed based on the results achieved in Phase I.

Val-Éo

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 based landowners and APCo. 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 early 2015 with commercial operations commencing in late 2015. The second phase of the project would entail the development of an additional 106 MW. The permitting and the Environmental Impact Assessment are ongoing with a projected provincial minister’s decree at the end of 2014.

APCo’s 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 24MW phase of the Val-Eo wind project will qualify as Canadian Renewable Conservation Expense and therefore the project will be entitled to a refundable tax credit equal to approximately $22.0 million. It is contemplated that a request for a PPA in respect of Phase II of the project will be submitted to Hydro Quebec pursuant to its current request for proposals and if successful would proceed based on the results achieved in Phase I.

Cornwall Solar Project

In the first quarter of 2012, APCo acquired all of the issued and outstanding shares of Cornwall Solar which owns the rights to develop the Cornwall Project, a 10 MW solar project located near Cornwall, Ontario. In addition to the Cornwall Project, APCo has acquired an option to acquire ten additional Ontario based solar projects.



2013 Annual Report	21
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

The Cornwall Project has been granted a 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. The Cornwall Project contemplates the use of a ground-mounted PV array system, installed on two parcels of leased land totalling approximately 138 acres.

The Cornwall Project received its Renewable Energy Approval on January 15, 2013 and its Notice to Proceed on April 29, 2013. Construction of the project began during the second quarter of 2013 with substantial completion expected by the end of the first quarter of 2014 and commercial operation expected to commence in the second quarter of 2014. After completion of the design and start of construction, improvements in engineering layout and module capacity have led to an increase in annual energy production forecast from 13.4 GW-hrs/year to 14.4 GW-hrs/year. Generation in excess of 13.4 GW-hrs/year is paid to the original developer after minimum return thresholds are achieved by APCo.

Bakersfield Solar Project

APCo 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. APCo plans to enter 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. It is anticipated that the total expected capital costs for the project of U.S. $58.5 million will be funded as to 55% by APCo and the balance by the Tax Partner. Subject to receipt of final permits and approvals and reaching satisfactory agreement with the Tax Partner, construction of the project is anticipated to commence in the second quarter of 2014 with a commercial operations date expected to occur in late 2014.

Liberty Utilities

Liberty Utilities is a national diversified rate regulated utility providing electricity, natural gas, water distribution and wastewater collection utility services in the U.S. Liberty Utilities’ strategy is to grow its business organically and through business development activities while using prudent acquisition criteria. Liberty Utilities believes that its business results are maximized by building constructive regulatory and customer relationships, and enhancing community connections.



Utility System Type	December 31, 2013			December 31, 2012
	Assets		Connections	Assets		Connections
	U.S. $			U.S. $
	(millions)			(millions)
Electricity	$	276.6	91,600	$	254.3	91,200
Natural Gas	661.5		291,800	394.8		175,500
Water and Wastewater	233.0		97,400	205.4		78,000
Total	$	1,171.1	480,800	$	854.5	344,700

Accumulated Deferred Income Taxes	$	66.5		$	53.5

Liberty Utilities reports the performance of its utility operations by geographic region – West, Central, and East

The Liberty Utilities (West) region is comprised of regulated electrical and water distribution and wastewater collection utility systems and serves approximately 115,800 connections in the states of Arizona and California.

The Liberty Utilities (Central) region is comprised of regulated natural gas and water distribution and wastewater collection utility systems and serves approximately 115,000 connections located in the states of Arkansas, Illinois, Iowa, Missouri, and Texas.

The Liberty Utilities (East) region is comprised of regulated natural gas and electric distribution utility systems and serves approximately 250,000 connections located in the states of Georgia, Massachusetts, and New Hampshire.



2013 Annual Report	22
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Liberty Utilities: West Region



	Year ended December 31,
	2013	2012
Average Active Electric Connections For The Period
Residential	41,200	41,300
Commercial and Industrial	5,500	5,600
Total Average Active Electric Connections For The Period	46,700	46,900

Average Active Water Connections For The Period
Wastewater connections	30,700	29,700
Water distribution connections	33,900	33,100
Total Average Active Water Connections For The Period	64,600	62,800

Customer Usage (GW-hrs)
Residential	281.3	273.6
Commercial and Industrial	277.1	279.1
Total Customer Usage (GW-hrs)	558.4	552.7

Gallons Provided
Wastewater treated (millions of gallons)	1,660	1,648
Water sold (millions of gallons)	5,072	5,080
Total Gallons Provided	6,732	6,728

The Liberty Utilities (West) region’s increase in average water and wastewater connections during the period is primarily due to development within the service territory. During the twelve months ended December 31, 2013, the Liberty Utilities (West) region provided approximately 5,072 million gallons of water to its customers and treated approximately 1,660 million gallons of wastewater as compared to 5,080 million gallons of water and 1,648 million gallons of wastewater during the same period in 2012.

For the twelve months ended December 31, 2013, electricity usage at the CalPeco Electric System totalled 558.4 GW-hrs, as compared to 552.7 GW-hrs for the same period in 2012, an increase of 5.7 GW-hrs or 1.1%. This increase in usage was primarily due to colder weather experienced in the first quarter of 2013 as compared to warmer weather experienced in the same period a year ago. Under the base rate revenue decoupling mechanism approved by the California Public Utilities Commission (“CPUC”), which became effective on January 1, 2013, the CalPeco Electric System’s base rate revenues will not be 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.



2013 Annual Report	23
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis



	Year ended December 31,						Year ended December 31,
	2013 U.S. $ (millions)			2012 U.S. $ (millions)			2013 Can $ (millions)			2012 Can $ (millions)
Water Assets for regulatory purposes	179.3			181.3
Electricity Assets for regulatory purposes	175.5			165.9
Revenue
Utility electricity sales and distribution	$	75.5		$	71.9		$	77.8		$	71.7
Wastewater treatment	18.1			18.3			18.7			18.3
Water distribution	19.8			19.0			20.4			19.0
Other Revenue	—			0.2			—			0.2
Total Revenue	$	113.4		$	109.4		$	116.9		$	109.2
Less:
Cost of Sales – Electricity	(38.6		)	(44.0		)	(39.8		)	(43.9		)
Net Utility Sales	$	74.8		$	65.4		$	77.1		$	65.3
Expenses
Operating expenses	(35.6		)	(35.6		)	(36.7		)	(35.6		)
Other income	1.4			2.1			1.4			2.1
Divisional operating profit	$	40.6		$	31.9		$	41.8		$	31.8

2013 Annual Operating Results

The Liberty Utilities (West) region has investments in water and wastewater distribution assets for regulatory purposes of U.S. $179.3 million and electricity assets for regulatory purposes of U.S.$175.5 million as at December 31, 2013, as compared to U.S. $181.3 million and U.S .$165.9 million, respectively as at December 31, 2012.

For the twelve months ended December 31, 2013, the Liberty Utilities (West) region’s revenue totalled U.S. $113.4 million as compared to U.S. $109.4 million during the same period in 2012, an increase of U.S. $4.0 million or 3.7%.

For the twelve months ended December 31, 2013, the Liberty Utilities (West) region’s revenue from utility electricity sales totalled U.S. $75.5 million as compared to U.S. $71.9 million during the same period in 2012, an increase of U.S. $3.6 million or 5.0%. This increase in revenues was primarily due to an increase in base revenue requirement approved in the most recent rate case that became effective January 1, 2013 and milder winter and spring weather that occurred in the first part of 2012. 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 will not be impacted by fluctuations in customer demand due to the variations in weather conditions and changes in the number of customers.

For the twelve months ended December 31, 2013, revenue from wastewater treatment and water distribution totalled U.S. $18.1 million and U.S. $19.8 million respectively, as compared to U.S. $18.3 million and U.S. $19.0 million, respectively, during the same period in 2012. The total wastewater treatment and water distribution revenue increase was due to increased connection counts, which increased fixed and usage revenue.

For the twelve months ended December 31, 2013, fuel and purchased power costs for the Liberty Utilities (West) region totalled U.S $38.6 million , as compared with U.S. $44.0 million for the same period in 2012. The overall electricity purchase costs experienced a decrease of U.S. $5.4 million primarily as a result of a change in rates effective January 1, 2013 which refunds an over-collection of electricity costs from the prior fiscal period

The purchase of electricity by the Liberty Utilities (West) region is a significant revenue driver and component of operating expenses but these costs are effectively passed through to its customers. As a result, the Liberty Utilities (West) region compares ‘net utility sales’ (see non-GAAP Financial Measures) as a more appropriate measure of the division’s results. For the twelve months ended December 31, 2013, net utility sales for the Liberty Utilities (West) region were U.S. $74.8 million, as compared to U.S. $65.4 million during the same period in 2012, an increase of $9.4 million, or 14.4% .

For the twelve months ended December 31, 2013, operating expenses totalled U.S. $35.6 million, which was consistent with the same period in 2012.



2013 Annual Report	24
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

For the twelve months ended December 31, 2013, the Liberty Utilities (West) region’s operating profit was U.S $40.6 million as compared to U.S $31.9 million in the same period in 2012, an increase of U.S.$ $8.7 million, or 27.3%.

Measured in Canadian dollars, the Liberty Utilities (West) region’s operating profit was $41.8 million as compared to $31.8 million in the same period in 2012.



	Three months ended December 31,
	2013	2012
Average Active Electric Connections For The Period
Residential	41,600	41,300
Commercial and Industrial	5,500	5,600
Total Average Active Electric Connections For The Period	47,100	46,900

Average Active Number of Water Connections For The Period
Wastewater connections	30,900	30,100
Water distribution connections	34,100	33,400
Total Average Active Water Connections For The Period	65,000	63,500

Customer Usage (GW-hrs)
Residential	77.0	72.2
Commercial and Industrial	77.2	81.5
Total Customer Usage (GW-hrs)	154.2	153.7

Gallons Provided
Wastewater treated (millions of gallons)	418	423
Water sold (millions of gallons)	1,277	1,256
Total Gallons Provided	1,695	1,679

For the three months ended December 31, 2013, the Liberty Utilities (West) region’s electricity usage totalled 154.2 GW-hrs, as compared to 153.7 GW-hrs for the same period in 2012, an increase of 0.5 GW-hrs. 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 will not be 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.

During the three months ended December 31, 2013, the Liberty Utilities (West) region provided approximately 1,277 million gallons of water to its customers and treated approximately 418 million gallons of wastewater, as compared to 1,256 gallons of water and 423 gallons of wastewater during the same period in 2012.



2013 Annual Report	25
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis



	Three months ended December 31,						Three months ended December 31,
	2013 U.S. $ (millions)			2012 U.S. $ (millions)			2013 Can $ (millions)			2012 Can $ (millions)
Revenue
Utility electricity sales and distribution	$	19.8		$	19.5		$	20.7		$	19.3
Wastewater treatment	4.2			4.7			4.4			4.7
Water distribution	5.2			4.5			5.5			4.5
Other Revenue	—			—			—			—
	$	29.2		$	28.7		$	30.6		$	28.5
Less:
Cost of Sales – Electricity	(10.5		)	(11.5		)	(11.0		)	(11.4		)
Net Utility Sales	$	18.7		$	17.2		$	19.6		$	17.1
Expenses
Operating expenses	(8.4		)	(9.3		)	(8.9		)	(9.4		)
Other income	0.2			1.1			0.3			1.1
Division operating profit	$	10.5		$	9.0		$	11.0		$	8.8

2013 Fourth Quarter Operating Results

For the three months ended December 31, 2013, the Liberty Utilities (West) region’s revenue totalled U.S. $29.2 million as compared to U.S.$28.7 million during the same period in 2012, an increase of U.S. $0.5 million or 1.7%.

For the three months ended December 31, 2013, the Liberty Utilities (West) region’s revenue from utility electricity sales totalled U.S. $19.8 million as compared to U.S. $19.5 million during the same period in 2012, an increase of U.S. $0.3 million or 1.5%. This increase in revenues was primarily due to an increase in base revenue requirements approved in the most recent rate case that became effective January 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 will not be impacted by fluctuations in customer demand due to the variations in weather conditions and changes in the number of customers.

For the three months ended December 31, 2013 revenue from wastewater treatment and water distribution totalled U.S. $4.2 million and U.S. $5.2 million, respectively, as compared to U.S. $4.7 million and U.S. $4.5 million, respectively, during the same period in 2012. The total wastewater treatment and water distribution revenue was primarily due to an increase in average connection counts, as compared to the same period in 2012.

For the three months ended December 31, 2013 fuel and purchased power costs for the Liberty Utilities (West) region totalled U.S $10.5 million, as compared with U.S. $11.5 million for the same period in 2012, a decrease of $1.0 million. The overall electricity purchase costs experienced a decrease of U.S. $1.0 million primarily as a result of a change in rates effective January 1, 2013 which refunds an over-collection of electricity costs from the prior fiscal period.

The purchase of electricity by the Liberty Utilities (West) region is a significant revenue driver and component of operating expenses but these costs are effectively passed through to its customers. As a result, the Liberty Utilities (West) region compares ‘net utility sales' (see non-GAAP Financial Measures) as a more appropriate measure of the division’s results. For the three months ended December 31, 2013 net utility sales for the Liberty Utilities (West) region were U.S. $18.7 million, as compared to U.S. $17.2 million during the same period in 2012, an increase of $1.5 million or 8.7%.

For the three months ended December 31, 2013 operating expenses totalled U.S. $8.4 million, as compared to U.S. $9.3 million during the same period in 2012.

For the three months ended December 31, 2013, the Liberty Utilities (West) region’s operating profit was U.S. $10.5 million as compared to U.S. $9.0 million in the same period in 2012, an increase of U.S. $1.5 million or 16.7%.

Measured in Canadian dollars, the Liberty Utilities (West) region’s operating profit was $11.0 million as compared to $8.8 million in the same period in 2012.



2013 Annual Report	26
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Liberty Utilities: Central Region



	Year ended December 31,
	2013	2012
Average Active Natural Gas Connections For The Period
Residential	71,300	71,500
Commercial and Industrial	9,200	9,500
Total Average Active Natural Gas Connections For The Period	80,500	81,000

Average Active Water Connections For The Period
Wastewater connections	5,900	5,800
Water distribution connections	21,900	5,300
Total Average Active Water Connections For The Period	27,800	11,100

Customer Usage (MMBTU)
Residential	5,187,000	1,307,000
Commercial and Industrial	3,555,000	1,093,000
Total Customer Usage (MMBTU)¹	8,742,000	2,400,000

Gallons Provided
Wastewater treated (millions of gallons)	374	372
Water sold (millions of gallons)²	3,090	383
Total Gallons Provided	3,464	755



1	Represents MMBTU since August 1, 2012 acquisition date
2	Water distribution utility was acquired on February 1, 2013

The Liberty Utilities (Central) region acquired the Pine Bluff Water System on February 1, 2013 and the Midstates Gas System on August 1, 2012, and accordingly, the twelve month results for 2012 are not comparative.

For the twelve months ended December 31, 2013, the Liberty Utilities (Central) region natural gas distribution sales totalled 8,742,000 MMBTU as compared to 2,400,000 MMBTU during the same period in 2012, an increase of 6,342,000 MMBTU.

During the twelve months ended December 31, 2013, the Liberty Utilities (Central) region provided approximately 3,090 million gallons of water to its customers, and treated approximately 374 million gallons of wastewater, as compared to 383 million gallons of water and 372 million gallons of wastewater during the same period in 2012.

As a result of the acquisition of the Pine Bluff Water System on February 1, 2013 the number of water connections in the region increased by approximately 17,700. During the twelve months ended December 31, 2013, the amount of water sold correspondingly increased by 2,613 million gallons.



2013 Annual Report	27
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis



	Year ended December 31,						Year ended December 31,
	2013 U.S. $ (millions)			2012 U.S. $ (millions)			2013 Can $ (millions)			2012 Can $ (millions)
Natural Gas Assets for regulatory purposes	148.1			131.4
Water Assets for regulatory purposes	53.7			24.1
Revenue
Utility natural gas sales and distribution¹	$	73.3		$	24.8		$	75.5		$	24.6
Wastewater treatment	5.8			5.6			6.0			5.6
Water distribution	11.9			3.5			12.2			3.5
Gas transportation	3.3			1.2			3.4			1.2
	$	94.3		$	35.1		97.1			$	34.9
Less:
Cost of Sales – Natural Gas¹	(44.7		)	(13.8		)	(46.0		)	(13.6		)
Net utility sales	$	49.6		$	21.3		$	51.1		$	21.3
Expenses
Operating expenses	(26.6		)	(13.1		)	(27.4		)	(13.1		)
Interest and other income	0.4			—			$	0.4		$	—
Divisional operating profit	$	23.4		$	8.2		$	24.1		$	8.2



1	Represents Natural Gas revenue and gas costs since August 1, 2012 acquisition date.

2013 Annual Operating Results

The Liberty Utilities (Central) region has investments in natural gas distribution assets for regulatory purposes of U.S. $148.1 million and water distribution assets for regulatory purposes of U.S. $53.7 million as at December 31, 2013, as compared to U.S $131.4 million and U.S. $24.1 million, respectively as at December 31, 2013. The increase in natural gas distribution assets for regulatory purposes is primarily related to pipe expansion and replacement activities and system implementations, while the increase in water assets for regulatory purposes is primarily a result of the Pine Bluff Water System acquisition.

For the twelve months ended December 31, 2013, the Liberty Utilities (Central) region’s revenue totalled U.S. $94.3 million as compared to U.S. $35.1 million during the same period in 2012, an increase of U.S. $59.2 million. The increase in revenue is primarily attributed to the addition of the natural gas distribution assets acquired on August 1, 2012 and the Pine Bluff Water System acquired on February 1, 2013.

For the twelve months ended December 31, 2013, the Liberty Utilities (Central) region’s revenue from natural gas sales and distribution totalled U.S. $73.3 million as compared to U.S. $24.8 million during the same period in 2012, an increase of U.S. $48.5 million.

For the twelve months ended December 31, 2013, the Liberty Utilities (Central) region’s revenue from gas transportation sales totalled U.S. $3.3 million as compared to U.S. $1.2 million during the same period in 2012, an increase of U.S. $2.1 million . The increase in transportation revenue is primarily attributed to the addition of the natural gas distribution assets acquired on August 1, 2012.

For the twelve months ended December 31, 2013, revenue from wastewater treatment and water distribution totalled U.S. $5.8 million and U.S. $11.9 million, respectively, as compared to U.S. $5.6 million and U.S. $3.5 million, respectively, during the same period in 2012. The increase in water distribution revenue is primarily attributed to the addition of the Pine Bluff Water System.

For the twelve months ended December 31, 2013, natural gas purchases for the Liberty Utilities (Central) region’s natural gas utility totalled U.S $44.7 million , as compared with U.S. $13.8 million for the same period in 2012. The overall natural gas purchase costs experienced an increase of U.S. $30.9 million.



2013 Annual Report	28
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

ended December 31, 2013, net utility sales from natural gas sales and distribution for the Liberty Utilities (Central) region totalled U.S. $49.6 million as compared to U.S. $21.3 million during the same period in 2012, an increase of U.S. $28.3 million. The increase in net utility sales is primarily due to the division reporting a full year of results in 2013 compared to partial year results in the previous year.

For the twelve months ended December 31, 2013, operating expenses, excluding natural gas purchases, totalled U.S. $26.6 million, as compared to U.S. $13.1 million during the same period in 2012. The increase in operating expenses can be primarily attributed to the addition of the natural gas distribution assets on August 1, 2012 and the Pine Bluff Water System acquired on February 1, 2013.

For the twelve months ended December 31, 2013, the Liberty Utilities (Central) region’s operating profit was U.S. $23.4 million as compared to U.S. $8.2 million in the same period in 2012, an increase of U.S. $15.2 million primarily attributed to the aforementioned acquisitions.

Measured in Canadian dollars, the Liberty Utilities (Central) region’s operating profit was $24.1 million as compared to $8.2 million in the same period in 2012.



	Three months ended December 31,
	2013	2012
Average Active Natural Gas Connections For The Period
Residential	70,300	72,000
Commercial and Industrial	9,100	9,600
Total Average Active Natural Gas Connections For The Period	79,400	81,600

Average Active Water Connections For The Period
Wastewater connections	6,000	5,800
Water distribution connections	21,800	5,300
Total Average Active Water Connections For The Period	27,800	11,100

Customer Usage (MMBTU)
Residential	1,308,000	1,160,000
Commercial and Industrial	1,147,000	841,000
Total Customer Usage (MMBTU)	2,455,000	2,001,000

Gallons Provided
Wastewater treated (millions of gallons)	88.5	94.6
Water sold (millions of gallons)	803.6	97.3
Total Gallons Provided	892.1	191.9

The Liberty Utilities (Central) region acquired the Pine Bluff Water System water distribution utility on February 1, 2013, and accordingly, there are no results for this utility for the corresponding period in 2012.

For the three months ended December 31, 2013, the Liberty Utilities (Central) region natural gas distribution sales totalled 2,455,000 MMBTU as compared to 2,001,000 during the same period in 2012, an increase of 454,000 MMBTU or 22.7%.

During the three months ended December 31, 2013, the Liberty Utilities (Central) region provided approximately 803.6 million gallons of water to its customers, and treated approximately 88.5 million gallons of wastewater, as compared to 97.3 million gallons of water and 94.6 million gallons of wastewater during the same period in 2012.

As a result of the acquisition of the Pine Bluff Water System on February 1, 2013 the number of water connections in the region increased by 17,700. During the three months ended December 31, 2013, the amount of water sold also correspondingly increased by 698 million gallons.



2013 Annual Report	29
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis



	Three months ended December 31,						Three months ended December 31,
	2013 U.S. $ (millions)			2012 U.S. $ (millions)			2013 Can $ (millions)			2012 Can $ (millions)
Revenue
Utility natural gas sales and distribution	$	22.5		$	19.7		$	23.8		$	19.6
Wastewater treatment	1.5			1.4			1.5			1.6
Water distribution	3.1			0.6			3.2			0.5
Gas Transportation	0.9			0.8			0.9			0.8
	28.0			22.5			29.4			22.5
Less:
Cost of Sales – Natural Gas	(14.2		)	(12.0		)	(15.2		)	(11.9		)
Net utility sales	13.8			10.5			14.2			10.6
Expenses
Operating expenses	(7.2		)	(6.3		)	(7.6		)	(6.3		)
Other income	0.2			—			0.2			—
Division operating profit	$	6.8		$	4.2		$	6.8		$	4.3

2013 Fourth Quarter Operating Results

For the three months ended December 31, 2013, the Liberty Utilities (Central) region’s revenue totalled U.S. $28.0 million as compared to U.S. $22.5 million during the same period in 2012, an increase of U.S. $5.5 million. The increase in revenue can be primarily attributed to the addition of the Pine Bluff Water System on February 1, 2013 and the increased natural gas sales and distribution discussed below.

For the three months ended December 31, 2013, the Liberty Utilities (Central) region’s revenue from natural gas sales and distribution totalled U.S. $22.5 million as compared to U.S. $19.7 million during the same period in 2012, an increase of U.S. $2.8 million or 14.2%.

For the three months ended December 31, 2013, the Liberty Utilities (Central) region’s revenue from gas transportation sales totalled U.S. $0.9 million as compared to U.S. $0.8 million during the same period in 2012, an increase of U.S. $0.1 million.

For the three months ended December 31, 2013, revenue from wastewater treatment and water distribution totalled U.S. $1.5 million and $3.1 million , as compared to U.S. $1.4 million and $0.6 million during the same period in 2012. The increase in total wastewater treatment and water distribution revenue can be primarily attributed to the addition of the Pine Bluff Water System.

For the three months ended December 31, 2013 natural gas purchases for the Liberty Utilities (Central) region’s natural gas utility totalled U.S $14.2 million, as compared with U.S. $12.0 million for the same period in 2012, an increase of $2.2 million.

The purchase of natural gas by the Liberty Utilities (Central) region is a significant revenue driver and component of operating expenses but these costs are effectively passed through to its customers. As a result, the division compares ‘net utility sales’ (utility sales after commodity costs) as a more appropriate measure of the division’s results. For the three months ended December 31, 2013, net utility sales from natural gas sales and distribution for the Liberty Utilities (Central) region totalled U.S. $13.8 million as compared to U.S. $10.5 million during the same period in 2012, an increase of U.S. $3.3 million, or 31.4%.

For the three months ended December 31, 2013, operating expenses, excluding natural gas purchases, totalled U.S. $7.2 million, as compared to U.S. $6.3 million during the same period in 2012. The increase in operating expenses is primarily attributed to the acquisition of the Pine Bluff Water System on February 1, 2013.

For the three months ended December 31, 2013, the Liberty Utilities (Central) region’s operating profit was U.S. $6.8 million as compared to U.S. $4.2 million in the same period in 2012, an increase of U.S. $2.6 million.

Measured in Canadian dollars, the Liberty Utilities (Central) region’s operating profit was $6.8 million as compared to $4.3 million in the same period in 2012.



2013 Annual Report	30
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Liberty Utilities East Region:



	Year ended December 31,
	2013	2012
Average Active Natural Gas Connections
Residential	178,800	74,000
Commercial and Industrial	17,200	8,800
Total Average Active Natural Gas Connections	196,000	82,800

Average Active Electric Connections
Residential	36,800	36,200
Commercial and Industrial	6,500	6,500
Total Average Active Electric Connections	43,300	42,700

Customer Usage (GW-hrs)
Residential	304.6	151.5
Commercial and Industrial	628.4	323.1
Total Customer Usage (GW-hrs)³	933.0	474.6

Customer Usage (MMBTU)
Residential	7,214,000	1,552,000
Commercial and Industrial	5,666,000	988,000
Total Customer Usage (MMBTU) ^1,2,3	12,880,000	2,540,000



1	New England Gas System was acquired on December 20, 2013
2	Peach State Gas System was acquired on April 1, 2013.
3	Granite State Electric System and EnergyNorth Gas System were acquired on July 3, 2012.

The Liberty Utilities (East) region is comprised of Liberty Utilities’ operations in New Hampshire, Massachusetts and Georgia. The Liberty Utilities (East) region acquired its natural gas distribution system in Massachusetts on December 20, 2013, its natural gas distribution system in Georgia on April 1, 2013, and the New Hampshire natural gas and electric distribution systems on July 3, 2012; accordingly the twelve month results for 2012 are not comparative.

For the twelve months ended December 31, 2013, the Liberty Utilities (East) region’s electricity usage totalled 933.0 GW-hrs and natural gas usage totalled 12,880,000 MMBTU. The Peach State Gas System usage totalled 3,369,000 MMBTU, while the New England Gas System usage totalled 242,000 MMBTU.

As a result of the acquisition of the New England Gas System and the Peach State Gas Systems, the Liberty Utilities (East) region added approximately 115,000 total natural gas connections.



2013 Annual Report	31
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis



	Year ended December 31,						Year ended December 31,
	2013 U.S. $ (millions)			2012 U.S. $ (millions)			2013 Can $ (millions)			2012 Can $ (millions)
Electricity Assets for regulatory purposes	101.1			88.4
Natural Gas for regulatory purposes	513.4			263.4
Revenue
Utility electricity sales and distribution¹	$	85.7		$	36.8		$	88.3		$	36.7
Utility natural gas sales and distribution^2,3,4	164.1			45.7			169.1			45.3
Gas Transportation	13.4			4.6			13.7			4.6
Other Revenue	—			0.1			—			0.1
	$	263.2		$	87.2		$	271.1		$	86.7
Less:
Cost of Sales – Electricity¹	(55.9		)	(24.4		)	(57.6		)	(24.3		)
Cost of Sales – Natural Gas^2,3,4,5	(99.8		)	(24.0		)	(102.8		)	(23.8		)
Net Utility Sales	$	107.5		$	38.8		$	110.7		$	38.6
Expenses
Operating expenses	(65.3		)	(30.4		)	(67.3		)	(30.2		)
Other Income	1.4			0.4			1.5			0.5
Division operating profit	$	43.6		$	8.8		$	44.9		$	8.9



1	Represents Granite State Electric System revenue and electricity costs since July 3, 2012 acquisition date.
2	Represents New England Gas System revenue and gas costs since December 20, 2013 acquisition date.
3	Represents Peach State Gas System revenue and gas costs since April 1, 2013 acquisition date.
4	Represents EnergyNorth Gas System revenue and costs since July 3, 2012 acquisition date.
5	Natural Gas costs are shown net of U.S. $11.7 million regulatory authorized deferral related to an under recovery of actual gas costs.

2013 Annual Operating Results

The Liberty Utilities (East) region has investments in electricity assets for regulatory purposes of U.S. $101.1 million, and natural gas assets for regulatory purposes of U.S. $513.4 million as at December 31, 2013, as compared to U.S $88.4 million and U.S. $263.4 million, respectively, as at December 31, 2012. The increase in electricity assets is primarily a result of the construction of a new substation, substation asset upgrades, and the construction of a new supply line by the Granite State Electric System, while the increase in gas assets for regulatory purposes from December 31, 2013 is primarily a result of maintenance and installation of new pipelines at the EnergyNorth Gas System, and the acquisitions of the Peach State and the New England Gas Systems.

For the twelve months ended December 31, 2013, the Liberty Utilities (East) region’s revenue totalled U.S. $263.2 million as compared to U.S. $87.2 million during the same period in 2012.

For the twelve months ended December 31, 2013, the Liberty Utilities (East) region’s revenue from utility electricity sales totalled U.S. $85.7 million.

For the twelve months ended December 31, 2013, the Liberty Utilities (East) region’s revenue from natural gas sales and distribution totalled U.S. $164.1 million, of which the EnergyNorth Gas System contributed U.S $126.0 million, the Peach State Gas System contributed U.S. $35.1 million, and the newly acquired New England Gas System contributed $3.0 million.

For the twelve months ended December 31, 2013, the Liberty Utilities (East) region’s revenue from gas transportation sales totalled U.S. $13.4 million. For the twelve months ended December 31, 2013, the EnergyNorth Gas System contributed U.S. $11.6 million, the Peach State Gas System contributed U.S.$1.3 million, and the newly acquired New England Gas System contributed U.S. $0.5 million.



2013 Annual Report	32
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

For the twelve months ended December 31, 2013, electricity purchases for the Liberty Utilities (East) region totalled U.S. $55.9 million, and natural gas purchases totalled U.S. $99.8 million.

The cost of electricity and natural gas is passed through to the Liberty Utilities (East) region’s customers in the rates they are charged. As a result, the division compares ‘net utility sales’ (see non-GAAP Financial Measures) as a more appropriate measure of the division’s results. For the twelve months ended December 31, 2013, net utility sales totalled U.S. $107.5 million compared to U.S. $38.8 million during the same period in 2012, an increase of $68.7 million. The increase is due to the fact that the division is reporting a full year of results in 2013 compared to partial year results in the previous year and the impact of the interim annual rate increase approved by the NHPUC on June 27, 2013.

For the twelve months ended December 31, 2013, operating expenses, excluding electricity and natural gas purchases, totalled U.S. $65.3 million. For the twelve months ended December 31, 2013, other income for the Liberty Utilities (East) region totaled U.S. $1.4 million, and primarily consists of an equity allowance for funds utilized during construction and rental income. For the twelve months ended December 31, 2013, the Liberty Utilities (East) region’s operating profit totalled U.S. $43.6 million.

Measured in Canadian dollars, the Liberty Utilities (East) region’s operating profit was $44.9 million.



	Three months ended December 31,
	2013	2012
Average Active Natural Gas Connections For The Period
Residential	178,900	73,300
Commercial and Industrial	17,100	8,700
Total Customer Usage (GW-hrs)	196,000	82,000

Average Active Electric Connections For The Period
Residential	36,600	36,600
Commercial and Industrial	6,500	6,500
Total Average Active Electric Connections For The Period	43,100	43,100

Customer Usage (GW-hrs)
Residential	69.4	68.5
Commercial and Industrial	145.3	143.6
Total Customer Usage (GW-hrs)	214.7	212.1

Customer Usage (MMBTU)
Residential	2,068,000	1,199,000
Commercial and Industrial	2,147,000	745,000
Total Customer Usage (MMBTU)	4,215,000	1,944,000

For the three months ended December 31, 2013, the Liberty Utilities (East) region’s electricity usage totalled 214.7 GW-hrs and natural gas usage totalled 4,215,000 MMBTU as compared to 212.1 GW-hrs and 1,944,000 MMBTU during the same period in 2012. The Peach State Gas System usage totalled 1,394,000 MMBTU, while the New England Gas System usage totalled 242,000 MMBTU.



2013 Annual Report	33
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis



	Three months ended December 31,						Three months ended December 31,
	2013 U.S. $ (millions)			2012 U.S. $ (millions)			2013 Can $ (millions)			2012 Can $ (millions)
Revenue
Utility electricity sales and distribution	$	22.2		$	17.7		$	23.3		$	17.6
Utility natural gas sales and distribution^1,2	62.4			35.3			65.7			34.9
Gas Transportation	3.5			2.8			3.7			2.8
Other Revenue	—			—			—			—
	$	88.1		$	55.8		$	92.7		$	55.3
Less:
Cost of Sales – Electricity	(14.7		)	(12.3		)	(15.5		)	(12.2		)
Cost of Sales – Natural Gas^1,2,3	(39.8		)	(21.9		)	(41.9		)	(21.7		)
Net Utility Sales	$	33.6		$	21.6		$	35.3		$	21.4
Expenses
Operating expenses	(18.2		)	(16.5		)	(19.1		)	(16.3		)
Other income	0.3			0.4			0.4			0.4
Division operating profit	$	15.7		$	5.5		$	16.6		$	5.5



1	Represents New England Gas System revenue and gas costs since December 20, 2013 acquisition date.
2	Represents Peach State Gas System revenue and gas costs since April 1, 2013 acquisition date.
3	Natural Gas costs are shown net of U.S. $2.5 million regulatory authorized deferral related to an under recovery of actual gas costs.

2013 Fourth Quarter Operating Results

For the three months ended December 31, 2013, the Liberty Utilities (East) region’s revenue totalled U.S. $88.1 million, as compared to U.S. $55.8 million during the same period in 2012, an increase of U.S. $32.3 million, or 57.9%. The increase in revenue can be primarily attributed to the acquisition of the Peach State Gas System on April 1, 2013 and the New England Gas System on December 20, 2013.

For the three months ended December 31, 2013, the Liberty Utilities (East) region’s revenue from utility electricity sales totalled U.S. $22.2 million as compared to U.S. $17.7 million during the same period in 2012, an increase of $4.5 million, or 25.4%, primarily due to interim rates in place at the Granite State Electric System effective July 1, 2013.

For the three months ended December 31, 2013, the Liberty Utilities (East) region’s revenue from natural gas sales and distribution totalled U.S. $62.4 million as compared to U.S. $35.3 million during the same period in 2012, an increase of U.S. $27.1 million, or 76.8%. During the three months ended December 31, 2013, the EnergyNorth Gas System contributed U.S. $43.4 million, while the Peach State Gas System contributed U.S.$16.0 million, and the newly acquired the New England Gas System contributed U.S. $3.0 million.

For the three months ended December 31, 2013, the Liberty Utilities (East) region’s revenue from gas transportation sales totalled U.S. $3.5 million as compared to U.S. $2.8 million during the same period in 2012, an increase of U.S. $0.7 million, or 25.0%. During the three months ended December 31, 2013 the EnergyNorth Gas System contributed U.S.$2.6 million, the Peach State Gas System contributed U.S. $0.4 million, and the newly acquired New England Gas System contributed U.S. $0.5 million.

For the three months ended December 31, 2013, electricity purchases for the Liberty Utilities (East) region totalled U.S. $14.7 million, and natural gas purchases totalled U.S. $39.8 million as compared to U.S. $12.3 million and U.S. $21.9 million, respectively, during the same period in 2012. The overall electricity purchase expense increase of U.S $2.4 million was primarily the result of an 18% increase in weighted average electricity rates as compared to the same period in 2013 and a 1% increase in the volume of electricity purchased to meet customer demand. The overall natural gas purchases increases



2013 Annual Report	34
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

can be primarily attributed to the acquisition of the Peach State Gas System on April 1, 2013 and the New England Gas System on December 20, 2013.

The cost of electricity and natural gas is passed through to the Liberty Utilities (East) region’s customers. As a result, the division compares ‘net utility sales’ (see non-GAAP Financial Measures) as a more appropriate measure of the division’s results. For the three months ended December 31, 2013, net utility sales for the Liberty Utilities (East) region totalled U.S. $33.6 million as compared to U.S. $21.6 million during the same period in 2012, an increase of U.S.$12.0 million, or 55.6%, primarily due to an interim annual rate increase approved by the NHPUC on June 27, 2013 and higher customer counts, due to the acquisition of the Peach State Gas System on April 1, 2013 and the New England Gas System on December 20, 2013.

For the three months ended December 31, 2013, operating expenses, excluding electricity and natural gas purchases, totalled U.S. $18.2 million as compared to U.S. $16.5 million during the same period in 2012, an increase of U.S. $1.7 million, or 10.3%. The increase in operating expenses as compared to the same period in 2012 can be primarily attributed to the acquisition of the Peach State Gas System on April 1, 2013 and the New England Gas System on December 20, 2013.

For the three months ended December 31, 2013, other income for the Liberty Utilities (East) region totaled U.S. $0.3 million, and primarily consists of an equity allowance for funds utilized during construction and rental income.

For the three months ended December 31, 2013, the Liberty Utilities (East) region’s operating profit totalled U.S. $15.7 million as compared to U.S. $5.5 million during the same period in 2012, an increase of U.S. $10.2 million. The increase in operating profit as compared to the same period in 2012 can be primarily attributed to the acquisition of the Peach State Gas System on April 1, 2013, and the New England Gas System on December 20, 2013.

Measured in Canadian dollars, the Liberty Utilities (East) region’s operating profit was $16.6 million as compared to $5.5 million during the same period in 2012, an increase of $11.1 million.

Regulatory Proceedings

The following table summarizes the major regulatory proceedings within Liberty utilities currently underway:



Utility	State	Regulatory Proceeding Type	Rate Request (U.S. $000’s)	Current Status
Rio Rico Water System	Arizona	General Rate Case	$750	Order issued authorizing $420 annual increase
LPSCo Water System	Arizona	General Rate Case	$3,000	Order expected first half of 2014
Peach State Gas System	Georgia	Georgia Rate Adjustment Mechanism ("GRAM") filing	$4,900	Settlement reached. Final Commission approval expected by the end of Q1 2014.
EnergyNorth Gas System	New Hampshire	Rate Proceeding	Cast iron/bare steel replacement program increase of $200	Order approving $200 increase for one year
Granite State Electric System	New Hampshire	General Rate Case	$13,000 + $1,200 step adjustment in 2014	Settlement reached for $10,200 + $1,100 in step increase for 2014. Commission approval expected by the end of Q1 2014
Missouri Gas System	Missouri	General Rate Case	$6,300	Order expected first quarter of 2015

On May 31, 2012, the Liberty Utilities (West) region filed a general rate case with the Arizona Corporation Commission (“ACC”) related to the Rio Rico Water System. The filing sought, among other things, an increase in EBITDA by U.S. $0.8 million over 2011 results if approved as filed. On July 17, 2013, an order was received from the ACC which corresponds to an increase in EBITDA of approximately U.S. $0.4 million per year.

On February 28, 2013, LPSCo Water System filed a general rate case with the Arizona Corporation Commission related to the LPSCo Water System seeking, among other things, an increase in EBITDA by U.S. $3.0 million over the 2012 results if approved as filed. The application seeks recognition of increased capital investment and increased operating expenses over current rates. In addition to a revenue increase, the application seeks 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



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Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

shift of moving more revenue recovery to fixed charges versus commodity charges. New rates are expected to be implemented in the first half of 2014.

On October 30, 2013, the Peach State Gas System filed an application to increase rates by U.S. $4.9 million in its annual Georgia Revenue Adjustment Mechanism (“GRAM”) filing with the Georgia Public Service Commission (“GPSC”). In January 2014, Liberty Utilities and the Staff of the GPSC agreed to a settlement which will provide an annual revenue increase of U.S. $4.7 million. It is anticipated that this settlement will be approved in March 2014.

On May 15, 2013, the Liberty Utilities (East) region filed its required fiscal year 2013 (April 1, 2012 - March 31, 2013) cast iron/bare steel (CIBS) replacement program results for EnergyNorth Gas System with the NHPUC. As part of this filing, Liberty requested an annual increase in base distribution rates of U.S. $0.2 million effective July 1, 2013. On June 26, 2013, the NHPUC approved the increase.

On March 29, 2013, the Granite State Electric System filed a rate case with the 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. The filing is based on a 2012 test year, with revenues and expenses adjusted to reflect known and measurable changes. Among other things, the Granite State Electric System requested and received approval to continue the current cost-recovery tracking mechanism related to the Reliability Enhancement and Vegetation Management Plan and was granted an annual rate increase of U.S. $0.4 million starting July 1, 2013. The Granite State Electric System also requested a modification to allow for recovery of pre-staging personnel and equipment for qualifying storms. On June 27, 2013, the NHPUC approved a settlement agreement authorizing a temporary annual rate increase of U.S.$6.5 million effective July 1, 2013, and provides recognition for Liberty to request an increase to its storm recovery adjustment factor (“SRAF”). On January 22, 2014, the Granite State Electric System entered a settlement with the New Hampshire PUC Staff, which will provide for a rate increase of U.S.$10.9 million consisting of U.S. $9.8 million in base rates and an additional U.S. $1.1 million for incremental capital expended after the test year. In addition, the settlement allows for one time recovery of rate case expenses of U.S. $0.4 million. It is anticipated that the settlement will be approved in the first quarter of 2014.

On July 2, 2013, the Missouri Gas System filed an application with the Missouri Public Service Commission (“MPSC”) seeking accelerated recovery for infrastructure deployed under the utility’s infrastructure system replacement surcharge (“ISRS”). The filing was approved by MPSC on October 16th, 2013 which is expected to increase revenues and EBITDA by U.S. $0.6 million.

In the first quarter of 2014, the Midstates Gas System filed a rate case with the Missouri Public Service Commission ("MOPSC") seeking an increase in EBITDA of U.S. $6.3 million. 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 is expected to conclude in first quarter of 2015.

APUC: Corporate and Other Expenses



	Three months ended December 31,						Year ended December 31,
	2013 (millions)			2012 (millions)			2013 (millions)			2012 (millions)
Corporate and other expenses:
Administrative expenses	$	5.2		$	5.3		$	23.5		$	19.6
(Gain)/Loss on foreign exchange	(0.1		)	(1.6		)	(0.6		)	(0.6		)
Interest expense	14.4			11.1			53.3			35.6
Interest, dividend and other Income	0.7			0.4			2.5			2.1
Write down of long lived assets	—			—			—			—
Acquisition-related costs	0.6			1.3			2.1			7.7
(Gain)/Loss on derivative financial instruments	(2.7		)	(0.4		)	(5.2		)	(0.2		)
Income tax expense/(recovery)	5.2			(6.5		)	9.2			(14.4		)

2013 Annual Corporate and Other Expenses

During the year ended December 31, 2013, administrative expenses totalled $23.5 million, as compared to $19.6 million in the same period in 2012. The expense increase in the year ended December 31, 2013 primarily results from additional personnel, increased wages, additional costs required to administer APUC’s operations, share based compensation expense and other costs as compared to the same period in 2012.



2013 Annual Report	36
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

For the year ended December 31, 2013, interest expense totalled $53.3 million as compared to $35.6 million in the same period in 2012. The increased interest expense is a result of new indebtedness incurred during the second half of 2012 and the first quarter of 2013 used to partially finance the new acquisitions and fund other growth initiatives. These amounts were partially offset by $4.9 million in reduced interest expense related to the Series 3 convertible debentures and $1.7 million in 2012 related to the Quebec water lease litigation.

For the year ended December 31, 2013, interest, dividend and other income totalled $2.5 million as compared to $2.1 million in the same period in 2012. Interest, dividend and other income primarily consists of dividends from APUC’s share investment in the Kirkland and Cochrane facilities.

For the year ended December 31, 2013, acquisition related costs totalled $2.1 million as compared to $7.7 million in the same period in 2012. 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, 2013, gains on derivative financial instruments totalled $5.2 million as compared to $0.2 million in the same period in 2012. The increase was primarily driven by derivative gains on the AES market hedges due to increased market prices during 2013 as compared to the same period in 2012.

An income tax expense of $9.2 million was recorded in the year ended December 31, 2013, as compared to a recovery of $14.4 million during the same period in 2012. The increase income tax expense for the year ended December 31, 2013 is primarily due to higher earnings in the U.S. resulting from the various U.S. acquisitions completed in 2012, deferred taxes on HLBV income, the recognition of deferred credits from the utilization of deferred income tax assets recognized at the time of the Unit Exchange Offer, non-taxable inter-corporate dividends, and other items permanently non-deductible for tax purposes.

2013 Fourth Quarter Corporate and Other Expenses

During the quarter ended December 31, 2013, administrative expenses totalled $5.2 million, as compared to $5.3 million in the same period in 2012.

For the quarter ended December 31, 2013, interest expense totalled $14.4 million as compared to $11.1 million in the same period in 2012. The increased interest expense is a result of new indebtedness incurred during the first half of 2013 used to partially finance the new acquisitions and fund other growth initiatives. These amounts were partially offset by reduced interest expense related to convertible debentures due to the conversion of the Series 3 Debentures in the prior year.

For the quarter ended December 31, 2013, interest, dividend and other income totalled $0.7 million, as compared to $0.4 million in the same period in 2012. Interest, dividend and other income primarily consists of dividends from APUC’s share investment in the Kirkland and Cochrane facilities.

For the quarter ended December 31, 2013, gains on derivative financial instruments totalled $2.7 million, as compared to $0.4 million in the same period in 2012. The increase was primarily driven by derivative gains on the AES market hedges due to increased market prices during 2013 as compared to the same period in 2012.

An income tax expense of $5.2 million was recorded in the three months ended December 31, 2013, as compared to a recovery of $6.5 million during the same period in 2012. The income tax expense for the three months ended December 31, 2013 primarily due to deferred taxes on HLBV income, the recognition of deferred credits from the utilization of deferred income tax assets recognized at the time of the Unit Exchange Offer, non-taxable inter-corporate dividends, and other items permanently non-deductible for tax purposes.



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Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

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,
	2013 (millions)			2012 (millions)			2013 (millions)			2012 (millions)
Net earnings attributable to Shareholders	$	13.1		$	6.4		$	20.3		$	14.5
Add (deduct):
Net earnings / (loss) attributable to the non-controlling interest, exclusive of HLBV	3.4			(3.2		)	9.6			(3.3		)
(Earnings) / loss from discontinued operations	6.7			0.4			42.0			(1.0		)
Income tax expense / (recovery)	5.2			(6.5		)	9.2			(14.4		)
Interest expense	14.4			11.1			53.3			35.6
Acquisition costs	0.6			1.3			2.1			7.7
Quebec water lease litigation	—			—			—			0.5
(Gain)/Loss on derivative financial instruments	(2.7		)	(0.4		)	(5.2		)	(0.2		)
(Gain)/Loss on foreign exchange	(0.1		)	(1.6		)	(0.6		)	(0.6		)
Depreciation and amortization	27.0			16.5			96.2			49.3
Adjusted EBITDA	$	67.6		$	24.0		$	226.9		$	88.1

Hypothetical Liquidation at Book Value (“HLBV”) represents the value of net tax attributes earned by APCo 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, 2013 amounted to approximately $6.8 million and $20.4 million, respectively.

For the year ended December 31, 2013, Adjusted EBITDA totalled $226.9 million as compared to $88.1 million during the same period in 2012, an increase of $138.8 million. For the quarter ended December 31, 2013, Adjusted EBITDA totalled $67.6 million as compared to $24.0 million, an increase of $43.6 million compared to the same period in 2012.

The major factors impacting Adjusted EBITDA are set out below. A more detailed analysis of these factors is presented within the business unit analysis.



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Algonquin Power & Utilities Corp. - Management's Discussion & Analysis



	Three months ended December 31 (millions)			Year ended December 31 (millions)
Comparative Prior Period Adjusted EBITDA	$	24.0		$	88.1
Significant Changes:
Liberty Utilities:
Increased demand and rate decoupling at the CalPeco Electric System	0.8			9.3
Acquisitions	12.8			48.5
APCo:
Renewable
Increased hydrology resource	0.8			6.6
Acquisitions of the U.S. Wind Facilities	23.6			62.9
Sale of Renewable Energy Credits	2.2			5.7
Increased wind resources at the St Leon wind facilities	1.0			1.3
Increased demand for retail sales at AES	—			2.6
Thermal
Windsor Locks & Sanger Facilities - Increased energy sales	0.3			2.5
Administrative expense	0.2			(3.9		)
Increased/(decreased) results from the stronger U.S. dollar	4.3			5.0
Other	(2.4		)	(1.7		)
Current Period Adjusted EBITDA	$	67.6		$	226.9

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,
	2013 (millions)			2012 (millions)			2013 (millions)			2012 (millions)
Net earnings attributable to Shareholders	$	13.1		$	6.4		$	20.3		$	14.5
Add (deduct):
(Gain) / Loss from discontinued operations, net of tax	6.7			0.4			42.0			(1.0		)
(Gain)/Loss on derivative financial instruments, net of tax	(1.6		)	(0.2		)	(2.7		)	(0.2		)
Cross Currency Interest Rate Swap interest differential	—			—			0.3			—
Quebec water lease litigation and interest, net of tax	—			—			—			1.2
(Gain)/Loss on foreign exchange, net of tax	(0.1		)	(0.9		)	(0.3		)	(0.3		)
Acquisition costs, net of tax	0.4			0.8			1.3			4.7
Adjusted net earnings	$	18.5		$	6.5		$	60.9		$	18.9
Adjusted net earnings per share	$	0.08		$	0.03		$	0.27		$	0.11

For the year ended December 31, 2013, adjusted net earnings totalled $60.9 million as compared to adjusted net earnings of $18.9 million, an increase of $42.0 million as compared to the same period in 2012. The increase in adjusted net earnings



2013 Annual Report	39
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

for the year ended December 31, 2013 is primarily due to higher income from operations, decreased acquisition costs partially offset by higher interest expense, and depreciation and amortization expense as compared to the same period in 2012.

For the three months ended December 31, 2013, adjusted net earnings totalled $18.5 million as compared to adjusted net earnings of $6.5 million, an increase of $12.0 million as compared to the same period in 2012. The increase in adjusted net earnings for the three months ended December 31, 2013 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 2012.

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,
	2013 (millions)		2012 (millions)			2013 (millions)		2012 (millions)
Cash flows from operating activities	$	31.3	$	17.1		$	98.9	$	63.0
Add (deduct):
Changes in non-cash operating items	13.5		7.2			47.8		3.9
Cash (provided)/used in discontinued operation	0.5		(1.0		)	4.4		(7.8		)
Cross Currency Swap interest difference	—		—			0.3		—
Acquisition costs	0.6		1.3			2.1		7.7
Adjusted funds from operations	$	45.9	$	24.6		$	153.5	$	66.8
Adjusted funds from operations per share	0.22		0.14			0.72		0.42

For the year ended December 31, 2013, adjusted funds from operations totalled $153.5 million as compared to adjusted funds from operations of $66.8 million, an increase of $86.7 million as compared to the same period in 2012.

For the three months ended December 31, 2013, adjusted funds from operations totalled $45.9 million as compared to adjusted funds from operations of $24.6 million, an increase of $21.3 million as compared to the same period in 2012.



2013 Annual Report	40
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Summary of Property, Plant and Equipment Expenditures



	Three months ended December 31,					Year ended December 31,
	2013 (millions)		2012 (millions)			2013 (millions)		2012 (millions)
APCo:
Renewable	$	18.0	$	7.5		$	46.9	$	21.1
Thermal	1.3		(2.0		)	2.6		10.3
Total APCo	$	19.3	$	5.5		$	49.5	$	31.4

LIBERTY UTILITIES
West	13.4		9.6			23.7		23.2
Central	8.4		8.8			28.6		10.8
East	21.6		8.9			56.6		12.5
Total Liberty Utilities	$	43.4	$	27.3		$	108.9	$	46.5

Corporate	—		0.1			—		—
Total	$	62.7	$	32.9		$	158.4	$	77.9

The company's consolidated capital expenditure plan for 2014 is approximately $460.0 million. APCo expects to invest approximately $260.0 million primarily in connection with the development of its existing project pipeline. Liberty Utilities expects to invest approximately $200.0 million primarily to improve the reliability and efficiency of its gas, and electric utility distribution systems.

APUC anticipates that it can generate sufficient liquidity through internally generated operating cash flows, bank credit facilities as well as the debt and equity capital markets to finance its property, plant and equipment expenditures and other commitments.

2013 Annual Property Plant and Equipment Expenditures

During the twelve months ended December 31, 2013, APCo incurred capital expenditures of $49.5 million, as compared to $31.4 million during the comparable period in 2012,

During the twelve months ended December 31, 2013, APCo’s Renewable Energy Division spent $46.9 million in capital expenditures as compared to $21.1 million in the comparable period in 2012. The capital expenditures primarily relate to project costs for the Cornwall Solar, Chaplin and St Damase development projects, as well as major repairs and upgrades at the Long Sault and Tinker Hydro Facilities. APCo’s Thermal Energy Division net capital expenditures were $2.6 million, as compared to $10.3 million in the comparable period in 2012. The capital expenditures in the prior year were primarily related to the Windsor Locks repowering and the major maintenance at the Sanger Thermal Facility offset by two one-time, non-recurring items received by the Windsor Locks Thermal Facility: the $6.5 million grant from the State of Connecticut; and a $2.4 million heat and power ITC sponsored by the U.S. Federal Government.

During the twelve months ended December 31, 2013, Liberty Utilities invested $108.9 million in capital expenditures as compared to $46.5 million during the comparable period in 2012. The Liberty Utilities (West) region’s $23.7 million investment in capital expenditures was primarily related to growth and upgrades at the CalPeco Electric System and the expansion of the LPSCo Water System. The Liberty Utility (Central) region’s $28.6 million investment in capital expenditures was primarily related to pipe expansion and replacement activities, IT system implementations, and the construction of a new building, as a result of the Midstate Gas Systems acquisition. The Liberty Utility (East) region’s $56.6 million investment in capital expenditures reflected the installation of a new substation, the start of a second supply line, the completion of certain substation upgrades and reliability enhancement projects on the Granite State Electric System, the installation of new mains and services supporting growth and distribution main replacements and reinforcements on the EnergyNorth Gas system, and system updates at the Peach State Gas System.

2013 Fourth Quarter Property Plant and Equipment Expenditures



2013 Annual Report	41
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

During the three months ended December 31, 2013, APCo incurred capital expenditures of $19.3 million, as compared to $5.5 million during the comparable period in 2012. During the three months ended December 31, 2013, APCo’s Renewable Energy Division spent $18.0 million in capital expenditures as compared to $7.5 million in the comparable period in 2012. The capital expenditures primarily relate to Cornwall Solar and St. Damase development proejcts, as well as upgrades at the Tinker Hydro Facility. APCo’s Thermal Energy Division net capital expenditures were $1.3 million, as compared to capital recovery of $2.0 million in the comparable period in 2012. The 2013 thermal capital expenditures consist of $1.0 relating to Windsor Locks Thermal Facility and $0.3 million relating to Sanger Thermal Facility whereas the prior capital expenditures were $0.4 million relating to Sanger Thermal Facility offset by a $2.4 million ITC sponsored by the U.S. Federal Government related to the repowering of the Windsor Locks Thermal Facility.

During the three months ended December 31, 2013, Liberty Utilities invested $43.4 million in capital expenditures as compared to $27.3 million during the comparable period in 2012. The Liberty Utilities (West) region’s spend was primarily related to growth and upgrades at the CalPeco Electric System and the expansion of the LPSCo Water System. The Liberty Utility (Central) region’s $8.4 million investment in capital expenditures was primarily related to pipe expansion and replacement activities and IT system implementations, as a result of the Midstates Gas System acquisition. The Liberty Utility (East) region’s $21.6 million investment in capital expenditures was primarily related to a second supply line and reliability enhancement projects on the Granite State Electric System, the installation of new mains and services supporting growth and system reinforcements on the EnergyNorth Gas System, and system updates at the Peach State Gas System.

Quebec Dam Safety Act

As a result of the dam safety legislation passed in Quebec (Bill C93), APCo 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.

APCo currently estimates further capital expenditures of approximately $15.4 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:



	Total	2014	2015	2016	2017
Future Estimated Bill C-93 Capital Expenditures	15.4	1.0	7.3	6.8	0.3

The majority of these capital costs are associated with the Donnacona, St. Alban, Belleterre, and Rivière-du-Loup Hydro Facilities.

APCo completed the majority of the second phase of the on-site remediation work for the Mont Laurier Hydro Facility in 2013 at a capital cost of approximately $0.2 million. The on-site remediation is now substantially complete.

In 2013 APCo completed a risk review of the of the dam rehabilitation plan for the Donnacona Hydro Facility and will explore methods to reduce risk associated with the rehabilitation project in 2014 . The remedial on-site work is anticipated to start in 2015 and be completed in 2016.

The dam safety study and a detailed condition assessment for the St. Alban facility have been completed. A small portion of the on-site remediation associated with the spillway gate superstructure was performed in 2013 at a cost of $0.1 million. APCo anticipates engineering and regulatory review for the remediation of the main dam to be performed in 2014, with remedial work in 2015 to 2016.

APCo is presently reviewing options with respect to the Belleterre Hydro Facility including the removal of several small dams that are not required for power generation. APCo anticipates completion of any required work on these dams by 2017.

Engineering for the Riviere-du-Loup Hydro Facility was completed in 2012. Following a geotechnical investigation, the remediation work is now estimated at $1.1 million. Completion of the remedial work is anticipated in 2014 and 2015.

The dam remediation work related to the Rawdon and Chute Ford Hydro Facilities has been completed.

In addition to the C-93 related dam remediation work, APCo 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 at APUC, APCo and Liberty Utilities to manage the liquidity and working capital requirements of each division (collectively the “Facilities”).



2013 Annual Report	42
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Bank Credit Facilities

The following table sets out the amounts drawn, letters of credit issued and outstanding amounts available to APUC and its subsidiaries as at December 31, 2013 under the Facilities:



	As at December 31, 2013												As at Dec 31 2012
	APUC (millions)			APCo (millions)			Liberty Utilities (millions)			Total (millions)			Total (millions)
Committed Facilities	$	65.0		$	200.0		$	212.7		$	477.7		$	329.5
Funds drawn on Facilities	—			(124.6		)	(85.6		)	(210.2		)	(54.5		)
Letters of Credit issued	(9.9		)	(47.7		)	(7.3		)	(64.9		)	(50.7		)
Funds available for draws on the Facilities	$	55.1		$	27.7		$	119.8		$	202.6		$	224.3
Cash on Hand										13.8			53.1
Total liquidity and capital reserves										$	216.4		$	277.4

As at December 31, 2013, the APUC Credit Facility, a $65.0 million senior unsecured revolving credit facility, was undrawn and had $9.9 million of outstanding letters of credit.

As at December 31, 2013, the APCo $200.0 million senior unsecured revolving credit facility (the “APCo Facility”) had drawn $124.6 million and had $47.7 million in outstanding letters of credit under the APCo Facility.

As at December 31, 2013, the Liberty Utilities $212.7 million (U.S.$200.0 million) senior unsecured revolving credit facility (the "Liberty Facility") had drawn $85.6 million and had $7.3 million of outstanding letters of credit.

On November 19th, 2013, APUC amended its existing $30.0 million senior unsecured credit facility ("APUC Facility") to increase the commitments available to $65.0 million and extend maturity to November 19, 2016. On January 3rd, 2014 a subsidiary of APUC drew on the APUC Facility to acquire a 100% interest in an office building at an approximate cost of $46.8 million. The building will be approximately 50% occupied by APUC and serve as corporate headquarters with the remainder leased to third parties.

Long Term Debt

On January 1, 2013, in conjunction with the acquisition of the Shady Oaks Wind Facility, APCo assumed a U.S. $150.0 million dollar variable rate long term credit facility. The facility is secured by the assets of the Shady Oaks Wind Facility. In 2013 APCo made principal payments of U.S. $25.0 million in the second quarter and U.S. $3.0 million in the third quarter of 2013 and will be required to make semi-annual principal payments ranging between U.S. $3.0 million and U.S. $6.0 million thereafter. The facility matures in 2026. Funds advanced against the facility are repayable at any time without penalty. Accordingly, subsequent to year end, APCo made a U.S.$ 40.0 million prepayment against the principal balance outstanding.

On March 14, 2013 Liberty Utilities completed a U.S. $15.0 million private placement debt financing. The notes are senior unsecured notes with a 10 year bullet maturity and carry a coupon of 4.14%.

On July 31, 2013, Liberty Utilities issued U.S. $125.0 million of debt through a private placement. The notes are senior unsecured with an average life maturity of approximately ten years and a weighted average coupon of 3.81%.

On December 20, 2013, in connection with the acquisition of New England Gas Company, Liberty Utilities assumed first mortgage bonds of U.S. $6.0 million, bearing an interest rate of 7.24%, maturing December 27, 2027; U.S. $7.0 million, bearing an interest rate of 7.99%, maturing December 26, 2026; and, U.S. $6.5 million, bearing an interest rate of 9.44%, maturing Feb 20, 2020.

Subsequent to year end, on January 17, 2104, APCo issued $200.0 million 4.65% senior unsecured debentures with a maturity date of February 15, 2022 (the "APCo Debentures") pursuant to a private placement in Canada and the United States. The APCo Debentures were sold at a price of $99.864 per $100.00 principal amount resulting in an effective yield of 4.67%.



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Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Concurrent with the offering, APCo entered into a fixed for fixed cross currency swap, coterminous with the APCo 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%.

As at December 31, 2013 the weighted average tenor of APUC's total long term debt is approximately 8.4 years with an average interest rate of 4.8%

Contractual Obligations

Information concerning contractual obligations as of December 31, 2013 is shown below:



	Total (millions)		Due less than 1 year (millions)		Due 1 to 3 years (millions)		Due 4 to 5 years (millions)		Due after 5 years (millions)
Long-term debt obligations¹	$	1,255.6	8.3		147.1		171.9		928.3
Advances in aid of construction	$	78.9	1.2						77.7
Interest on long-term debt obligations	$	416.8	54.8		103.6		90.0		168.4
Purchase obligations	$	156.9	156.9
Environmental Obligations	$	77.7	10.1		45.2		3.9		18.5
Derivative financial instruments:
Cross Currency Swap	$	7.9	—		—		—		7.9
Interest rate swap	$	3.1	1.9		1.2		—		—
Energy derivative contracts	$	4.8	0.2		0.1		—		4.5
Capital lease obligations	$	4.0	0.1		3.9		—		—
Capital projects	$	51.6	49.3		2.3		—		—
Long term service agreements	$	633.2	24.1		53.3		57.5		498.3
Purchased power	$	111.5	64.6		46.9		—		—
Gas delivery, service and supply agreements	$	156.1	42.1		40.2		19.3		54.5
Operating leases	$	106.1	5.1		8.5		7.3		85.2
Other obligations	$	21.1	7.3		—		—		13.8
Total obligations	$	3,085.3	$	426.0	$	452.3	$	349.9	$	1,857.1

Equity

The shares of APUC are publicly traded on the Toronto Stock Exchange (“TSX”). As at December 31, 2013, APUC had 206,348,985 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.

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, 2013, APUC had issued 4,800,000 cumulative rate reset preferred shares, Series A (the “Series A Shares”), yielding 4.5% annually for the initial six-year period ending on December 31, 2018, and 100 Series C preferred shares (the "Series C Shares") that were issued in exchange for 100 Class B limited partnership units issued by St. Leon Wind Energy LP.

APUC has a shareholder dividend reinvestment plan (the “Reinvestment Plan”) for registered holders of shares (“Shareholders”) of APUC. As at December 31, 2013, 43.2 million common shares representing approximately 21% of total shares outstanding had been registered with the Reinvestment Plan and 2,126,258 shares had been issued during the year ended December 31, 2013. During the quarter ended December 31, 2013 688,886 common shares were issued under the Reinvestment Plan, and subsequent to the end of the quarter, on January 15, 2014, an additional 501,818 common shares were issued under the Reinvestment Plan.



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Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Subsequent to the end of the year, 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 million. The shares yield 5.0% annually for the initial five-year period ending on 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 proceeds of the offering were used to partially finance certain of APUC's previously disclosed growth opportunities, reduce amounts outstanding on APUC's credit facilities and for general corporate purposes.

On January 1, 2013, the Company issued 100 redeemable Series C Shares and exchanged such shares for the 100 Class B units that provide dividends identical to what is expected from the Class B units, as determined by independent consultants retained by the Independent Board Committee.

On November 19, 2012, APUC announced its intent to redeem, on January 1, 2013, the convertible unsecured debentures maturing on June 30, 2017 (“Series 3 Debentures”) bearing interest at 7.0% per annum. During the year ended December 31, 2012, a principal amount of $61.6 million Series 3 Debentures were converted into 14,669,266 shares of APUC. The Series 3 Debentures were convertible into common shares of APUC at the option of the holder at a conversion price of $4.20 per common share. On December 31, 2012, there was a face value of $0.96 million Series 3 Debentures outstanding. Subsequent to the end of the quarter, on January 1, 2013, APUC redeemed the outstanding Series 3 Debentures and issued 150,816 shares as a result of the redemption. Following the redemption, there were no Series 3 Debentures outstanding.

Emera subscription receipts

For the year ended December 31, 2013, a total of 15.2 million common shares were issued to Emera for proceeds of $90.5 million pursuant to subscription agreements in contemplation of certain previously announced transactions, as outlined below:

•

On February 7, 2013 and February 14, 2013, respectively, in connection with the closing of the acquisition of the Minonk and Senate Wind Facilities from Gamesa USA that occurred on December 10, 2012, APUC issued 2.6 million common shares at a price of $5.74 and 5.2 million shares at a price of $5.74. The total $45 million in cash proceeds from the exercise of the subscription receipts were used to fund a portion of the cost of the acquisition;


•	On February 14, 2013, in connection with the acquisition of Emera’s non-controlling interest in the CalPeco Electric System, APUC issued 3.4 million common shares at a price of $4.72 for share proceeds of $16.1 million; and


•	On March 26, 2013, in connection with the acquisition of the Peach State Gas System, APUC issued 4.0 million shares at a price of $7.40 per share to Emera pursuant to a subscription agreement, for total cash proceeds of $29.3 million. The cash proceeds were used to partially fund the acquisition of the Peach State Gas System.

As at March 6, 2014, in total, Emera owns 50.1 million APUC common shares representing approximately 24.2% of the total outstanding common shares of the Company, and there are no 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, 2013, APUC recorded $570 and $2.0 million (2012 - $287 and $1.8 million) in total share-based compensation expense. 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, 2013, total unrecognized compensation costs related to non-vested options and share unit awards were $1.8 million and $0.1 million respectively, and are expected to be recognized over a period of 1.57 years and 1.0 year 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.

For the year ended December 31, 2013, 816,402 options were granted to senior executives and certain senior management of APUC which allow for the purchase of common shares at a weighted average price of $7.72. One third of the options will vest on each of January 1, 2014, 2015, and 2016.

As at December 31, 2013, APUC had 4,567,129 options issued and outstanding. 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.



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Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

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. As APUC does not expect to settle these instruments in cash, these PSUs are accounted for as equity awards.

As at December 31, 2013, a total of 66,195 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.

As at December 31, 2013, a total of 74,786 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. As at December 31, 2013, a total of 146,813 shares had been issued under the ESPP.

MANAGEMENT OF CAPITAL STRUCTURE

APUC views its capital structure in terms of its debt levels, at APCo, Liberty Utilities and an overall company level, and its equity balances.

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 proper credit facilities available for ongoing investment in growth and investment in development opportunities.

APUC monitors its cash position on a regular basis to ensure funds are available to meet current normal as well as capital and other expenditures. In addition, APUC continuously reviews its capital structure to ensure its individual business units are using a capital structure which is appropriate for their respective industries.

RELATED PARTY TRANSACTIONS

Resolution of Business Associations with APMI, Affiliates and Senior Executives

Ian Robertson and Chris Jarratt (“Senior Executives”) 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” within this section refers to a Committee comprising the independent members of the Board of Directors of APUC as defined in National Instrument 58-101. 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 fair market valuations of the generating assets, tax and legal matters.

The process initiated in 2011 has been completed and all related party transactions between APUC and the Parties have been resolved to the satisfaction of the Independent Board Committee and the Board as discussed below.



2013 Annual Report	46
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

The following describes the business associations and resolution with APMI and Senior Executives:

Due to and from related parties

As at December 31, 2013, amounts due from related parties were nil (December 31, 2012 - $816) owed to APUC from the Parties and amounts due to related parties were nil (December 31, 2012 - $1,811) owed to the Parties.

Prior to 2010, APMI was the manager of APIF (predecessor organization to APUC) and at the time of the internalization of management, had a number of fees under negotiation as described below:


•	APMI was one of the original developers of the Red Lily I Wind Facility and was entitled to a royalty fee based on a percentage of operating revenue and a development fee from the equity owner of the Red Lily I Wind Facility. In 2011, APUC acquired APMI’s interest in this royalty.


•	As part of the project to re-power the Sanger facility, APUC entered into an agreement with APMI to undertake certain construction management services on the project for a performance based contingency fee.


•	During 2007, APUC allowed its offer to acquire Clean Power Income Fund to expire and earned a termination fee for which APMI was entitled to a portion thereof.


•	During 2008, APMI provided construction supervision services for the construction of BCI Thermal Facility and was entitled to a construction supervision fee on the BCI projects.


•	During 2009, APMI provided management services to APUC for which fees were earned but not paid. In the provision of these management services, APMI incurred and was also entitled to reimbursement of reasonable expenses in 2009 which were not reimbursed by APUC.

Resolution: The Independent Board Committee and the Parties entered into a definitive agreement on November 15, 2013 whereby APUC agree to pay the Parties $1,829 in connection with outstanding fees and the Parties shall pay APUC $812 in connection with reimbursement of expenses both in full satisfaction of the related party balances. The balances have been fully settled as at December 31, 2013.

The aforementioned transaction was completed by December 31, 2013.

Equity interests in Rattle Brook Hydro, Long Sault Hydro, and BCI Thermal Facilities

Prior to December 31, 2013, the Parties owned interests in three power generation facilities in which APUC also has an interest in. A brief description of the facilities is provided as follows:


•	Rattle Brook Hydro Facility is a 4 MW hydroelectric generating facility constructed in 1998 in which APUC owned a 45% interest and Senior Executives held 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 the Long Sault Hydro Facility by way of subscribing to two notes from the original partners. One of the original partners is an affiliate of APMI which was entitled to receive 5% of the equity cash flows commencing in 2014.


•	BCI is an energy supply facility which sells steam produced from APCo’s EFW Facility . In 2004, APMI acquired 50 Class B partnership units in BCI equal to 50% of the annual returns on the project greater than 15%.

Resolution: As part of the process to resolve the co-ownership issue of the above noted assets, the Independent Board Committee undertook valuations by independent consultants which were reviewed and accepted by the Independent Board Committee. APUC and the Parties entered into an agreement whereby APUC would acquire the Parties’ shares of Algonquin Power Corporation Inc. which owns a residual equity interest in the 18MW Long Sault Rapids Hydro Facility and the partnership interest in the BCI Thermal Facility for an amount equal to $3,780. In addition APUC and the Parties entered into an agreement whereby the Parties would acquire APUC’s 45% interest in the 4MW Rattle Brook Hydro Facility for an amount equal to $3,408. APUC earned a fee of $400 from APC during the year ended December 31, 2013 (2012 -$nil) related to settlement of the related party transactions.

The aforementioned transaction was completed on December 31, 2013.

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. The Class B units held by Senior Executives received cash distributions of $nil and $14 for the three and twelve months ended December 31, 2013 (2012 - $47 and $175).

Resolution: On January 1, 2013, the Company issued 100 redeemable Series C preferred shares and exchanged such shares for the 100 Class B units including 36 units held indirectly by Senior Management. The Series C preferred



2013 Annual Report	47
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

shares provide dividends identical to what is expected from the Class B units, as determined by independent consultants retained by the Independent Board Committee. Independent tax, legal and accounting advisors were also retained by the Independent Board Committee to provide advice in relation to the exchange.

As of January 1, 2013, no Senior Executives had any further direct or indirect ownership of the St. Leon facility.

Office Facilities

APUC has leased a portion of its head office facilities since 2001 on a triple net basis from an entity partially owned by Senior Executives. The Independent Board Committee conducted independent reviews of the office leasing market and believes the current terms and conditions for office lease are at fair market value for a building of comparable size and quality. Base lease costs for the three and twelve months ended December 31, 2013 were $77 and $310 (2012 ‑ $83 and $333).

Resolution: The current office lease for a portion of its head office facilities expires on December 31, 2015. In August 2013, APUC through a wholly owned subsidiary has acquired a new office facility which is suitable for meeting the future head office needs of APUC. Upon occupancy of the new head office facilities which is anticipated to occur in 2014, it is expected that the currently occupied premises will be subleased to third parties and the relationship between APUC and Senior Executives in respect of office premises will be concluded.

The Board has deemed this related party transaction to have been satisfactorily addressed.

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 interest. In 2004, APUC remitted $1,300 to an affiliate of APMI as an advance against expense reimbursements (including utilization reserves) for APUC’s business use of the aircraft. By the end of 2012 the entire advance had been amortized against expense reimbursements and therefore no amortization expense during the three and twelve months ended December 31, 2013 related to the advance were incurred (2012 - $52 and $279). During the three and twelve months ended December 31, 2013, APUC reimbursed direct costs in connection with the use of the aircraft of $161 and $472 (2012 ‑ $103 and $598).

Resolution: As of December 31, 2013, the remaining amount of the advance was $nil (December 31, 2012 - $nil) and as a result the Independent Board Committee is satisfied that the advance arrangement has concluded. The Independent Board Committee and the Parties have agreed that all future utilization of chartered aircraft will be undertaken through third party charter operators at fair market value and under arrangements in which the Senior Executives have no interest.

The Board has deemed this related party transaction to have been satisfactorily addressed.

Operations Services

APUC provides supervisory services on a cost recovery basis for one small hydro facility hydroelectric generating facility where Senior Executives hold an equity interest. The fees paid in relation to the supervisory management services were nominal for the three and twelve months ended December 31, 2012 and 2013.

Resolution: This agreement terminated on December 31, 2013.

Trafalgar

APCo owns debt on seven hydroelectric facilities owned by Trafalgar Power Inc. and an affiliate (“Trafalgar Hydro Facility”). 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 million in legal fees prior to 2004.

Resolution: In 2004, the Board reimbursed APMI $1 million of the total third party legal fees (which to that point totalled $2 million), and APUC would 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.

The Board has deemed this related party transaction to have been satisfactorily addressed.



2013 Annual Report	48
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Other Related Party Transactions

Related Party Transactions between APUC and Emera are discussed in the section below titled “Transactions with Emera”.

Transactions with Emera

A member of the Board of Directors of APUC, Chris Huskilson, is an executive at Emera.

In 2011, a subsidiary of Emera provided lead market participant services for fuel capacity and forward reserve markets to ISO NE for the Windsor Locks facility. During the three and twelve months ended December 31, 2013 APUC paid U.S. $nil (2012 - U.S. $nil) in relation to this contract. In 2011, APUC provided a corporate guarantee to a subsidiary of Emera in an amount of U.S. $1,000 in conjunction with this contract.

For the three and twelve months ended December 31, 2013, the Energy Services Business sold electricity to Maine Public Service Company (“MPS”), a subsidiary of Emera, amounting to U.S. $1,453 and U.S. $6,042 (2012 - U.S. $1,539 and U.S. $6,096). In 2011, APUC provided a corporate guarantee to MPS in an amount of U.S. $3,000 and a letter of credit in an amount of U.S. $100, primarily in conjunction with a three year contract to provide standard offer service to commercial and industrial customers in Northern Maine.

The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.

Other

An individual related to Ian Robertson, CEO of APUC provided market research consulting services to certain subsidiaries of Liberty Utilities. During the three and twelve months ended December 31, 2013 APUC paid $nil and $29 (2012 - $nil and $nil) in relation to these services.

TREASURY RISK MANAGEMENT

APUC attempts to proactively manage the risk exposures of its subsidiaries in a prudent manner. APUC ensures that both APCo and Liberty Utilities maintain insurance on all of their facilities. This includes property and casualty, boiler and machinery, and liability insurance. It has also initiated a number of programs and policies including currency and interest rate hedging policies to manage its risk exposures.

There are a number of monetary and financial risk factors relating to the business of APUC and its subsidiaries. Some of these risks include the U.S. versus Canadian dollar exchange rates, energy market prices, interest rate, liquidity and commodity price risk considerations, and credit risk associated with a reliance on key customers. The risks discussed below are not intended as a complete list of all exposures that APUC may encounter. A further assessment of APUC and its subsidiaries’ business risks is also set out in the most recent AIF.

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 72% of EBITDA in 2013 and 70% 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 $16.2 million ($0.08 per share) on an annual basis.

APUC manages this risk primarily through the use of natural hedges by using U.S. long term debt to finance its U.S. operations. APUC’s policy is not to utilize derivative financial instruments for trading or speculative purposes.

Market price risk

Liberty Utilities is not exposed to market price risk as rates charged to customers are stipulated by the respective regulatory bodies.

On May 15, 2012, APCo 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 APCo’s production volume against exposure to the Alberta Power Pool’s current spot market rates. For the unhedged portion of production, each $10.00 per MW-hr change in the market prices in the Western region would result in a change in revenue of $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 production volume against exposure to PJM Western Hub current spot market rates. For the unhedged portion of production, each $10 per MW-hr change in the market prices would result in a change in revenue of about $0.3 million for the year.



2013 Annual Report	49
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

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 Senate Wind Facility’s production volume against exposure to ERCOT North Zone current spot market rates. For the unhedged portion of production, each $10 per MW-hr change in the market prices would result in a change in revenue of about $1.1 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 production volume against exposure to PJM Northern Illinois Hub current spot market rates. For the unhedged portion of production, each $10 per MW-hr change in market prices would result in a change in revenue of about $1.1 million for the year.

For the Sandy Ridge, Senate and Minonk Wind Facilities, in the fourth quarter of 2013 APCo entered into unit contingent financial hedges which commenced January 1, 2014 for a one year period. These hedges are structured to hedge all of the production from the Facilities in excess of the production covered by the hedges described in the three preceding paragraphs. The hedges do not have a minimum volume commitment and hence the facilities do not bear any market risk associated with production. As a result, the Sandy Ridge, Senate and Minonk Wind Facilities now have hedges in place covering 100% of the energy produced.

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, each $10 per MW-hr change in market prices would result in a change in revenue of about $1.1 million for the year.

Credit/Counterparty risk

APUC and its subsidiaries are subject to credit risk through its 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 this risk to be significant as approximately 85% of APCo Renewable Energy division’s revenue, approximately 100% of APCo Thermal Energy division’s revenue, and over 88.1% of APCo’s total revenue is earned from large utility customers having a credit rating of BBB or better.The following chart sets out APCo’s significant customers, their credit ratings and percentage of total revenue associated with the customer:



Counterparty	Credit Rating ¹	Approximate Annual Revenues		Percent of Divisional Revenue
Renewable Energy Division
PJM Interconnection LLC	Aa3	33.6		23.1	%
Manitoba Hydro	Aa1	27.8		19.1	%
Hydro Quebec	Aa2	22.4		15.4	%
US Wind Hedge Counterparty²	A	12.1		8.3	%
Ontario Electricity Financial Corporation	Aa2	11.7		8.0	%
Main Public Service³	BBB+	9.4		6.4	%
Commonwealth Edison	BBB	7.3		5.0	%
Total – Renewable		$	124.3	85.3	%
Thermal Energy Division
Pacific Gas and Electric Company	A3	16.9		48.9	%
Connecticut Light and Power	A-	17.6		51.1	%
Total – Thermal		$	34.5	100.0	%
Total – APCo		$	158.8	88.1	%



1	Ratings by Moody’s or Standard & Poor’s as of February 2014.
2	Hedge counterparty for the Sandy Ridge, Senate, and Minonk Wind Facilities
3	Maine Public Service is a subsidiary of Emera.



2013 Annual Report	50
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

The remaining revenue is primarily earned by Liberty Utilities. In this regard, the credit risk related to the Liberty Utilities (West) and Liberty Utilities (Central) regions' accounts receivable balances related to the water and wastewater utilities total U.S. $3.3 million which is spread over approximately 93,000 connections, resulting in an average outstanding balance of approximately $35.00 dollars per connection. Liberty Utilities (East) and Liberty Utilities (Central) regions' accounts receivable balances related to the natural gas utilities total U.S. $52.6 million, while the Liberty Utilities (East) and Liberty Utilities (West) regions’ accounts receivable balances related to the electric utilities total U.S. 15.7 million. The natural gas and electrical utilities derive over 88% of their revenue from residential customers.

In addition to the counterparty risk related to customer sales outlined above, APCo and Liberty Utilities utilizes 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:


•	The APUC Facility is subject to a variable interest rate. The APUC Facility has no amounts outstanding as at December 31, 2013. As a result, a 100 basis point change in the variable rate charged would not impact interest expense.


•	The APCo Facility had $124.6 million outstanding as at December 31, 2013. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $1.2 million annually.


•	APCo’s project debt at its Sanger Thermal Facility has a balance of U.S. $19.2 million as at December 31, 2013. Assuming the current level of borrowings over an annual basis, a 100 basis point change in the variable rate charged would impact interest expense by U.S. $0.2 million annually.


•	The Liberty Facility had $80.5 million outstanding as at December 31, 2013. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.8 million annually.


•	The Shady Oaks Senior Debt Facility had $129.8 million outstanding as at December 31, 2013. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $1.3 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.

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 APCo and Liberty 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 at each of APCo and Liberty Utilities to meet their liabilities when due.

As at December 31, 2013, APUC and its subsidiaries had a combined $202.6 million of committed and available credit facilities remaining and $13.8 million of cash resulting in $216.4 million of total liquidity and capital reserves.

APUC currently pays a dividend of $0.34 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 dividends paid during the year ended December 31, 2013, cash provided by operating activities exceeded dividends declared by 1.4 times and exceeds Adjusted Cash From Operations by 2.2 times.

The long term portion of debt totals approximately $1,255.6 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.



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Commodity price risk

APCo’s exposure to commodity prices is primarily limited to exposure to natural gas price risk. Liberty Utilities is exposed to energy price risk in the Liberty Utilities (West) and Liberty Utilities (East) regions. Additionally, Liberty Utilities is exposed to natural gas price risk in the Liberty Utilities (Central) and Liberty Utilities (East) regions.

In this regard, a discussion of this risk is set out as follows:


•	APCo’s 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.


•	APCo’s Windsor Locks Thermal Facility’s ESA includes provisions which reduce its exposure to natural gas price risk but has exposure to market rate conditions for sales above those to Ahlstrom. 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.

•

AES provides short-term energy requirements to various customers at fixed rates. The energy requirements of these customers are estimated at approximately 200,000 MW-hrs in fiscal 2014. While the Tinker facility is expected to provide the majority of the energy required to service these customers, AES anticipates having to purchase approximately 90,000 MW-hrs of its energy requirements at the ISO-NE spot rates to supplement self-generated energy. The risk associated with the expected market purchases of 90,000 MW-hrs is mitigated through the use of short-term financial energy hedge contracts which cover approximately 65,000 MWhrs of AES's anticipated purchases over the next 12 months at an average rate of approximately $59 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 $0.3 million on an annualized basis.

Liberty Utilities is exposed to energy price risk in the Liberty Utilities (West) region which is mitigated through a regulatory balancing account. The Liberty Utilities (West) region 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 purchase power agreement 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. In the CalPeco Electric System's 2012 general rate case, a revenue decoupling mechanism and a vegetation management memorandum account were agreed upon. 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.

In the Liberty Utilities (East) region, 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, the 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 and quarterly for large 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(s) 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.

In the Liberty Utilities (East) region, the EnergyNorth Gas System purchases pipeline capacity, storage and commodity from a variety of counterparties. The EnergyNorth Gas System's portfolio of assets, planning and forecasting methodology is approved by the NHPUC bi-annually through an Integrated Resource Plan filing. In addition, the EnergyNorth Gas System files with the NHPUC for recovery of its transportation and commodity costs through a semi-annual winter and summer Cost of Gas (COG) filing and approval process. The EnergyNorth Gas System establishes rates for its customers within the COG filing and these rates are designed to fully recover its anticipated transportation and commodity costs. In order to minimize commodity price fluctuations, the EnergyNorth Gas System has implemented a NHPUC approved commodity hedging program designed to hedge approximately 60% 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 COG filing and the approved rates in said filing. Should



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commodity prices increase or decrease relative to the initial semi-annual COG rate filing, the EnergyNorth 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 carrying costs to the next year’s period COG filing, i.e. winter to winter and summer to summer.

The Liberty Utilities (Central) region 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 Liberty Utilities (Central) region 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 Liberty Utilities (Central) region 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. The Liberty Utilities (Central) region may adjust its rates 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

APUC attempts to proactively manage its risk exposures in a prudent manner and has initiated a number of programs and policies such as employee health and safety programs and environmental safety programs to manage its risk exposures.

There are a number of risk factors relating to the business of APUC and its subsidiaries. Some of these risks include the dependence upon APUC businesses, regulatory climate and permits, tax related matters, gross capital requirements, labour relations, reliance on key customers and environmental health and safety considerations. A further assessment of APUC’s business risks is set out in the most recent AIF.

Mechanical and Operational Risks

APUC is entirely dependent upon the operations and assets of APUC’s businesses. This profitability could be impacted by 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 hydro assets of APCo utilize dams to pond water for generation and if the dams burst catastrophic amounts of water would flood downriver from the facility. The units can be subjected to drought conditions and lose the ability to generate during peak load conditions, causing the facilities to miss on 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 wind assets of APCo could catch on fire, and depending on the season could ignite significant amounts of forest or crop downwind from the unit. The wind units could also be affected by large atmospheric conditions (e.g. El Nina) which will lower wind levels below our PPA and hedge minimum production levels. The wind units risk is mitigated by properly maintaining the units using long term maintenance agreements with the turbine O&M’s by 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 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 by the regular maintenance of the boiler system, and by continual monitoring of exhaust gases. Fuel restrictions can be hedged somewhat by long term purchases.

The water distribution networks of Liberty Utilities 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 electricity distribution systems owned by Liberty Utilities 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 gas distribution systems owned by Liberty Utilities 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 (APCo and Liberty Utilities) 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.



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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 APCo hydroelectric facilities, water rights are generally owned by governments who reserve the right to control water levels which may affect revenue.

Liberty Utilities’ 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. The Liberty Utilities (West) region's CalPeco Electric System files a Post-Test Year Adjustment Mechanism ("PTAM") that increases base tariff general rates for inflation. Federal, State and local environmental laws and regulations impose substantial compliance requirements on electricity and natural gas distribution utilities. Operating costs could be significantly affected in order to comply with new or stricter regulatory requirements.

Electricity and natural gas distribution utilities could be subject to condemnation or other methods of taking by government entities under certain conditions. While any taking by government entities would require compensation be paid to Liberty Utilities, and while Liberty Utilities believes it would receive fair market value for any assets that are taken, there is no assurance that the value received for assets taken will be in excess of book value.

Liberty Utilities regularly works with its governing authorities to manage the affairs of the business.

Asset Retirement Obligations

APUC and its subsidiaries complete periodic reviews of potential asset retirement obligations that may require recognition. As part of this process, APUC and its subsidiaries consider the contractual requirements outlined in their operating permits, leases and other agreements, the probability of the agreements being extended, the likelihood of being required to incur such costs in the event there is an option to require decommissioning in the agreements, the ability to quantify such expense, the timing of incurring the potential expenses as well as business and other factors which may be considered in evaluating if such obligations exist and in estimating the fair value of such obligations.

Liberty Utilities’ 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, Liberty Utilities has regular maintenance programs at each facility to ensure its equipment is properly maintained and replaced on a cyclical basis. These maintenance expenses, expenses associated with replacing aging distribution facilities and expenses associated with providing new sources of commodity supply can generally be included in the facility’s rate base and thus Liberty Utilities expects to be allowed to earn a return on such investment.

In conjunction with the recent acquisitions the Company assumed certain asset retirement obligations. The asset retirement obligations mainly relate to legal requirements to: (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 adequate insurance which include property, boiler and machinery, environmental and excess liability policies.

APCo’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; State/Provincial Agencies such us, 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.

Liberty Utilities 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, Liberty Utilities generates some hazardous wastes as a result of its operations. Under Federal and State Superfund laws, potential liability for



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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, Liberty Utilities investigates 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. 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. Liberty 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.

The Liberty Utilities (East) region’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 Liberty Utilities, 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 Liberty Utilities 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 Liberty Utilities believes that obligations imposed on it because of those sites will not have a material impact on its results of operations or financial position.

Liberty Utilities estimates the remaining cost of these MGP-related environmental cleanup activities will be $77.7 million which at a discount rates ranging from 3.8% to 4.5% represents $69.6 million at December 31, 2013, which has been accrued as Liberty Utilities’ estimate of costs for known issues. By rate orders, the Regulator provided for the recovery of site investigation and remediation costs and accordingly, at December 31, 2013 the Company has reflected a regulatory asset of $80.4 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 Season

The hydroelectric operations of APCo are impacted by seasonal fluctuations. 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. It is, however, anticipated that due to the geographic diversity of the facilities, variability of total revenues will be minimized.

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 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 Liberty Utilities (West) and Liberty Utilities (Central) regions’ 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.

Prior to January 1, 2013, the Liberty Utilities (West) region was exposed to volume sales risk related to seasonal weather variations at the CalPeco Electric System. Effective on January 1, 2013, pursuant to a CPUC approved Rate Case decision, a Base Revenue Requirement Balancing Account (BRRAM) rate mechanism has been implemented. The BRRAM removes the



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seasonal variations of the revenues and flattens the net revenue (minus Fuel, Purchased Power, and ECAC) to a monthly rate of $3.0 million or $36.0 million annually. This eliminates the risk of revenue variations associated with seasonal weather changes.

The Liberty Utilities (West) region’s demand for energy is primarily affected by weather conditions and conservation initiatives. Above normal snowfall in the Lake Tahoe area brings more tourists with an increased demand for electricity by small commercial customers. The Liberty Utilities (West) 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 BRRAM mitigates this risk.

The Liberty Utilities (East) and Liberty Utilities (Central) regions' natural gas demand is driven by the seasonal heating requirements of its residential, commercial, and industrial customer. That is, the colder the weather the greater the demand for natural gas to heat homes and businesses. As such, the Liberty Utilities (East) and Liberty Utilities (Central) regions’ natural gas demand profiles typically peaks in the winter months of January and February and declines in the summer months of July and August. At the Peach State Gas System, 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.

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. The Second Circuit Court of Appeals, among other things, on November 2, 2010 dismissed the claims against APUC in the civil proceedings. The bankruptcy proceedings are continuing, with a Second Circuit Court of Appeal hearing scheduled for December 12, 2012 to hear the appeal of the District Court’s October 25, 2011 decision holding that APUC does not have a security interest in the monies transferred by Trafalgar before it filed for bankruptcy protection.

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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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.

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. Cross examinations were held in November, 2013. A hearing is scheduled for early 2014.

Dimos and Katsekas breach of contract claim

On September 30, 2013, previous owners of the Clement Dam hydro facility, filed a demand for arbitration with Algonquin Power Fund (America) Inc. 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 March, 2015.

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. Discovery is being scheduled.

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 project in Ontario, Canada. Plaintiffs attempted to serve Algonquin with the complaint on February 11, 2014.

Bryson School District in Texas property taxes claim

On February 10, 2014, APCo received correspondence from the Bryson 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. The assertion is being disputed.

Obligations to serve

Liberty Utilities 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, Liberty Utilities may be required to solicit additional capital or obtain additional borrowings to finance these future construction obligations.



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Quarterly Financial Information

The following is a summary of unaudited quarterly financial information for the eight quarter ended December 31, 2013:



Millions of dollars (except per share amounts)	1^st Quarter 2013		2^nd Quarter 2013			3^rd Quarter 2013			4^th Quarter 2013
Revenue	$	193.1	$	148.8		$	127.9		$	205.3
Adjusted EBITDA	61.8		56.5			40.5			67.6
Net earnings / (loss) attributable to shareholders from continuing operations	20.4		15.8			6.3			19.8
Net earnings / (loss) attributable to shareholders	19.2		(18.1		)	6.0			13.1
Net earnings / (loss) per share from continuing operations	0.10		0.08			0.02			0.09
Net earnings / (loss) per share	0.10		(0.09		)	0.02			0.06
Adjusted net earnings	19.4		15.4			6.9			18.5
Adjust net earnings per share	0.10		0.08			0.03			0.08
Total Assets	2,990.7		3,201.8			3,156.4			3,472.6
Long term debt*	917.5		1,091.5			1,092.0			1,255.6
Dividend declared per common share	0.08		0.09			0.09			0.09
	1^st Quarter 2012		2^nd Quarter 2012			3^rd Quarter 2012			4^th Quarter 2012
Revenue	$	58.1	$	58.7		$	93.0		$	138.9
Adjusted EBITDA	21.4		22.2			20.8			24.0
Net earnings / (loss) attributable to shareholders from continuing operations	2.0		5.3			(0.6		)	6.8
Net earnings/(loss) attributable to shareholders	2.3		6.1			(0.2		)	6.4
Net earnings / (loss) per share from continuing operations	0.01		0.03			—			0.04
Net earnings/(loss) per share	0.02		0.04			—			0.03
Adjusted net earnings	5.0		6.5			1.1			6.5
Adjust net earnings per share	0.04		0.04			0.01			0.03
Total Assets	1,265.6		1,416.0			1,967.1			2,779.0
Long term debt¹	391.9		461.8			705.1			770.8
Dividend declared per common share	0.07		0.07			0.08			0.08



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 $58.1 million and $205.3 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.

Quarterly net earnings attributable to shareholders have fluctuated between net earnings attributable to shareholders of $19.2 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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Disclosure Controls

At the end of the fiscal year ended December 31, 2013, 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, 2013, 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, 2013, APUC acquired the Shady Oaks Wind Facility, the Pine Bluff Water System, the Peach State Gas System and the New England Gas System. The financial information for these business acquisitions is included in this MD&A and in Note 3 to the consolidated financial statements. As permitted by National Instrument 52-109 and the U.S. Securities and Exchange Commission, the Company excluded these acquisitions from its evaluation of the effectiveness of APUC’s internal controls over financial reporting as of December 31, 2013 due to the complexity associated with assessing internal controls during integration efforts and the proximity of some of the acquisitions to year-end.

Management conducted an evaluation of the design and operation of APUC’s internal control over financial reporting as of December 31, 2013 based on the criteria set forth in Internal Control – Integrated Framework (1992) 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, 2013.

During the year ended December 31, 2013, 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. APUC continues to implement its internal control structure over the operations of the acquired businesses discussed above.

Critical Accounting Estimates and Polices

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 and Intangibles



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The provisions for depreciation of utility 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, 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 Liberty Utilities’ 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 write 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. Derivative instruments that do not meet the normal purchases and sales exception are recorded at fair value. Changes in the derivative’s fair value are recognized as regulatory assets or liabilities when the regulator permits recovery of the hedging strategy. For derivative designated in a cash flow hedge relationship, the effective portion of the change in fair value is deferred to accumulated other comprehensive income, until the hedged transaction occurs and is recognized in earnings. The ineffective portion is immediately recognized in earnings. For derivative or financial instruments designated as a hedge of the foreign currency exposure of a net investment in foreign operations, foreign currency transaction gain or loss that are effective as an economic hedge of the net investment in a foreign operation are reported in other comprehensive income.

Management’s judgment is required to determine if a transaction meets the definition of a derivative and, if it does, 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



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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. A significant change in estimate could affect APUC’s results of operations.

Fair value of assets and liabilities acquired in a business combination

The Company has closed 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 SEDAR at www.sedar.com and on the APUC website at www.AlgonquinPowerandUtilities.com.



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Algonquin Power & Utilities (AQN) 40-F2013 FY Annual report (Canada)

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