Algonquin Power & Utilities 40F 2012 Annual report | AQN Filing

Exhibit 99.3

LOGO

Management’s Discussion and Analysis

(All monetary amounts are in thousands of Canadian dollars, except per share and convertible debenture 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, 2012. The Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with APUC’s audited consolidated financial statements for the years ended December 31, 2012 and 2011. This material is available on SEDAR atwww.sedar.com and on the APUC website atwww.AlgonquinPowerandUtilities.com. Additional information about APUC, including the most recent Annual Information Form (“AIF”) can be found on SEDAR atwww.sedar.com.

This MD&A is based on information available to management as of March 14, 2013.

Caution concerning forward-looking statements and non-GAAP Measures

Certain statements included herein contain forward-looking information within the meaning of certain securities laws. These statements reflect the views of APUC with respect to future events, based upon assumptions relating to, among others, the performance of APUC’s assets and the business, interest and exchange rates, commodity market prices, and the financial and regulatory climate in which it operates. These forward looking statements include, among others, statements with respect to the expected performance of APUC, its future plans and its dividends to shareholders. Statements containing expressions such as “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.

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” and “per share cash provided by operating activities” 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” and Adjusted EBITDA 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” and “per share cash provided by operating activities” 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” and “per share cash provided by operating activities” 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.

Overview and Business Strategy

APUC is incorporated under theCanada 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 targets to deliver annualized per share earnings and cash flow growth of more than 5%.

APUC’s current quarterly dividend to shareholders is $0.0775 per share or $0.31 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 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 170 MW. APCo also owns or has interests in wind powered generating stations with a combined generating capacity of 650 MW. Approximately 84% 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 15 years.

APCo owns or has interests in thermal energy facilities with approximately 341 MW of installed generating capacity. Approximately 95% 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 7 years.

Liberty Utilities Co.

Liberty Utilities is a diversified rate regulated utility providing electricity, natural gas, water distribution and wastewater collection utility services. 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 Utility”) serve approximately 46,955 active electric connections in the State of California. Liberty Utilities (West) region’s regulated water and wastewater utility systems serve approximately 66,550 water and wastewater connections located in the State of Arizona.

wastewater collection utilities serve approximately 11,500 water and wastewater customers located in the States of Arkansas, Illinois, Missouri, and Texas.

Liberty Utilities (East) region is comprised of regulated natural gas and electric distribution utility systems located in the State of New Hampshire providing regulated local electrical utility services to approximately 43,250 active electric connections; and regulated local gas distribution utility services to approximately 87,650 active natural gas connections. Upon completion of certain pending acquisitions of natural gas utility systems located in Georgia and Massachusetts, the additional 114,000 customers will be added to the Liberty Utilities (East) region.

Major Highlights

Corporate Highlights

Dividend Increased to $0.31 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 August 9, 2012, the Board approved a dividend increase of $0.03 per share annually bringing the total annual dividend to $0.31, paid quarterly at the rate of $0.0775 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.

Strengthened Balance Sheet

Issuance of $120M Preferred Shares

On November 9, 2012, APUC issued 4.8 million cumulative rate reset preferred shares, Series A (the “Series A Shares”) at a price of $25 per share, for aggregate gross proceeds of $120 million. The shares will yield 4.5% annually for the initial six-year period ending on December 31, 2018. The preferred shares have been assigned a rating of P-3 and Pfd-3(low) by S&P and DBRS respectively. The proceeds of the offering were used primarily to partially fund the acquisition of the interest in the Gamesa wind powered generating stations (the “Gamesa Wind Facilities”) which closed on December 10, 2012.

Emera Subscription Receipts

For the year ended December 31, 2012, APUC issued a total of 26.4 million shares for cash and share proceeds of $142.6 million pursuant to the exercise of subscription receipts issued to Emera in contemplation of certain previously announced transactions. The shares were issued in the context of the existing Strategic Investment Agreement which contemplates Emera’s investment in APUC of up to 25%.

As at December 31, 2012, Emera owned 34.9 million APUC common shares representing approximately 18.5% of the total outstanding common shares of the Company.

Subsequent to the end of the year and pursuant to previously committed subscription receipts, APUC issued 2.6 million shares at a price of $5.74, 5.2 million shares at a price of $5.74 and 3.4 million shares at a price representing $4.72 per share pursuant to subscription agreements. As a result, at March 14, 2013, Emera owns 46.1 million APUC common shares representing approximately 23% of the total outstanding common shares of the Company.

On February 22, 2013, APUC announced that Emera agreed to subscribe to 4.0 million common shares of APUC at a price of $7.40 per share for total proceeds of approximately $29 million representing a $0.10 premium to the closing price of APUC shares on February 19, 2013. The conversion of these subscription receipts will bring Emera’s total investment in APUC to 25%.

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.

Conversion of Series 2A Convertible Debentures to Equity

On February 24, 2012 (“Series 2A Redemption Date”), APUC redeemed $57.0 million, representing the remaining issued and outstanding, Series 2A Debentures by issuing and delivering 9,836,520 APUC common shares. Between January 1, 2012 and the Series 2A Redemption Date, a principal amount of $2.9 million of Series 2A Debentures were converted into 485,998 common shares of APUC.

Conversion and Redemption of Series 3 Convertible Debentures to Equity

On December 31, 2012 (“Series 3 Redemption Date”), APUC converted $55.3 million of Series 3 Debentures by issuing and delivering 13,172,619 APUC common shares. On January 1, 2013, APUC completed a redemption of the outstanding Series 3 Debentures by issuing and delivering 150,816 APUC common shares for the remaining $0.9 million in Series 3 Debentures.

APUC Credit Facility

On November 19, 2012, APUC entered into an agreement for a $30.0 million senior unsecured revolving credit facility (“APUC Facility”) with a Canadian chartered bank. The credit facility will be used for general corporate purposes and has a maturity date of November 19, 2015.

Liberty Utilities Highlights

Agreement to Acquire New England Utility

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 New England Gas Company (“NEGasCo Acquisition”) from an affiliate of Southern Union Company. New England Gas Company is a natural gas distribution utility serving over 50,000 customers in Massachusetts. The acquisition is subject to certain approvals and conditions, including state and federal regulatory approval, and is expected to close in the second half of 2013.

Total consideration for the utility asset purchase is approximately U.S. $74 million, subject to working capital and closing adjustments representing a 1.0x premium to regulatory assets of $73.9 million. The purchase price will be funded using a target capital structure of 52% equity and 48% debt and will include the assumption of U.S. $19.5 million of existing debt.

Agreement to Acquire Georgia Utility

On August 8, 2012, Liberty Utilities entered into an agreement with Atmos to acquire certain regulated natural gas distribution utility systems (the “Georgia Utility”) serving approximately 64,000 connections located in the State of Georgia. The total purchase price for the Georgia Utility is approximately U.S. $140.7 million representing a 1.1x premium to net assets for regulatory purposes of U.S. $128.1 million and is subject to certain working capital and other closing adjustments.

On February 22, 2013, Liberty Utilities has received all federal and state regulatory approvals required to complete the acquisition. Closing is expected to occur on or about April 1, 2013 and will be reported as part of the Liberty Utilities (East) region.

Acquisition of Remaining Interest in the California Utility

On December 21, 2012, APUC completed the acquisition of the remaining 49.999% ownership in California Pacific Utility Ventures LLC, which owns 100% of the Calpeco Electric Utility assets. APUC acquired the remaining 49.999% interest from Emera through proceeds received from the issuance of 8.2 million APUC common shares, 4.8 million of which were issued on December 27, 2012, and the remaining 3.4 million shares issued on February 14, 2013.

Acquisition of New Hampshire Utility

On July 3, 2012, Liberty Utilities completed the acquisition of all issued and outstanding shares of Granite State Electric Co. (“Granite State Electric Utility”) and EnergyNorth Natural Gas Inc. (“EnergyNorth Gas Utility”), both from National Grid, for consideration of U.S. $285.0 million plus working capital and other closing adjustments for a total consideration of U.S. $295.8 million. The purchase price for the utility assets represents a multiple of aggregate expected regulatory assets of approximately 1.14x. The regulated electric distribution company provides electric service to over 43,000 connections in 21 communities in New Hampshire and the regulated natural gas distribution

utility provides natural gas service to over 87,000 connections in five counties and 30 communities in New Hampshire.

In the first half of 2013, Granite State Electric Utility will file a rate case with the New Hampshire Public Utilities Commission (“NHPUC”) seeking an increase in distribution base rates. The filing is based on a 2012 test year, with revenues and expenses reflecting known and measurable changes. The regulatory process associated with the rate case is expected to last one year, with temporary rates expected to be implemented on or about July 1, 2013 and the final permanent rates determined in the rate case going into effect on or about March 2014.

Acquisition of Missouri Utility

On August 1, 2012, Liberty Utilities completed the acquisition of regulated natural gas distribution utility systems (the “Midwest Gas Utilities”) located in Missouri, Illinois, and Iowa from Atmos Energy Corporation (“Atmos”) for consideration of U.S. $127.7 million plus working capital and other closing adjustments for a total consideration of U.S. $128.2 million.

The acquisition was originally announced in May 2011 and final regulatory approvals were received in June 2012. The purchase price for the utility assets represented a multiple of net assets for regulatory purposes of approximately 1.1x. Collectively, the regulated natural gas distribution systems provide natural gas service to approximately 82,000 connections.

Acquisition of Arkansas Utility

On February 1, 2013, Liberty Utilities completed the acquisition of issued and outstanding shares of United Water Arkansas Inc., a regulated water distribution utility (“Pine Bluff Water Utility”) from United Waterworks Inc. The Pine Bluff Water Utility is located in Pine Bluff, Arkansas and serves approximately 17,000 customers. Total purchase price for the Pine Bluff Water Utility was approximately U.S. $27.6 million representing a 1.16x premium to net utility assets of U.S. $24.6 million and subject to certain working capital and other closing adjustments. The Pine Bluff Water Utility will be included in the Liberty Utilities (Central) region.

U.S. Debt Private Placements

In connection with the above noted gas and electric utility acquisitions during the third quarter, Liberty Utilities completed a U.S. $225 million private placement debt financing. The financing was closed in two tranches contemporaneously with the closing of the New Hampshire and Missouri Utilities acquisitions. The notes are senior unsecured notes with an average life maturity of over ten years and a weighted average coupon of 4.38%. The notes have been assigned a rating of “BBB high” by DBRS Limited. Proceeds from the private placement were used to partially fund the New Hampshire and Midwest Gas Utilities acquisitions.

Subsequent to the year end on March 14, 2013 Liberty Utilities completed a U.S. $15 million private placement debt financing in connection with the above noted acquisition of an Arkansas water utility. The notes are senior unsecured with a 10 year term and a coupon of 4.14%.

U.S. $100 million Acquisition Term Facility

On March 14, 2013 Liberty Utilities entered into a U.S. $100 million term loan with a U.S. Bank. The loan facility is available for acquisitions and general corporate purposes and matures on December 31, 2013.

Expansion of Liberty Utilities Credit Facility

In 2012, Liberty Utilities entered into an agreement for a U.S. $100 million senior unsecured revolving credit facility (the “Liberty Facility”) with a consortium of U.S. banks. The Liberty Facility will be used for general corporate purposes and has a three year term with a maturity date of January 18, 2015.

Algonquin Power Co. Highlights

Acquisition of U.S. Wind Facilities

In 2012 APCo completed its 60% equity investment in a portfolio of three wind powered generating stations: Minonk Wind (200MW), Senate Wind (150MW) and Sandy Ridge Wind (50MW) Facilities (“Gamesa Wind Facilities”) located in the states of Illinois, Texas, and Pennsylvania, respectively for consideration of $271.7 million.

The Gamesa Wind Facilities were acquired through a newly formed partnership whose members include Class B members consisting of APCo (60% interest in Class B membership units) and Gamesa Energy USA, LLC (“Gamesa USA”), a subsidiary of Gamesa Corporación Tecnológica, S.A., the original developer of the projects, (holding a 40% interest in Class B membership units) and certain Class A equity investors who are primarily entitled to the tax attributes associated with the projects. Total cost of the three wind farms was approximately $747 million.

The Gamesa Wind Facilities utilize Gamesa G9X-2.0 MW wind turbines. Gamesa USA has assumed all operations, maintenance, and capital repair responsibilities for the facilities pursuant to a 20 year agreement for the turbines and balance of plant facilities.

Total annual energy production is expected to be 1,352 GW-hrs per year. The Gamesa Wind Facilities have long term, fixed price power sales contracts (the “Power Sales Contracts”) with a weighted average life of 11.8 years (Minonk and Sandy Ridge Wind Facilities 10 years each, Senate Wind Facility 15 years). Approximately 73% of energy revenues would be earned under the Power Sales Contracts. All energy produced in excess of that sold under the Power Sales Contracts, together with ancillary services including capacity and renewable energy credits, will be sold into the energy markets in which the facilities are located.

Acquisition of Shady Oaks Wind Facility

Effective January 1, 2013, APCo acquired a 109.5 MW contracted wind powered generating station (“Shady Oaks Wind Facility”) from Goldwind International SO Limited (“Goldwind”) for total consideration of approximately US$148.9 million.

The Shady Oaks Wind Facility is located in Northern Illinois, approximately 80 km west of Chicago, Illinois and reached 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 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.

APCo $150 million Senior Unsecured Debentures

On December 3, 2012, APCo issued $150 million 4.82% senior unsecured debentures with a maturity date of February 15, 2021 (the “APCo Debentures”) pursuant to a private placement in Canada and the United States. The APCo Debentures were sold at a price of $99.94 per $100.00 principal amount, resulting in an effective yield to maturity of 4.83% per annum. 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 4.4%.

Net proceeds from the APCo Debentures were used primarily to fund the 400MW investment in the Gamesa Wind Facilities discussed above.

APCo Credit Facility

On November 16, 2012, APCo amended its existing $155 million senior secured credit facility (“APCo Facility”) to increase the commitments available under the Facility to $200 million. In addition, the bank syndicate has agreed to release its security previously held over certain APCo entities, such that the amended APCo Facility is now fully unsecured. The APCo Facility now has a maturity date of November 16, 2015.

Completion of Windsor Locks Repowering

APCo has completed the repowering of the Windsor Locks electrical and steam energy generating station. The installation of a new 14 MW Solar Titan combustion gas turbine was completed in July

2012 at a total capital cost of U.S. $18.3 million (net of one-time non-recurring items: State of Connecticut grant for U.S. $6.5 million; and a U.S. Federal Government heat and power investment tax credit (“ITC”) for U.S. $2.4 million) and is now fully operational. As part of the repowering project APCo also entered into an extension of the energy services agreement with Ahlstrom for delivery of 100% of its steam capacity and a portion of its electrical generating capacity. The agreement now continues until 2027. With the new turbine operational the existing Frame 6 is now available as a peaking turbine to generate additional revenues.

Sale of Small U.S. Hydro Facilities

On March 14, 2013, APCo entered into an agreement to sell 10 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 million. The operating results from these facilities are therefore disclosed as discontinued operations on the consolidated statements of operations and prior periods have been reclassified to conform to this presentation.

2012 Annual Results from Operations

During the year, APUC positioned both its regulated and non-regulated utility businesses for significant growth in 2013 and beyond. Growth expected in the first quarter of 2013 will reflect the acquisition of 3 U.S. wind generation facilities near the end of the year. The acquisition of natural gas and electric utilities in the third quarter of 2012 will also contribute to significant growth expected in 2013 as cash flow and earnings from these utilities are heavily weighted to the first and second quarters of each year.

Key Selected Annual Financial Information


	Year ended December 31
(millions of dollars except per share information)	2012		2011		2010

Revenue	$	369.9	$	270.7	$	175.1

Adjusted EBITDA^{1, 3}		106.2		103.7		74.1

Cash provided by operating activities		63.0		69.7		41.4

Adjusted funds from operations^{1, 3}		76.9		72.7		41.5

Net earnings attributable to Shareholders from continuing operations		15.7		24.1		18.3

Net earnings attributable to Shareholders		14.5		23.4		18.0

Adjusted net earnings^{1, 3}		21.1		38.3		22.8

Dividends declared to Common Shareholders		50.2		32.4		22.8

Weighted Average number of common shares outstanding		158,304,340		116,712,934		94,338,193

Per share
Basic net earnings from continuing operations	$	0.10	$	0.21	$	0.19
Basic net earnings	$	0.09	$	0.20	$	0.19
Adjusted net earnings^{1, 2, 3}	$	0.14	$	0.33	$	0.24
Diluted net earnings	$	0.09	$	0.20	$	0.19
Cash provided by operating activities^{1, 2, ,3}	$	0.40	$	0.60	$	0.44
Adjusted funds from operations^{1, 2, 3}	$	0.52	$	0.62	$	0.44
Dividends declared to Common Shareholders	$	0.30	$	0.27	$	0.24

Total assets		2,778.2		1,282.3		1,016.9
Long term liabilities⁴		771.8		455.0		441.7

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.

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	Non-GAAP measure - see applicable section later in this MD&A and the caution regarding non-GAAP measures on page 1.

⁴	Long term debt includes current and long term portion of debt and convertible debentures.

For the year ended December 31, 2012, APUC experienced an average U.S. exchange rate of approximately $0.999 as compared to $0.989 in the same period in 2011. 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, 2012, APUC reported total revenue of $369.9 million as compared to $270.7 million during the same period in 2011, an increase of $99.2 million or 37%. The major factors resulting in the increase in APUC revenue for the year ended December 31, 2012 as compared to the corresponding period in 2011 are set out as follows:


	Year ended December 31, 2012 (Millions)

Comparative Prior Period Revenue	$	270.7

Significant Changes:
Liberty Utilities:
West – Lower electricity sales to customers		(5.4	)
Central – Revenue increase due to Midwest Gas Utilities acquisitions		26.2
East – Gas and electricity revenue due to EnergyNorth Gas Utility and Granite State Electric Utility acquisitions		86.9

APCo:
Renewable:
Effect of hydrology resource compared to comparable period in prior year		(4.7	)
Acquisition of Sandy Ridge, Minonk, and Senate Wind Facilities		3.9
St Leon Wind Facility– Effect of wind resource compared to comparable period in prior year		(1.0	)
St Leon II Wind Facility – Revenue increase from expansion		1.6
Tinker Hydro/AES – Increased demand for retail sales		2.8
Thermal:
Windsor Locks and Sanger Thermal Facilities – Lower power demand and rates, and offline for major maintenance		(10.7	)
Energy-from-Waste Facility – Lower price per tonne for supplemental waste		(2.1	)
Impact of the stronger U.S. dollar		1.1
Other		0.6


Current Period Revenue	$	369.9

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

Adjusted EBITDA in the year ended December 31, 2012 totalled $106.2 million as compared to $103.7 million during the same period in 2011, an increase of $2.5 million or 2%. The increase in Adjusted EBITDA was primarily due to revenues from the St. Leon facility expansion and the EnergyNorth Gas Utility, Granite State Electric Utility, Midwest Gas Utilities, and the Gamesa Wind Facilities acquisitions which closed near the end of the year. These items were partially offset by lower results from operations primarily from lower hydrology in APCo’s Renewable Energy Division, reduced energy sales at APCo’s Windsor Locks facility during the re-powering, reduced margins at APCO’s energy sales group, increased administrative expenses and lower customer demand at the Liberty Utilities (West)’s electric distribution utility. 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, 2012, net earnings attributable to Shareholders totalled $14.5 million as compared to $23.4 million during the same period in 2011, a decrease of $8.9 million. Net earnings per share totalled $0.09 for the year ended December 31, 2012, as compared to $0.20 during the same period in 2011.

The decrease in net earnings attributable to Shareholders for the year ended December 31, 2012 was due to $10.1 million increased depreciation and amortization expense, $2.1 million related to increased administration charges, $0.1 million due to a stronger U.S. dollar, $5.5 million in higher interest expense, $4.7 million in increased acquisition costs, $9.0 million in reduced recoveries of income tax expense (tax explanations are discussed inAPUC: Corporate and Other Expenses), $0.4 million due to a greater loss from discontinued operations, and $3.5 million in increased allocations of earnings to non-controlling interests as compared to the same period in 2011. These items were partially offset by $3.7 million increased earnings from operating facilities, $15.2 million in decreased write-downs of long lived assets, $1.6 million in increased interest, dividend and other income, and $6.0 million in increased gains from derivative instruments as compared to the same period in 2011.

During the year ended December 31, 2012, cash provided by operating activities totalled $63.0 million or $0.40 per share as compared to cash provided by operating activities of $69.7 million, or $0.60 per share during the same period in 2011. During the year ended December 31, 2012, adjusted funds from operations, a non-GAAP measure, totalled $76.9 million or $0.52 per share as compared to adjusted funds from operations of $72.7 million, or $0.62 per share during the same period in 2011. The change in adjusted funds from operations in the year ended December 31, 2012, is primarily due to reduced earnings from operations, partially offset by increased interest, dividend and other income as compared to the same period in 2011.

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.

2012 Three month results from operations

Key Selected Fourth Quarter Financial Information


	Quarter ended December 31
(millions of dollars except per share information)	2012		2011

Revenue	$	143.1	$	70.5
Adjusted EBITDA^{1, 3}		33.4		24.3
Cash provided by operating activities		16.1		1.4
Adjusted funds from operations^{1, 3}		26.9		12.7
Net earnings / (loss) attributable to Shareholders from continuing operations		6.6		(7.7	)
Net earnings / (loss) attributable to Shareholders		6.4		(8.5	)
Adjusted net earnings^{1, 3}		5.4		3.6
Dividends declared to Common Shareholders		15.5		9.5
Weighted Average number of common shares outstanding		172,474,338		130,805,502

Per share
Basic net earnings/(loss) from continuing operations	$	0.04	$	(0.06	)
Basic net earnings/(loss)	$	0.04		(0.07	)
Adjusted net earnings^{1, 2, 3}	$	0.03	$	0.03
Diluted net earnings/(loss)	$	0.04	$	(0.07	)
Cash provided by operating activities^{1, 2, ,3}	$	0.09	$	0.01
Adjusted funds from operations^{1, 2, 3}	$	0.16	$	0.10
Dividends declared to Common Shareholders	$	0.08	$	0.07

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	Non-GAAP measure - see applicable section later in this MD&A and the caution regarding non-GAAP measures on page 1.

For the three months ended December 31, 2012, APUC experienced an average U.S. exchange rate of approximately $0.991 as compared to $1.023 in the same period in 2011. 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, 2012, APUC reported total revenue of $143.1 million as compared to $70.5 million during the same period in 2011, an increase of $72.6 million. The major factors resulting in the increase in APUC revenue in the three months ended December 31, 2012 as compared to the corresponding period in 2011 are set out as follows:


	Quarter ended December 31, 2012
	(Millions)

Comparative Prior Period Revenue	$	70.5

Significant Changes:
Liberty Utilities:
West – Lower electricity sales to customers		(1.3	)
Central – Revenue increase due to Midwest Gas Utilities acquisitions		20.7
East – Gas and electricity revenue due to EnergyNorth Gas Utility and Granite State Electric Utility acquisitions		55.6

APCo:
Renewable
Effect of hydrology resource compared to comparable period in prior year		(1.2	)
Acquisition of Sandy Ridge, Minonk, and Senate Wind Facilities		3.2
St Leon Wind Facility – effect of lower wind resource compared to comparable period in prior year		(1.6	)
St Leon II Wind Facility– Revenue increase from expansion		0.9
Thermal
Windsor Locks Thermal Facility – Lower power demand and rates		(0.8	)
Energy-from-Waste Facility – Lower price per tonne for supplemental waste		(1.5	)
Impact of the weaker U.S. dollar		(2.1	)
Other		0.7


Current Period Revenue	$	143.1

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

Adjusted EBITDA in the three months ended December 31, 2012 totalled $33.4 million as compared to $24.3 million during the same period in 2011, an increase of $9.1 million or 37%.

The increase in Adjusted EBITDA was primarily due to increased revenues from EnergyNorth Gas Utility, Granite State Electric Utility, Midwest Gas Utilities, and the U.S. Wind Project acquisitions, and increased demand at the Liberty Utilities (West)’s electric distribution utility. These items were partially offset by lower results from operations primarily from increased energy costs for APCO’s energy sales group, lower revenues from APCo’s EFW facility due to the expiry of the Region of Peel contract, and reduced wind resources at APCo’s St Leon facility. 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, 2012, net income attributable to Shareholders totalled $6.4 million as compared to net loss attributable to Shareholders of $8.5 million during the same period in 2011, an increase of $14.9 million. Net income per share totalled $0.04 for the three months ended December 31, 2012, as compared to net loss per share of $0.07 during the same period in 2011.

The increase in net earnings attributable to Shareholders for the quarter ended December 31, 2012 was due to $10.0 million increased earnings from operating facilities, $15.2 million in decreased write-downs of long lived assets, $2.0 million due to a stronger U.S. dollar, $1.1 million in increased interest, dividend and other income, $2.0 million in increased gains from derivative instruments, $0.7 million in reduced losses from discontinued operations and $0.5 million in increased recoveries of income tax expense (tax explanations are discussed inAPUC: Corporate and Other Expenses)as compared to the same period in 2011. These items were partially offset by $6.5 million increased depreciation and amortization expense, $0.5 million related to increased administration charges, $3.7 million in higher interest expense, $0.1 million in increased acquisition costs, and $5.8 million in increased allocations of earnings to non-controlling interests as compared to the same period in 2011.

During the three months ended December 31, 2012, cash provided by operating activities totalled $16.1 million or $0.09 per share as compared to cash provided by operating activities of $1.4 million, or $0.01 per share during the same period in 2011. During the three months ended December 31, 2012, adjusted funds from operations totalled $26.9 million or $0.16 per share as compared to adjusted funds from operations of $12.7 million, or $0.10 per share during the same period in 2011. The change in adjusted funds from operations in the three months ended December 31, 2012, is primarily due to decreased earnings from operations, partially offset by increased interest, dividend and other income as compared to the same period in 2011.

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.

Outlook

Overall APUC expects operational results for power generation in the first quarter of 2013 to reflect long-term average resource conditions for hydroelectric and wind power generation.

APUC expects continuing modest customer growth throughout its regulated utilities service territories in 2013 and that utility operations will meet APUC’s expectations for the first quarter of 2013.

As a result of several acquisitions concluded by APUC over the past 9 months, the Company’s results in the first quarter of 2013 is expected to show growth compared to the first quarter of 2012. APUC’s results will reflect several acquisitions which have now closed but were not part of APUC’s operations in the first quarter of 2012. These acquisitions include the Shady Oaks Wind Facility and the Gamesa Wind Facilities, the Pine Bluff Water Utility, the Midwest Gas Utilities, EnergyNorth Gas Utility and Granite State Electric Utility.

LOGO

APCo: Renewable Energy Division


			Three months ended December 31								Year ended December 31
	Long Term Average Resource		2012			2011			Long Term Average Resource		2012			2011
Performance (GW-hrs sold)
Hydro Facilities:
Quebec Region		73.8		70.0			79.3			279.7		263.4			304.4
Ontario Region		31.9		6.9			28.8			133.7		95.6			121.1
Western Region		12.6		11.5			11.8			65.0		64.4			65.5
Maritime Region		33.6		24.1			40.2			125.8		112.9			183.0

		151.9		112.5			160.1			604.2		536.3			674.0

Wind Facilities:
Manitoba Region		121.4		106.6			119.7			424.0		405.0			383.8
Saskatchewan Region¹		23.7		20.7			27.7			88.4		82.8			68.0
Pennsylvania Region²		43.6		34.8			—			72.5		55.9			—
Illinois Region³		47.1		46.8			—			47.1		46.8			—
Texas Region³		33.8		34.0			—			33.8		34.0			—


		269.6		242.9			147.4			665.8		624.5			451.8


Total		421.5		355.4			307.5			1,270.0		1,160.8			1,125.8


			(millions)			(millions)					(millions)			(millions)

Revenue⁴
Energy sales			$	21.5		$	22.3				$	84.2		$	81.6
Less:
Cost of Sales – Energy⁵				(1.7	)		(0.7	)				(8.9	)		(3.8	)

Net Energy Sales			$	19.8		$	21.6				$	75.3		$	77.8

Other Revenue				0.8			0.3					1.9			2.3

Total Net Revenue			$	20.6		$	21.9				$	77.2		$	80.1

Expenses
Operating expenses				(5.4	)		(6.7	)				(21.4	)		(21.6	)
Interest and Other income				0.5			0.6					2.0			2.1


Division operating profit			$	15.7		$	15.8				$	57.8		$	60.6

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. The prior year actual production in the Saskatchewan Region reflects production since Red Lily I achieved commercial operation on February 23, 2011. The long term average resource reflects three and twelve months of production.

²	Represents the operations of Sandy Ridge Wind Facility which was acquired on July 1, 2012.

³	Represents the operations of Minonk and Senate Wind Facilities in the states of Illinois and Texas, respectively which was acquired on December 10, 2012.

⁴

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.

⁵	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.

2012 Annual Operating Results

Production data, revenue and expenses have been adjusted to remove the results of the New York and New England regional assets which are now disclosed as discontinued operations. See Financial Statement note 18 for details.

For the year ended December 31, 2012, the Renewable Energy Division produced 1,160.8 GW-hrs of electricity, as compared to 1,125.8 GW-hrs produced in the same period in 2011, an increase of 3%. The increased generation is primarily due to additional wind production in Canada from the expansion of St. Leon and the addition of the Gamesa Wind Facilities, partially offset by reduced hydrology and wind resource in 2012 as compared to the comparable period in 2011. The level of production in 2012 represents sufficient renewable energy to supply the equivalent of 64,500 homes on an annualized basis with renewable power. Using new standards of thermal generation, as a result of renewable energy production, the equivalent of 640,000 tons of CO₂ gas was prevented from entering the atmosphere in the year ended December 31, 2012.

During the year ended December 31, 2012, the Renewable Energy Division generated electricity equal to 91% of long-term projected average resources (wind and hydrology) as compared to 107% during the same period in 2011. For the year ended December 31, 2012, the new Texas region experienced resources higher than long-term averages resources, whereas the Quebec, Western, Maritimes, Manitoba, Saskatchewan regions and the new Illinois region experienced below long-term averages resources, with energy production consistent with resources between 1%-10% below long-term average resources. The Ontario and Pennsylvania regions experienced results between 23%-29% below long-term average resources. The Ontario region’s lower production was primarily due to an unplanned shutdown at the Long Sault facility.

For the year ended December 31, 2012, revenue from energy sales in the Renewable Energy Division totalled $84.2 million, as compared to $81.6 million during the same period in 2011. As the purchase of energy by the Energy Services Business is a significant revenue driver and component of variable operating expenses, the division compares ‘net energy sales’ (energy sales revenue less energy purchases) as a more appropriate measure of the division’s sales results. For the year ended December 31, 2012, net revenue from energy sales in the Renewable Energy Division totalled $75.3 million, as compared $77.8 million during the same period in 2011.

Revenue generated from APCo’s hydro facilities located in the Quebec and Western regions decreased by $3.6 million primarily due to $5.1 million in lower hydrology and partially offset by $1.5 million due to an increase in weighted average energy rates, as compared to the same period in 2011. Revenue from lost production due to the unplanned shutdown in Ontario was covered by business interruption insurance claim proceeds in the amount of $1.8 million. Revenue from APCo’s hydro facility located in the Maritime region decreased by 10% primarily driven by a $1.8 million in decreased customer demand offset by a $1.5 million increase in weighted average energy rates as compared to the same period in 2011.

Revenue from APCo’s wind facilities located in the Manitoba region increased $0.7 million primarily due to the expansion of the St. Leon facility offset by a lower than average wind resource. APCo’s wind facilities located in the new Pennsylvania, Texas, and Illinois regions, which were acquired in late 2012, produced revenue of $3.9 million.

Revenue at the Energy Services Business increased 24% due to $6.4 million of increased customer demand, partially offset by a $3.2 million decrease in weighted average energy rates. Revenue at the Energy Services Business primarily consists of wholesale deliveries to local electric utilities, retail sales to commercial and industrial customers in Northern Maine, and merchant sales of production in excess of customer demand at the Tinker hydroelectric generating facility.

For the year ended December 31, 2012, energy purchase costs by the Energy Services Business totalled $8.9 million as compared to $3.8 million during the same period in 2011, an increase of $5.1 million. During this period, the Energy Services Business purchased approximately 140.7 GW-hrs of energy at market and fixed rates averaging U.S. $63 per MW-hr. The Maritime region generated approximately 43% of the load required to service its customers as well as the customers of the Energy Services Business in the year ended December 31, 2012, as compared to 80% in the same period in 2011. The lower production from the Maritime region was the primary driver for the increased energy purchase costs for the year ended December 31, 2012. The division reported increased energy purchase costs of $0.1 million as a result of the stronger U.S. dollar as compared to the same period in 2011.

The Red Lily I wind farm located in Saskatchewan produced 82.8 GW-hrs of electricity for the year ended December 31, 2012. 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 revenues from energy sales. Under the terms of the agreements, APCo has the right to exchange these contractual and debt interests in Red Lily I for a direct 75% equity interest in 2016. For the year ended December 31, 2012, APCo earned fees and interest payments from Red Lily I in the total amount of $3.2 million.

The Renewable Energy Division reported increased revenue of $0.2 million from U.S. operations as a result of the stronger U.S. dollar as compared to the same period in 2011.

For the year ended December 31, 2012, operating expenses excluding energy purchases totalled $21.4 million, as compared to $21.6 million during the same period in 2011, a decrease of $0.2 million or 1%. The decrease was primarily impacted by $1.8 million in lower operating costs at the hydro facilities due to lower flows and related direct production costs, and $0.3M in lower personnel costs at the Energy Services Business. These items were partially offset by a $0.5 million accrual for costs related to the Quebec water lease proceedings and by $1.4 million in operating costs related to the U.S. Wind Project acquisitions and other business development initiatives such as the Cornwall Solar development.

For the year ended December 31, 2012, interest and other income totalled $2.0 million, consistent with the same period in 2011. Interest and other income primarily consists of interest related to the senior and subordinated debt interest in the Red Lily I wind project. This amount is included as part of APCo’s earnings from its investment in Red Lily I, as discussed above.

For the year ended December 31, 2012, the Renewable Energy Division’s operating profit totalled $57.8 million, as compared to $60.6 million during the same period of 2011, representing a decrease of $2.8 million or 5%.

2012 Fourth Quarter Operating Results

For the quarter ended December 31, 2012, the Renewable Energy Division produced 355.4 GW-hrs of electricity, as compared to 307.5 GW-hrs produced in the same period in 2011, an increase of 16%. The increased generation is primarily due to the acquisition of Sandy Ridge, Minonk and Senate Wind Facilities. This level of production represents sufficient renewable energy to supply the equivalent of 79,000 homes on an annualized basis with renewable power. Using new standards of thermal generation, as a result of renewable energy production, the equivalent of 195,500 tons of CO2 gas was prevented from entering the atmosphere in the fourth quarter of 2012.

During the quarter ended December 31, 2012, the division generated electricity equal to 84% of long-term projected average resources (wind and hydrology) as compared to 109% during the same period in 2011. In the fourth quarter of 2012, the new Texas region experienced resources slightly higher than long-term averages resources, whereas the new Illinois region as well as the Western, and Quebec regions experienced resources slightly lower than long-term averages resources, producing 1-9% below long-term average resources. The Manitoba, Saskatchewan and Pennsylvania regions produced 12-20% below long-term averages resources. The Ontario and Maritimes regions produced well below long-term averages resources, primarily due to the unplanned outage at the Long Sault Facility.

For the quarter ended December 31, 2012, revenue from energy sales in the Renewable Energy Division totalled $21.5 million, as compared to $22.3 million during the same period in 2011. As the purchase of energy by the Energy Services Business is a significant revenue driver and component of variable operating expenses, the division compares ‘net energy sales’ (energy sales revenue less energy purchases) as a more appropriate measure of the division’s sales results. For the quarter ended December 31, 2012, net revenue from energy sales in the Renewable Energy Division totalled $19.8 million, as compared $21.6 million during the same period in 2011.

Revenue generated from APCo’s hydro facilities located in the Ontario, Quebec and Western regions decreased by $1.1 million due to a $1.3 million overall decrease in hydrology, primarily in the Ontario and Quebec regions, offset partially by a $0.2 million increase in weighted average energy rates as compared to the same period in 2011. Lost production from the unplanned shutdown in Ontario was covered by business interruption insurance claim proceeds in the amount of $1.8 million. Revenue from APCo’s hydro facility located in the Maritime region decreased primarily due to a $0.5 million decrease in customer demand, partially offset by a $0.2 million increase in weighted average energy rates as compared to the same period in 2011.

Revenue from APCo’s wind facilities located in the Manitoba region decreased $0.7 million primarily due to lower than normal wind resource, decreased weighted average energy rates realized on production in excess of contracted dependable volumes partially offset by an increase in production from the expansion of the facility. Revenue from APCo’s wind facilities located in the new Pennsylvania, Texas, and Illinois regions which accounts for Sandy Ridge, Minonk and Senate Wind Facilities, the three U.S. Wind Project interests acquired in 2012, produced revenue of $3.2 million.

Revenue at AES increased 5% primarily due to $0.5 million of increased customer demand, partially offset by a $0.4 million decrease in weighted average energy rates. 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 customer demand at the Tinker Facility and other revenue.

For the quarter ended December 31, 2012, energy purchase costs by AES totalled $1.7 million as compared to $0.7 million during the same period in 2011, an increase of $1.0 million. During this period, AES purchased approximately 22.1 GW-hrs of energy at market and fixed rates averaging U.S. $76 per MW-hr. During the quarter, the Maritime region generated approximately 52% of the load required to service its customers as well as AES’ customers, as compared to 70% in the same period in 2011. The lower production from the Maritime region was a result of a planned shutdown to implement various equipment upgrades. This planned shutdown and resultant lower production was the primary driver for AES’ increased energy purchase costs for the quarter

ended December 31, 2012. The division reported decreased energy purchase costs of $0.1 million as a result of the weaker U.S. dollar as compared to the same period in 2011.

The division reported decreased revenue of $0.2 million from U.S. operations as a result of the weaker U.S. dollar as compared to the same period in 2011.

The Red Lily I wind farm located in Saskatchewan produced 20.7 GW-hrs of electricity for the quarter ended December 31, 2012. 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 revenues from energy sales. Under the terms of the agreements, APCo has the right to exchange these contractual and debt interests in Red Lily for a direct 75% equity interest in 2016. For the quarter ended December 31, 2012, APCo earned fees and interest payments from Red Lily in the total amount of $0.9 million.

For the quarter ended December 31, 2012, operating expenses excluding energy purchases totalled $5.4 million, as compared to $6.7 million during the same period in 2011, a decrease of $1.3 million or 19%. The decrease was primarily impacted by a $1.0 million decrease in costs in the Ontario region as a result of the unplanned shut down of the Long Sault facility, as compared to the same period in 2011.

For the quarter ended December 31, 2012, interest and other income totalled $0.5 million, consistent with the same period in 2011. Interest and other income primarily consist of interest related to the senior and subordinated debt interest in the Red Lily I project. This amount is included as part of APCo’s earnings from its investment in Red Lily I, as discussed above.

For the quarter ended December 31, 2012, the Renewable Energy Division’s operating profit totalled $15.7 million, as compared to $15.8 million during the same period in 2011, representing a decrease of $0.1 million or 1%.

APCo: Thermal Energy Division


	Three months ended December 31						Year ended December 31
	2012			2011			2012			2011

Performance (GW-hrs sold)		80.5			126.5			330.5			517.0
Performance (‘000 tonnes of waste processed)		36.6			42.1			163.8			166.8
Performance (steam sales – billion lbs)		342.2			308.4			1,305.6			1,209.4

	(millions)			(millions)			(millions)			(millions)

Revenue
Energy/steam sales	$	11.3		$	10.6		$	36.9		$	46.7
Less:
Cost of Sales – Fuel¹		(4.4	)		(7.8	)		(14.6	)		(24.6	)

Net Energy/Steam Sales Revenue	$	6.9		$	2.8		$	22.3		$	22.1

Waste disposal sales		2.7			4.0			14.3			16.4
Other revenue		0.6			0.5			1.7			1.4

Total net revenue	$	10.2		$	7.3		$	38.3		$	39.9
Expenses
Operating expenses¹		(5.2	)		(3.3	)		(21.1	)		(19.9	)
Interest and other income		(0.3	)		(0.1	)		0.5			—


Division operating profit	$	5.3		$	3.9		$	17.7		$	20.0

¹	Cost of Sales - Fuel consists of natural gas and fuel costs at the Sanger and Windsor Locks facilities.

APCo’s Sanger and Windsor Locks 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.

2012 Annual Operating Results

For the year ended December 31, 2012, the Thermal Energy Division produced 330.5 GW-hrs of energy as compared to 517.0 GW-hrs of energy in the comparable period of 2011, primarily due to the planned outages at the Sanger and Windsor Locks facilities. During the year ended December 31, 2012, the business unit’s total production decreased by 157.0 GW-hrs at the Windsor Locks facility and by 31.8 GW-hrs from the Sanger facility, as compared to the same period in 2011.

For the year ended December 31, 2012, the Energy-from-Waste (“EFW”) facility processed approximately 163,800 tonnes of municipal solid waste as compared to 166,800 tonnes of municipal solid waste in the same period of 2011. The current level of production resulted in the diversion of approximately 127,200 tonnes of waste from municipal solid waste landfill sites in the twelve months of 2012.

For the year ended December 31, 2012, the Brampton Cogeneration Inc. (“BCI”) and Windsor Locks facilities sold 1,305.6 billion lbs of steam as compared to 1,209.4 billion lbs of steam in the comparable period of 2011. During the year ended December 31, 2012, operations at the EFW facility generated 489 billion lbs of steam for the BCI facility as compared to 507 billion lbs of steam in the same period in 2011.

For the year ended December 31, 2012, energy / steam revenue in the Thermal Energy Division totalled $36.9 million, as compared to $46.7 million during the same period in 2011, a decrease of $9.8 million, or 21%. The decreased revenue from energy / steam sales as compared to the same period in 2011, was primarily due to a decrease in revenue of $7.9 million from lower production at the Windsor Locks facility as a result of a planned shutdown in the second quarter of 2012 to install the new Solar Titan combustion gas turbine, and a decrease of $1.9 million in lower production at the Sanger facility as a result of being offline for a planned shutdown commencing in January 2012.

As natural gas expense is a significant revenue driver and component of operating expenses, the division compares ‘net energy sales revenue’ (energy sales revenue less natural gas expense) as an appropriate measure of the division’s results. For the year ended December 31, 2012, net energy / steam sales revenue at the Thermal Energy Division totalled $22.3 million, as compared to $22.1 million during the same period in 2011, an increase of $0.2 million. The increase is primarily due to lower gas costs as a result of increased operating efficiency and appropriate scale of the new Titan turbine installed at the Windsor Locks facility in 2012, partially offset by the Sanger facility being offline from January to April 2012 and the Windsor Locks facility being offline for a large part of the second quarter of 2012, and a $1.8 million reclassification from operating expenses into cost of sales – fuel in 2011 related to the KMS and Peel facilities.

For the year ended December 31, 2012, fuel costs at Sanger and Windsor Locks totalled $14.6 million, as compared with $24.6 million in the same period in 2011, a decrease of $10.0 million. The overall natural gas expense at the Windsor Locks facility decreased $6.6 million or 36%, primarily due to a 37% decrease in volume of natural gas consumed, partially offset by a 1% increase in the average landed cost of natural gas per MMBTU as compared to the same period in 2011. The average landed cost of natural gas at the Windsor Locks facility during the year ended December 31, 2012 was $4.91 per MMBTU. Natural gas expense at Sanger decreased $1.9 million or 39%, primarily the result of a 22% decrease in the volume of natural gas consumed in addition to a 22% decrease in the average landed cost of natural gas per MMBTU as compared to the same period in 2011. The average landed cost of natural gas at the Sanger facility during the year ended December 31, 2012 was U.S. $3.45 per MMBTU. A portion of the decrease in gas costs is attributable to a $1.8 million reclassification from operating expenses into cost of sales – fuel in 2011 related to the KMS and Peel facilities. The division reported increased fuel costs of $0.3 million as a result of the stronger U.S. dollar as compared to the same period in 2011.

Revenue from waste disposal sales for the year ended December 31, 2012 totalled $14.3 million, as compared to $16.4 million during the same period in 2011, a decline of $2.1 million or 13%. Revenue declined as the result of a greater level of supplemental waste processed by the facility for which lower average rates are charged pursuant to the existing waste disposal contract and the contract with the region of Peel expiring in October of 2012.

For the year ended December 31, 2012, operating expenses, excluding fuel costs at EFW, Windsor Locks and Sanger, totalled $21.1 million, as compared to $19.9 million during the same period in 2011, an increase of $1.2 million. The increase in operating expenses was primarily impacted by a $1.8 million reclassification from operating expenses into cost of sales – fuel in 2011 related to the KMS and Peel facilities offset by lower expenses of $0.3 million at the EFW facility, primarily related to lower gas and maintenance costs, and lower expenses of $0.2 million due to planned shutdowns of the Sanger and Windsor Locks facilities for portions of the twelve months of 2012.

For the year ended December 31, 2012, the Thermal Energy Division’s operating profit totalled $17.7 million, as compared to $20.0 million during the same period in 2011, representing a decrease of $2.3 million or 12%.

2012 Fourth Quarter Operating Results

For the quarter ended December 31, 2012, the Thermal Energy Division produced 80.5 GW-hrs of energy as compared to 126.5 GW-hrs of energy in the comparable period of 2011. The decrease in energy production

was due primarily to the installation of the new Titan turbine which is a smaller, more efficient turbine, sized to optimize the energy and steam requirements of the steam host compared to the larger, less efficient Frame 6 turbine that was operating the previous year.

The EFW facility processed approximately 36,600 tonnes of municipal solid waste in the quarter as compared to 42,100 tonnes of municipal solid waste in the same period of 2011. The current level of production resulted in the diversion of approximately 32,600 tonnes of waste from municipal solid waste landfill sites in the fourth quarter of 2012.

For the quarter ended December 31, 2012, the BCI and Windsor Locks facilities sold 342.2 billion lbs of steam as compared to 308.4 billion lbs of steam in the comparable period of 2011. During the quarter ended December 31, 2012, operations at the EFW facility generated 103.5 billion lbs of steam for the BCI facility as compared to 129.0 billion lbs of steam in the same period in 2011.

For the quarter ended December 31, 2012, energy / steam revenue in the Thermal Energy Division totalled $11.3 million, as compared to $10.6 million during the same period in 2011, an increase of $0.7 million, or 7%. As natural gas expense is a significant revenue driver and component of operating expenses, the division compares ‘net energy sales revenue’ (energy sales revenue less natural gas expense) as an appropriate measure of the division’s results. For the quarter ended December 31, 2012, net energy / steam sales revenue at the Thermal Energy Division totalled $6.9 million, as compared to $2.8 million during the same period in 2011, an increase of $4.1 million. The increase is primarily attributed to lower fuel costs at Windsor Locks as a result of the installation of the new Titan Turbine and a $1.8 million reclassification from operating expenses into cost of sales – fuel in 2011 related to the KMS and Peel facilities.

Revenue from energy / steam sales increased by $0.7 million as a result of $2.4 million in higher rates at the Windsor Locks facility as compared to the same period in 2011 and increased production volumes of 3% at the Sanger facility, offset by a decrease of $3.2 million in production at Windsor Locks and a 1% decrease in billing rates at Sanger.

For the quarter ended December 31, 2012, fuel costs at Sanger and Windsor Locks totalled $4.4 million, as compared with $6.0 million (net of the $1.8 million reclassification) in the same period in 2011, a decrease of $1.6 million. The overall natural gas expense at the Windsor Locks facility decreased $1.1 million or 25%, primarily the result of a 43% decrease in volume of natural gas consumed, offset by a 32% increase in the average landed cost of natural gas per MMBTU as compared to the same period in 2011. The average landed cost of natural gas at the Windsor Locks facility during the quarter was $6.29 per MMBTU. Natural gas expense at Sanger increased 3%, primarily the result of a 0.2% decrease in the average landed cost of natural gas per MMBTU offset by a 3% increase in the volume of natural gas consumed as compared to the same period in 2011. The average landed cost of natural gas at the Sanger facility during the quarter was U.S. $4.02 per MMBTU. The division reported decreased fuel costs of $0.2 million as a result of the weaker U.S. dollar as compared to the same period in 2011.

Revenue from waste disposal sales at the EFW facility for the quarter ended December 31, 2012 totalled $2.7 million as compared to $4.0 million during the same period in 2011, primarily due to the expiration of the Region of Peel contract.

For the quarter ended December 31, 2012, operating expenses, excluding fuel costs at Windsor Locks and Sanger, totalled $5.2 million as compared to $3.3 million during the same period in 2011, an increase of $1.9 million, primarily as a result of a $1.8 million reclassification from operating expenses into cost of sales – fuel in 2011 related to the KMS and Peel facilities.

For the quarter ended December 31, 2012, the Thermal Energy Division’s operating profit totalled $5.3 million, as compared to $3.9 million during the same period in 2011.

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	PPATerm		Production GW-hrs
Chaplin Wind¹	Saskatchewan		177	$	355.0	2016		25		720.0
Amherst Island²	Ontario		75	$	230.0	2015		20		247.0
Val Eo¹	Quebec		24	$	70.0	2015		20		66.0
Morse Wind^{3, 4}	Saskatchewan		25	$	70.0	2014		20		93.0
St. Damase¹	Quebec		24	$	66.0	2014		20		78.7
Cornwall Solar^{1, 2}	Ontario		10	$	45.0	2013		20		13.4


Total			335	$	836.0					1,218.1

Notes:

1	PPA signed

2	FIT contract awarded

3	Two 10 MW PPAs; one 5 MW 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”).

Chaplin Wind

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, 200 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 $355 million and consist of approximately 77 multi-megawatt wind turbines. The project is expected to generate first full year EBITDA of $37.5 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.

Amherst Island Wind

The Amherst Island wind project is located on Amherst Island in the village of Stella, approximately 25 kilometres southwest of Kingston, Ontario. In February 2011, the 75 MW project was awarded a feed-in tariff (“FIT”) contract by the OPA as part of the second round of the OPA’s FIT program.

The FIT contract originally stated that the OPA had the option to terminate the FIT contract prior to the date that the OPA had issued a Notice to Proceed (“NTP”) and APCo had paid the incremental security required by the NTP. On August 2, 2011, the Ontario Ministry of Energy directed the OPA to offer FIT contract holders the opportunity to have the OPA’s termination rights under the FIT contract waived. APCo exercised this option on August 9, 2011. As required by the waiver, APCo submitted a domestic content plan on October 14, 2011 and provided a statutory declaration regarding equipment supply commitments by November 30, 2011.

The Amherst Island wind project is currently contemplated to use efficient 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 final open-house for public consultation was conducted on March 5^th and 6^th, 2013. The submission of the Renewable Energy Approval application subsequent to the open house is targeted for April 2013. Construction will commence shortly following the approval of the application and is expected to take 12 to 18 months.

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.

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 two 10 MW projects were awarded in May 2010 and the 5 MW project was awarded in June 2011. The execution of the PPA pursuant to this program is expected to take place concurrently with the execution of the Interconnection Agreement in late March of 2013. The Environmental Impact Assessment was submitted for the project in mid-2012 and as a result the project was deemed “not a development”. This allows the project to proceed towards the construction phase without the requirement for a full Environmental Assessment. The expected date of operation for the projects is in early 2015.

The total annual energy production for the Morse wind project is estimated to be 93,000 MW-hrs. The capital cost to construct the Morse wind project is currently estimated to be between $65 million and $70 million, inclusive of acquisition costs. The first year PPA rate is set at $101.98 per MW-hr for the first full year of operations, which APCo expects to occur in 2014, with an annual escalation provision of 2% over the expected 20 year term.

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.

1. 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 la Matapédia. The project proponents include the Municipality of Saint-Damase and APCo. At the request of the turbine manufacturer, the project has recently gone through a turbine model change, changing from the originally proposed 8 wind turbines (E-101) of 3 MW each to 10 wind turbines (E-92) of 2.35 MW each. The annual energy production is estimated at 78,700 MW-hrs with a total installed capacity of 23.5 MW for the first phase. The second phase of the project would entail the development of an additional 106 MW’s. The permitting and the environmental impact assessment are ongoing and the construction of the first project phase is to begin in the fall of 2013. Commercial operations are expected to commence in late 2014.

APCo’s interest in the project will not be less than 50%. Final funding of the project will be arranged and announced when all required permitting has been met, and all other pre-construction conditions have been satisfied. Preliminary permitting began in early 2011 and community consultations were conducted in July 2011, March 2012 and September 2012. The project’s social acceptance is strong and there will be no requirement for a public hearing under the auspices of the BAPE. The environmental impact assessment for the project has also been submitted and is under review with provincial ministerial approval anticipated for the third quarter of 2013.

2. Val-Éo

Phase one of the Val-Éo wind project is located in the local municipality of Saint-Gideon de Grandson, 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 66,000 MW-hr annually. Construction of the first 24 MW phase of the project is expected to begin in the fall of 2014 with commercial operations commencing in late 2015. The second phase of the project would entail the development of an additional 106 MW’s.

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 25%. Final funding of the project will be arranged and announced when all required permitting has been secured, and all other pre-construction conditions have been satisfied. Preliminary permitting began in early 2011 and studies of flora and fauna and the public consultation process are ongoing. The submission of the environmental impact study to the Minister of Sustainable Development, Environment, Wildlife and Parks is targeted for the second quarter of 2013.

Cornwall Solar

In the first quarter of 2012, APCo acquired all of the issued and outstanding shares of Cornwall Solar Inc. (“Cornwall Solar”), which owns the rights to develop a 10 MWac solar project located near Cornwall, Ontario (the “Cornwall Project”). In addition to the Cornwall Project, APCo has acquired an option to acquire ten additional Ontario based solar projects. APCo has submitted FIT applications for an additional 100MWac.

The Cornwall Project has been granted an Ontario 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 project received its Renewable Energy Approval on January 15^th, 2013, and construction of the project is expected to begin in the second quarter of 2013. The project’s environmental assessment has now been deemed “administratively complete”. Commercial operation is estimated in late 2013 with expected annual generation of approximately 13,400 MW-hrs.

Total capital cost of the project is targeted at approximately $45 million, including the consideration to be paid for the acquisition of the project. Funding for the project will be arranged and announced when all required permitting and all other pre-construction conditions have been satisfied.

APCo Outlook

The APCo Renewable Energy Division is expected to perform based on long-term average resource conditions for both wind and hydrology in the first quarter of 2013. In October 2012, APCo’s hydroelectric generating facility at Long Sault experienced an unplanned shut down. The facility is expected to return to full service in the second quarter of 2013. New York and New England facilities are expected to perform at similar levels as the previous year. The acquisitions of an interest in the Sandy Ridge Wind Facility (on July 1, 2012), the Minonk and Senate Wind Facilities (on December 10, 2012), and the Shady Oaks Wind Facility (on January 1, 2013) are recently acquired wind powered generating stations that will generate additional revenue in 2013.

Unlike 2012, there are no planned outages in 2013 for the Thermal Energy Division. After installation of the new Solar Titan combustion gas turbine in the third quarter of 2012, the Windsor Locks facility is better able to match production with demand from its industrial host under a PPA, limiting its exposure to the more volatile market power pricing in New England. In October 2012, the EFW facility received approval from the Ontario Ministry of Environment for an amendment to its environmental permits allowing the EFW facility to accept municipal, industrial, commercial and institutional waste from anywhere in Ontario. APCo has now entered into several waste supply agreements to ensure continued operation of the facility following the end of the Region of Peel waste supply contract in 2012.

LOGO

Liberty Utilities is a national diversified rate regulated utility providing electricity, natural gas, water distribution and wastewater collection utility services. Liberty Utilities’ strategy is to grow its business organically and through business development activities while using prudent acquisition criteria. The business will focus on driving maximum results by building constructive regulatory and customer relationships, and enhancing community connections.


Utility System Type	December 31, 2012				December 31, 2011
	Assets		Connections		Assets		Connections
	U.S. $				U.S. $
	(millions)				(millions)
Electricity	$	254.3		90,205	$	155.8		46,906
Natural Gas		394.8		169,700		—		—
Water and Wastewater		205.4		78,050		203.4		76,100

	$	854.5		337,955	$	359.2		123,006

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

The Liberty Utilities (West) region is currently comprised of regulated electrical and water distribution and wastewater collection utility systems. The regulated electrical distribution utility serves approximately 46,955 active electric connections in the State of California. The Liberty Utilities (West) region’s regulated water and

wastewater utility systems serve approximately 66,550 water and wastewater connections located in the State of Arizona. These utilities systems, previously reported in the Liberty Utilities (South) region, have now been combined with Liberty Utilities (West) for reporting purposes, effective July 1, 2012.

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 82,050 active natural gas connections located in the states of Missouri, Illinois, and Iowa and the regulated water distribution and wastewater collection utilities serve approximately 11,500 water and wastewater customers located in the states of Illinois, Missouri, and Texas.

Liberty Utilities (East) region is comprised of regulated natural gas and electric distribution utility systems located in the State of New Hampshire which provides regulated local electrical utility services to approximately 43,250 active electric connections; and regulated local gas distribution utility services to approximately 87,650 active natural gas connections.

For electricity and natural gas operations, Liberty Utilities reports active connections, exclusive of vacant connections rather than total connections. For water and wastewater operations, Liberty Utilities reports total connections, inclusive of vacant connections.

Liberty Utilities: West Region


	Year ended December 31
	2012		2011
Number of Active Electric Connections
Residential		41,400		41,346
Commercial – Small		5,500		5,506
Commercial – Large		55		54
Total Active Electric Connections		46,955		46,906

Number of Water Connections
Wastewater connections		31,750		30,900
Water distribution connections		34,800		33,900
Total Water Connections		66,550		64,800

Customer Usage (GW-hrs)
Residential		273.6		291.2
Commercial – Small		149.7		173.1
Commercial – Large		121.0		136.6
Public Street and Highway Lighting		1.1		1.1
Total Customer Usage (GW-hrs)		545.4		602.0

Gallons Provided
Wastewater treated (millions of gallons)		1,650		1,710
Water sold (millions of gallons)		5,080		5,190
Total Gallons Provided		6,730		6,900

Liberty Utilities (West) is comprised of Liberty Utilities operations in California and Arizona. On December 21, 2012, Liberty Utilities (West) acquired the remaining 49.999% interest in the Calpeco Electric Utility. Therefore, as at December 31, 2012, Liberty Utilities (West) holds a 100% interest in the Calpeco Electric Utility.

Liberty Utilities (West)’s increase in water and wastewater connections during the period is primarily due to development within the service territory.

For the year ended December 31, 2012, Liberty Utilities (West)’s electricity usage totalled 545.4 GW-hrs, as compared to 602.0 GW-hrs for the same period in 2011, a decrease of 56.6 GW-hrs or 9%. This decrease in usage was primarily due to milder winter and spring weather in 2012 as compared to the colder weather experienced in the same period a year ago. Under the rate tariff approved in November 2012, and commencing on January 1, 2013, the revenues earned by the Calpeco Electric Utility will not reflect variations due to customer demand variability.

During the year ended December 31, 2012, Liberty Utilities (West) provided approximately 5.1 billion U.S. gallons of water to its customers, treated approximately 1.7 billion U.S. gallons of wastewater and sold approximately 360 million U.S. gallons of treated effluent.


	Year ended December 31						Year ended December 31
	2012			2011			2012			2011
	U.S. $			U.S. $			Can $			Can $
	(millions)			(millions)			(millions)			(millions)
Water Assets for regulatory purposes		181.3			180.3
Electricity Assets for regulatory purposes		165.9			155.8

Revenue
Utility electricity sales and distribution¹	$	72.0		$	78.1		$	71.7		$	77.4
Wastewater treatment		18.7			18.2			18.7			18.0
Water distribution		18.6			18.3			18.6			18.1
Other Revenue		0.2			—			0.2			—

Total Revenue	$	109.5		$	114.6		$	109.2		$	113.5
Less:
Cost of Sales – Electricity¹		(44.0	)		(46.9	)		(43.9	)		(46.5	)

	$	65.5		$	67.7		$	65.3		$	67.0
Expenses
Operating expenses		(35.7	)		(34.8	)		(35.6	)		(34.5	)
Other income		2.1			0.5			2.1			0.5


Divisional operating profit	$	31.9		$	33.4		$	31.8		$	33.0

¹	Represents 100% of investment in the Calpeco Electric Utility

2012 Annual Operating Results

Liberty Utilities (West) has investments in water and wastewater distribution assets for regulatory purposes of U.S. $181.3 million in the state of Arizona and electricity assets for regulatory purposes of U.S. $165.9 million in the State of California as at December 31, 2012, as compared to U.S. $180.3 million and U.S. $155.8 million, respectively as at December 31, 2011.

For the year ended December 31, 2012, Liberty Utilities (West)’s revenue totalled U.S. $109.2 million as compared to U.S. $113.5 million during the same period in 2011, a decrease of U.S. $4.3 million or 4%.

For the year ended December 31, 2012, Liberty Utilities (West)’s revenue from utility electricity sales totalled U.S. $72.0 million as compared to U.S. $78.1 million during the same period in 2011, a decrease of U.S. $6.1 million or 8%. This decrease in revenues was primarily due to milder winter and spring weather in the first half of 2012, compared with the colder winter weather experienced in the same period a year ago. The decreased utility electricity sales were primarily a result of a U.S. $6.3 million decrease due to a decrease in customer demand and partially offset by an increase of U.S. $0.2 million due to increased weighted average electricity and general rates as compared to the same period in 2011. The purchase of electricity by Liberty Utilities (West) is a significant revenue driver and component of operating expenses but these costs are effectively passed through to its customers. As a result, Liberty Utilities (West) compares ‘net utility electricity sales’ (utility electricity sales less fuel and purchased power costs) as a more appropriate measure of the division’s results. For the year ended December 31, 2012, net utility electricity sales revenues for Liberty Utilities (West) were U.S. $28.0 million, as compared to U.S. $31.2 million during the same period in 2011. Under the rate tariffs approved in November 2012, and commencing on January 1, 2013, the revenues earned by the Calpeco Electric Utility will not experience fluctuations related to variations in customer demand.

For the year ended December 31, 2012, revenue from wastewater treatment totalled U.S. $18.7 million, as compared to U.S. $18.2 million during the same period in 2011, an increase of U.S. $0.5 million or 3%.

Revenue from water distribution totalled U.S. $18.6 million, as compared to U.S. $18.3 million during the same period in 2011, an increase of U.S. $0.3 million or 2%. The twelve months of water distribution revenue was impacted by U.S. $0.1 million at the Litchfield Park (“LPSCo”) facility primarily due to the increased residential, commercial and industrial revenue and U.S. $0.2 million at the Sierra Vista facilities due to increase in connection counts and overall consumption, U.S. $0.1 million at all other Liberty Utilities (West) water utilities, offset by a $0.1 million decrease at the LPSCo facility primarily due to the decreased residential usage revenue.

For the year ended December 31, 2012, fuel and purchased power costs for Liberty Utilities (West)’s electric utility totalled U.S $44.0 million, as compared with U.S. $46.9 million for the same period in 2011. The overall electricity purchase expense decrease of U.S. $2.9 million was primarily the result of a $3.8 million decrease in the volume of electricity purchased to meet customer demand, partially offset by a U.S. $0.9 million increase in weighted average electricity rates as compared to the same period in 2011.

For the year ended December 31, 2012, operating expenses totalled U.S. $35.7 million, as compared to U.S. $34.8 million during the same period in 2011. The increase in operating expenses was due to increases in customer care expenses, increases in general and administrative expenses, and increases in bad debt expense relating to uncollectible customer accounts receivable as compared to the same period in 2011.

For the year ended December 31, 2012, Liberty Utilities (West)’s operating profit was U.S. $31.9 million as compared to U.S. $33.4 million in the same period in 2011, a decrease of U.S. $1.5 million or 4%.

Measured in Canadian dollars, for the year ended December 31, 2012, Liberty Utilities (West)’s revenue from utility electricity sales totalled $71.7 million, as compared to $77.4 million during the same period in 2011. For the year ended December 31, 2012, net utility electricity sales for Liberty Utilities (West) totalled $27.8 million, as compared to $30.9 million during the same period in 2011.

Measured in Canadian dollars, for the year ended December 31, 2012, electricity purchases for Liberty Utilities (West) totalled $43.9 million, as compared to $46.5 million in the same period in 2011.

Measured in Canadian dollars, for the year ended December 31, 2012, Liberty Utilities (West)’s revenue from water treatment and wastewater distribution totalled $37.3 million, as compared to $36.1 million during the same period in 2011.

Measured in Canadian dollars, for the year ended December 31, 2012, operating expenses totalled $35.6 million, as compared to $34.5 million during the same period in 2011.

Measured in Canadian dollars, for the year ended December 31, 2012, Liberty Utilities (West)’s operating profit totalled $31.8 million as compared to $33.0 million during the same period in 2011.


	Three months ended December 31
	2012		2011
Customer Usage (GW-hrs)
Residential		72.2		69.4
Commercial – Small		42.3		50.2
Commercial – Large		39.2		40.4
Public Street and Highway Lighting		0.3		0.2
Total Customer Usage (GW-hrs)		154.0		160.2

Gallons Provided
Wastewater treated (millions of gallons)		425		410
Water sold (millions of gallons)		1,255		1,225
Total Gallons Provided		1,680		1,635

For the three months ended December 31, 2012, Liberty Utilities (West) electricity usage totalled 154.0 GW-hrs, as compared to 160.2 GW-hrs for the same period in 2011, a decrease of 6.2 GW-hrs or 4%.

During the quarter ended December 31, 2012, Liberty Utilities (West) provided approximately 1.25 billion U.S. gallons of water to its customers, treated approximately 425 million U.S. gallons of wastewater and sold approximately 113 million U.S. gallons of treated effluent.


	Three months ended December 31						Three months ended December 31
	2012			2011			2012			2011
	U.S. $			U.S. $			Can $			Can $
	(millions)			(millions)			(millions)			(millions)
Revenue
Utility electricity sales and distribution*	$	19.5		$	20.8		$	19.3		$	21.3
Wastewater treatment		4.7			4.5			4.7			4.6
Water distribution		4.4			4.4			4.4			4.5
Other Revenue		—			—			—			—

	$	28.6		$	29.7		$	28.4		$	30.4
Less:
Cost of Sales – Electricity		(11.5	)		(13.2	)		(11.4	)		(13.5	)

	$	17.1		$	16.5		$	17.0		$	16.9
Expenses
Operating expenses		(9.3	)		(9.9	)		(9.4	)		(10.1	)
Other income		1.1			0.2			1.1			0.2


Division operating profit*	$	8.9		$	6.8		$	8.7		$	7.0

2012 Fourth Quarter Operating Results

For the three months ended December 31, 2012, Liberty Utilities (West)’s revenue totalled U.S. $28.6 million as compared to U.S. $29.7 million during the same period in 2011, a decrease of U.S. $1.1 million.

For the three months ended December 31, 2012, Liberty Utilities (West)’s revenue from utility electricity sales totalled U.S. $19.5 million as compared to U.S. $20.8 million during the same period in 2011, a decrease of U.S. $1.3 million or 6%. Revenue decreased U.S. $0.9 million due to decreased customer demand and decreased U.S. $0.4 million due to decreased weighted average electricity and general rates as compared to the same period in 2011. The purchase of electricity by Liberty Utilities (West) is a significant revenue driver and component of operating expenses but these costs are effectively passed through to its customers. As a result, Liberty Utilities (West) compares ‘net utility electricity sales’ (utility electricity sales revenue less electricity purchases) as a more appropriate measure of the division’s results. For the three months ended December 31, 2012, net utility electricity sales for Liberty Utilities (West) totalled U.S. $8.0 million, as compared to U.S. $7.6 million during the same period in 2011, an increase of U.S. $0.4 million or 5%.

For the three months ended December 31, 2012, revenue from wastewater treatment and water distribution totalled U.S. $9.1 million, as compared to U.S. $8.9 million during the same period in 2011, an increase of U.S. $0.2 million or 2%.

For the three months ended December 31, 2012, fuel and purchased power costs for Liberty Utilities (West) totalled U.S $11.5 million, as compared with U.S. $13.2 million in the same period in 2011. The decrease of U.S. $1.7 million was a result of a 4% decrease in the volume of electricity used and a 9% decrease in average cost of electricity as compared to the same period in 2011.

For the three months ended December 31, 2012, operating expenses totalled U.S. $9.3 million, as compared to U.S. $9.9 million during the same period in 2011, a decrease of U.S. $0.6 million or 6%. Operating expenses decreased due to reduced utilities and consumable expenses as compared to the same period in 2011.

For the three months ended December 31, 2012, Liberty Utilities (West)’s operating profit was U.S. $8.9 million as compared to U.S. $6.8 million in the same period in 2011, an increase of U.S. $2.1 million or 31%.

Measured in Canadian dollars, for the three months ended December 31, 2012, Liberty Utilities (West)’s revenue from utility electricity sales totalled $19.3 million, as compared to $21.3 million during the same period in 2011. For the three months ended December 31, 2012, net utility electricity sales for Liberty Utilities (West) totalled $7.9 million, as compared to $7.8 million during the same period in 2011.

Measured in Canadian dollars, for the three months ended December 31, 2012, electricity purchases for Liberty Utilities (West) totalled $11.4 million, as compared to $13.5 million in the same period in 2011.

Measured in Canadian dollars, for the three months ended December 31, 2012, Liberty Utilities (West)’s revenue from water treatment and wastewater distribution totalled $9.1 million, which was consistent with the same period in 2011.

Measured in Canadian dollars, for the three months ended December 31, 2012, operating expenses totalled $9.4 million, as compared to $10.1 million in the same period in 2011.

Measured in Canadian dollars, for the three months ended December 31, 2012, Liberty Utilities (West)’s operating profit totalled $8.7 million as compared to $7.0 million in the same period in 2011.

Liberty Utilities: Central Region


	Year ended December 31
	2012		2011
Number of Active Natural Gas Connections
Residential		72,500		—
Commercial		9,500		—
Industrial		50		—
Total Active Natural Gas Connections		82,050		—

Number of Water Connections
Wastewater connections		6,000		5,900
Water distribution connections		5,500		5,400
Total Water Connections		11,500		11,300

Customer Usage (MMBTU)
Residential		1,306,800		—
Commercial		914,150		—
Industrial		178,900		—
Total Customer Usage (MMBTU)¹		2,399,850		—

Gallons Provided
Wastewater treated (millions of gallons)		370		290
Water sold (millions of gallons)		385		410
Total Gallons Provided		755		700

¹	Represents MMBTU since August 1, 2012 acquisition date

Liberty Utilities (Central) is comprised of Liberty Utilities’ operations in Texas, Missouri, Illinois, and Iowa. Liberty Utilities (Central) acquired its natural gas distribution utilities on August 1, 2012 and accordingly there are no results for these utilities for the corresponding period in 2011.

From the acquisition date of August 1, 2012 to December 31, 2012, Liberty Utilities (Central) natural gas distribution sales totalled 2,399,850 MMBTU.

During the year ended December 31, 2012, Liberty Utilities (Central) provided approximately 385 million U.S. gallons of water to its customers, and treated approximately 370 million U.S. gallons of wastewater.


	Year ended December 31						Year ended December 31
	2012			2011			2012			2011
	U.S. $ (millions)			U.S. $ (millions)			Can $ (millions)			Can $ (millions)
Natural Gas Assets for regulatory purposes		131.4			—
Water Assets for regulatory purposes		24.1			23.1

Revenue
Utility natural gas sales and distribution¹	$	26.0		$	—		$	25.8		$	—
Wastewater treatment		5.7			5.7			5.7			5.6
Water distribution		3.4			3.3			3.4			3.2

		35.1			9.0			34.9			8.8
Less:
Cost of Sales – Natural Gas¹		(13.8	)		—			(13.6	)		—

	$	21.3		$	9.0		$	21.3		$	8.8

Expenses
Operating expenses		(13.1	)		(4.3	)		(13.1	)		(4.3	)


Divisional operating profit	$	8.2		$	4.7		$	8.2		$	4.5

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

2012 Annual Operating Results

Liberty Utilities (Central) has investments in natural gas distribution assets for regulatory purposes of U.S. $131.4 million and water distribution assets for regulatory purposes of U.S. $24.1 million as at December 31, 2012, as compared to U.S. $nil and U.S. $23.1 million, respectively as at December 31, 2011.

For the year ended December 31, 2012, Liberty Utilities (Central)’s revenue totalled U.S. $35.1 million as compared to U.S. $9.0 million during the same period in 2011, an increase of U.S. $26.1 million. The revenue increase can be primarily attributed to the addition of the natural gas distribution assets on August 1, 2012.

From the date of acquisition to December 31, 2012, Liberty Utilities (Central)’s revenue from natural gas sales and distribution totalled U.S. $26.0 million. The purchase of natural gas by Liberty Utilities (Central) 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 natural gas sales and distribution revenue’ (utility natural gas sales and distribution revenue less natural gas purchases) as a more appropriate measure of the division’s results. From the date of acquisition to December 31, 2012, net utility natural gas sales and distribution revenue for Liberty Utilities (West) totalled U.S. $12.2 million.

From the date of acquisition to December 31, 2012, natural gas purchases for Liberty Utilities (Central) totalled U.S $13.8 million.

For the year ended December 31, 2012, revenue from wastewater treatment and water distribution totalled U.S. $9.1 million, as compared to U.S. $9.0 million during the same period in 2011, an increase of U.S. $0.1 million or 1%.

For the year ended December 31, 2012, operating expenses, excluding natural gas purchases, totalled U.S. $13.1 million, as compared to U.S. $4.3 million during the same period in 2011. The increase in operating expenses can be mostly attributed to the addition of the natural gas distribution assets on August 1, 2012.

For the year ended December 31, 2012, Liberty Utilities (Central)’s operating profit was U.S. $8.2 million as compared to U.S. $4.7 million in the same period in 2011, an increase of U.S. $3.5 million or 74%.

Measured in Canadian dollars, from the date of acquisition to December 31, 2012, Liberty Utilities (Central)’s revenue from natural gas sales and distribution totalled $25.8 million. From the date of acquisition to December 31, 2012, net utility natural gas sales and distribution revenue for Liberty Utilities (Central) totalled $12.2 million.

Measured in Canadian dollars, from the date of acquisition to December 31, 2012, natural gas purchases for Liberty Utilities (Central) totalled $13.6 million.

Measured in Canadian dollars, for the year ended December 31, 2012, Liberty Utilities (Central)’s revenue from water treatment and wastewater distribution totalled $9.1 million, as compared to $8.8 million during the same period in 2011. Liberty Utilities (Central) reported a foreign exchange impact on revenue from water treatment and wastewater distribution of $0.2 million in the twelve months ended December 31, 2012 as a result of the stronger U.S. dollar as compared to the same period in 2011.

Measured in Canadian dollars, for the year ended December 31, 2012, operating expenses, excluding natural gas purchases totalled $13.1 million, as compared to $4.3 million during the same period in 2011.

Measured in Canadian dollars, for the year ended December 31, 2012, Liberty Utilities (Central)’s operating profit totalled $8.2 million as compared to $4.5 million in the same period in 2011.


	Three months ended December 31
	2012		2011
Customer Usage (MMBTU)
Residential		1,160,000		—
Commercial		709,750		—
Industrial		131,300		—
Total Customer Usage (MMBTU)		2,001,050		—

Gallons Provided
Wastewater treated (millions of gallons)		95		90
Water sold (millions of gallons)		100		75
Total Gallons Provided		195		165

For the three months ended December 31, 2012, Liberty Utilities (Central) natural gas distribution sales totalled 2,001,050 MMBTU.

During the three months ended December 31, 2012, Liberty Utilities (Central) provided approximately 100 million U.S. gallons of water to its customers, and treated approximately 95 million U.S. gallons of wastewater.


	Three months ended December 31						Three months ended December 31
	2012			2011			2012			2011
	U.S. $ (millions)			U.S. $ (millions)			Can $ (millions)			Can $ (millions)
Revenue
Utility natural gas sales and distribution	$	20.5		$	—		$	20.4		$	—
Wastewater treatment		1.5			1.5			1.4			1.5
Water distribution		0.7			0.8			0.7			0.9

		22.7			2.3			22.5			2.4
Less:
Cost of Sales – Natural Gas		(12.0	)		—			(11.9	)		—

	$	10.7		$	2.3		$	10.6		$	2.4
Expenses
Operating expenses		(6.3	)		(1.2	)		(6.3	)		(1.2	)


Division operating profit	$	4.4		$	1.1		$	4.3		$	1.2

2012 Fourth Quarter Operating Results

For the three months ended December 31, 2012, Liberty Utilities (Central)’s revenue totalled U.S. $22.7 million as compared to U.S. $2.3 million during the same period in 2011, an increase of U.S. $20.4 million. The revenue increase can be primarily attributed to the addition of the natural gas distribution assets on August 1, 2012.

For the three months ended December 31, 2012, Liberty Utilities (Central)’s revenue from natural gas sales and distribution totalled U.S. $20.5 million. The purchase of natural gas by Liberty Utilities (Central) 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 natural gas sales and distribution revenue’ (utility natural gas sales and distribution revenue less natural gas purchases) as a more appropriate measure of the division’s results. For the three months ended December 31, 2012, net utility natural gas sales and distribution revenue for Liberty Utilities (Central) totalled U.S. $8.5 million.

For the three months ended December 31, 2012, natural gas purchases for Liberty Utilities (Central) totalled U.S $12.0 million.

For the three months ended December 31, 2012, revenue from wastewater treatment and water distribution totalled U.S. $2.2 million, as compared to U.S. $2.3 million during the same period in 2011, a decrease of U.S. $0.1 million or 4%.

For the three months ended December 31, 2012, operating expenses, excluding natural gas purchases, totalled U.S. $6.3 million, as compared to U.S. $1.2 million during the same period in 2011. The increase in operating expenses can be mostly attributed to the addition of the natural gas distribution assets on August 1, 2012.

For the three months ended December 31, 2012, Liberty Utilities (Central)’s operating profit was U.S. $4.4 million as compared to U.S. $1.1 million in the same period in 2011, an increase of U.S. $3.3 million, primarily related to the acquisition of the natural gas utility.

Measured in Canadian dollars, for the three months ended December 31, 2012, Liberty Utilities (Central)’s revenue from utility natural gas sales and distribution totalled $20.4 million. Measured in Canadian dollars, for the three months ended December 31, 2012, net utility natural gas sales and distribution revenue for Liberty Utilities (Central) totalled $8.5 million.

Measured in Canadian dollars, for the three months ended December 31, 2012, natural gas purchases for Liberty Utilities (Central) totalled $11.9 million.

Measured in Canadian dollars, for the three months ended December 31, 2012, Liberty Utilities (Central)’s revenue from water treatment and wastewater distribution totalled $2.1 million, as compared to $2.4 million during the same period in 2011.

Measured in Canadian dollars, for the three months ended December 31, 2012, operating expenses, excluding natural gas purchases, totalled $6.3 million, as compared to $1.2 million during the same period in 2011.

Measured in Canadian dollars, for the three months ended December 31, 2012, Liberty Utilities (Central)’s operating profit totalled $4.3 million as compared to $1.2 million in the same period in 2011.

In the June 30, 2012 Interim MD&A, guidance was provided on the Liberty Utilities (Central)’s expected operating results over the 12 month period ending June 30, 2013. For the three months ended December 31,

2012, Midwest Gas Utilities’ EBITDA of U.S. $3.9 million did not meet the guidance EBITDA of U.S. $4.6 million. The decreased EBITDA was due primarily to lower than expected natural gas usage in the states of Missouri, Illinois, and Iowa with Central recording actual usage of 2,001,050 MMBTU compared to the guidance of 2,006,230 MMBTU. A portion of the decreased usage results from actual active natural gas connections being 82,050 compared to the guidance of 83,223 active natural gas connections a difference of 928 active connections.

The table below represents forward looking information that was provided as at August 9, 2012 and which summarizes the expected operating results for the Liberty Utilities (Central)’s gas utilities for the next two quarters:


Expected short term metrics	2013		2013
	Q1		Q2
Missouri	$	4.0	$	1.3
Illinois		2.6		0.8
Iowa		0.9		0.2

Total EBITDA (U.S.$ millions)	$	7.5	$	2.3

Customers		83,336		83,358
Normalized MMBTU		4,175,086		1,542,906

Readers are cautioned that actual results may vary from the above noted forward-looking information. Management is providing this forward looking information to allow readers to better understand the actual EBITDA of the acquired utilities as they occur in the year following acquisition, including the variation in financial performance that might be expected from quarter to quarter. Further, the forward-looking financial information does not include information for net earnings resulting from the acquisitions as it does not include information related to interest, depreciation, amortization and income taxes. Therefore, this forward-looking information may not be suitable or appropriate for other purposes other than as described herein. Management intends to report actual EBITDA results compared to this forward-looking information. Management does not intend to further update this financial information except as may be required by law.

Liberty Utilities: East Region


	From the acquisition date to December 31¹
	2012		2011

Number of Active Natural Gas Connections
Residential		76,350		—
Commercial and Industrial		11,300		—
Total Active Natural Gas Connections		87,650		—

Number of Active Electric Connections
Residential		35,450		—
Commercial and Industrial		7,800		—
Total Active Electric Connections		43,250		—

Customer Usage (GW-hrs)
Residential		143.4		—
Commercial and Industrial		331.1		—
Total Customer Usage (GW-hrs)²		474.5		—

Customer Usage (MMBTU)
Residential		1,552,200		—
Commercial and Industrial		3,176,200		—
Total Customer Usage (MMBTU)²		4,728,400		—

¹	Granite State Electric Utility and EnergyNorth Gas Utility were acquired on July 3, 2012.

²	Represents MMBTU and GW-hrs since July 3, 2012 acquisition date.

Liberty Utilities (East) is comprised of Liberty Utilities’ operations in New Hampshire. Liberty Utilities (East) acquired its natural gas and electric distribution utilities on July 3, 2012 and, accordingly, there are no results for the utilities for the corresponding period in 2011.

Liberty Utilities (East) operates a regulated natural gas utility and an electric retail distribution company, both located in New Hampshire. Liberty Utilities (East) provides regulated natural gas services to approximately 87,650 active connections and regulated electric retail distribution service to approximately 43,250 active

connections. Liberty Utilities (East) reports active connections, exclusive of vacant connections rather than total connections.

From the acquisition date of July 3, 2012 to December 31, 2012, Liberty Utilities (East)’s electricity usage totalled 474.5 GW-hrs and natural gas usage totalled 4,728,400 MMBTU.


	From the acquisition date to December 31¹					From the acquisition date to December 31¹
	2012			2011		2012			2011
	U.S. $ (millions)			U.S. $ (millions)		Can $ (millions)			Can $ (millions)
Electricity Assets for regulatory purposes		88.4			—
Natural Gas for regulatory purposes		263.4			—

Revenue
Utility electricity sales and distribution	$	36.8		$	—	$	36.7		$	—
Utility natural gas sales and distribution		50.3			—		49.9			—
Other Revenue		0.1			—		0.1			—

		87.2			—		86.7			—
Less:
Cost of Sales – Electricity		(24.4	)		—		(24.3	)		—
Cost of Sales – Natural Gas²		(24.0	)		—		(23.8	)		—

	$	38.8		$	—	$	38.6		$	—

Expenses
Operating expenses		(30.4	)		—		(30.2	)		—
Other Income		0.4					0.4


Division operating profit¹	$	8.8		$	—	$	8.8		$	—

¹	Granite State Electric Utility and EnergyNorth Gas Utility were acquired on July 3, 2012.

²	Natural Gas costs are shown net of U.S. $4.5 million regulatory authorized deferral related to an under recovery of actual gas costs.

2012 Annual Operating Results

Liberty Utilities (East) has investments in electricity assets for regulatory purposes of U.S. $88.4 million, and natural gas assets for regulatory purposes of U.S. $263.4 million as at December 31, 2012, as compared to U.S. $nil and U.S. $nil, respectively as at December 31, 2011.

From the date of acquisition to December 31, 2012, Liberty Utilities (East)’s revenue totalled U.S. $87.2 million as a result of the acquisitions of Granite State Electric Utility and EnergyNorth Gas Utility on July 3, 2012.

From the date of acquisition to December 31, 2012, Liberty Utilities (East)’s revenue from utility electricity sales totalled U.S. $36.8 million. The cost of electricity is passed through to Liberty Utilities (East)’s customers. As a result, the division compares ‘net utility electricity sales’ (revenue from electricity sales less fuel and purchased power costs) as a more appropriate measure of the division’s results. From the date of acquisition to December 31, 2012, net electricity utility sales for Liberty Utilities (East) totalled U.S. $12.4 million.

From the date of acquisition to December 31, 2012, Liberty Utilities (East)’s revenue from natural gas sales and distribution totalled U.S. $50.3 million. The cost of natural gas by Liberty Utilities (East) is passed through to Liberty Utilities (East)’s customers. As a result, the division compares ‘net utility natural gas sales and distribution revenue’ (utility natural gas sales and distribution revenue less natural gas purchases) as a more appropriate measure of the division’s results. From the date of acquisition to December 31, 2012, net utility natural gas sales and distribution revenue for Liberty Utilities (East) totalled U.S. $26.3 million.

From the date of acquisition to December 31, 2012, electricity purchases for Liberty Utilities (East) totalled U.S. $24.4 million, and natural gas purchases totalled U.S. $24.0 million.

From the date of acquisition to December 31, 2012, operating expenses, excluding electricity and natural gas purchases, totalled U.S. $30.4 million.

From the date of acquisition to December 31, 2012, Liberty Utilities (East)’s operating profit totalled U.S. $8.8 million.

Measured in Canadian dollars, from the date of acquisition to December 31, 2012, Liberty Utilities (East)’s revenue from utility electricity sales totalled $36.7 million and utility natural gas sales totalled $49.9 million. Measured in Canadian dollars, from the date of acquisition to December 31, 2012, Liberty Utilities (East)’s net utility electricity sales and distribution revenue totalled $12.4 million and net utility natural gas sales and distribution revenue totalled $26.1 million.

Measured in Canadian dollars, from the date of acquisition to December 31, 2012, Liberty Utilities (East)’s electricity purchases totalled $24.3 million, and natural gas purchases totalled $23.8 million.

Measured in Canadian dollars, from the date of acquisition to December 31, 2012, Liberty Utilities (East)’s operating expenses excluding electricity and natural gas purchases totalled $30.2 million.

Measured in Canadian dollars, from the date of acquisition to December 31, 2012, Liberty Utilities (East)’s operating profit totalled $8.8 million.


	Three months ended December 31,
	2012		2011

Customer Usage (GW-hrs)
Residential		64.1		—
Commercial and Industrial		148.0		—
Total Customer Usage (GW-hrs)		212.1		—

Customer Usage (MMBTU)
Residential		1,206,900		—
Commercial and Industrial		2,059,900		—
Total Customer Usage (MMBTU)		3,266,800		—

For the three months ended December 31, 2012, Liberty Utilities (East)’s electricity usage totalled 212.1 GW-hrs and natural gas usage totalled 3,266,800 MMBTU.


	Three months ended December 31					Three months ended December 31
	2012			2011		2012			2011
	U.S. $ (millions)			U.S. $ (millions)		Can $ (millions)			Can $ (millions)
Revenue
Utility electricity sales and distribution	$	17.7		$	—	$	17.6		$	—
Utility natural gas sales and distribution		38.1			—		37.7			—
Other Revenue		—			—		—			—

		55.8			—		55.3			—
Less:
Cost of Sales – Electricity		(12.3	)		—		(12.2	)		—
Cost of Sales – Natural Gas¹		(21.9	)		—		(21.7	)		—

	$	21.6		$	—	$	21.4		$	—

Expenses
Operating expenses		(16.5	)		—		(16.3	)		—
Other income		0.4					0.4


Division operating profit¹	$	5.5		$	—	$	5.5		$	—

¹	Natural Gas costs are shown net of U.S. $1.7 million regulatory authorized deferral related to an under recovery of actual gas costs.

2012 Fourth Quarter Operating Results

For the three months ended December 31, 2012, Liberty Utilities (East)’s revenue totalled U.S. $55.8 million.

For the three months ended December 31, 2012, Liberty Utilities (East)’s revenue from utility electricity sales totalled U.S. $17.7 million. The cost of electricity is passed through to Liberty Utilities (East)’s customers. As a result, the division compares ‘net utility electricity sales’ (revenue from electricity sales less fuel and purchased power costs) as a more appropriate measure of the division’s results. For the three months ended December 31, 2012, net electricity utility sales for Liberty Utilities (East) totalled U.S. $5.4 million.

For the three months ended December 31, 2012, Liberty Utilities (East)’s revenue from natural gas sales and distribution totalled U.S. $38.1 million. The cost of natural gas by Liberty Utilities (East) is passed through to Liberty Utilities (East)’s customers. As a result, the division compares ‘net utility natural gas sales and distribution revenue’ (utility natural gas sales and distribution revenue less natural gas purchases) as a more appropriate measure of the division’s results. For the three months ended December 31, 2012, net utility natural gas sales and distribution revenue for Liberty Utilities (East) totalled U.S. $16.2 million.

For the three months ended December 31, 2012, electricity purchases for Liberty Utilities (East) totalled U.S. $12.3 million, and natural gas purchases totalled U.S. $21.9 million.

For the three months ended December 31, 2012, operating expenses, excluding electricity and natural gas purchases, totalled U.S. $16.5 million.

For the three months ended December 31, 2012, Liberty Utilities (East)’s operating profit totalled U.S. $5.5 million.

Measured in Canadian dollars, for the three months ended December 31, 2012, Liberty Utilities (East)’s revenue from utility electricity sales totalled $17.6 million and utility natural gas sales totalled $37.7 million. Measured in Canadian dollars, for the three months ended December 31, 2012, Liberty Utilities (East)’s net utility electricity sales and distribution revenue totalled $5.4 million and net utility natural gas sales and distribution revenue totalled $16.0 million.

Measured in Canadian dollars, for the three months ended December 31, 2012, Liberty Utilities (East)’s electricity purchases totalled $12.2 million, and natural gas purchases totalled $21.7 million.

Measured in Canadian dollars, for the three months ended December 31, 2012, Liberty Utilities (East)’s operating expenses excluding electricity and natural gas purchases totalled $16.3 million.

Measured in Canadian dollars, for the three months ended December 31, 2012, Liberty Utilities (East)’s operating profit totalled $5.5 million.

In the June 30, 2012 Interim MD&A, guidance was provided on Granite State Electric Utility and EnergyNorth Gas Utility’s expected operating results over the 12 month period ending June 30, 2013. For the three months ended December 31, 2012, Granite State Electric Utility’s EBITDA of U.S. $0.5 million was lower than the guidance EBITDA of U.S. $0.8 million. The decreased EBITDA was due to lower than expected electricity usage by residential, commercial and industrial connections. Actual electricity usage was 212.1 GW-hrs compared to the guidance of 224.6 GW-hrs. Actual active electric connections were 43,250 compared to the previous guidance of 43,259 active electric connections.

For the three months ended December 31, 2012, EnergyNorth Gas Utility’s EBITDA of U.S. $5.0 million met the guidance EBITDA of U.S. $5.0 million. The EBITDA for the fourth quarter was a result of higher than expected connections for the quarter offset by lower than expected natural gas usage by residential, commercial, and industrial connections as compared to the previous guidance. Actual MMBTU was 3,266,800 compared to the previous guidance of 3,787,000. Actual active natural gas connections were 87,650 compared to the previous guidance of 86,832 active natural gas connections.

The table below represents forward looking information that was provided as at August 9, 2012 and which summarizes the expected operating results for Granite State Electric Utility and EnergyNorth Gas Utility over the next two quarters:


Expected short term metrics	2013 Q1		2013 Q2
Granite State Electric Utility:
Customers		43,312		43,365
Normalized MW-hrs		238,200		227,500
EBITDA (U.S.$ millions)	$	1.8	$	1.0

EnergyNorth Gas Utility
Customers		87,263		87,696
Normalized MMBTU		5,629,000		2,462,000
EBITDA (U.S. $ millions)	$	12.8	$	3.9

Outlook – Liberty Utilities

Liberty Utilities (West) expects continuing modest customer growth throughout its respective service territories in 2013.

On May 31, 2012, Liberty Utilities (West) filed a general rate case with the Arizona Corporation Commission related to the Rio Rico facilities seeking, among other things, an increase in EBITDA by U.S. $1.0 million over

2011 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 a mechanism that helps mitigate the effects of regulatory lag on capital investment. The new rates are expected to be implemented in the second half of 2013.

On February 17, 2012, Liberty Utilities (West) filed a general rate case and on November 29, 2012, approval of the All Parties General Rate Case Settlement (“Settlement”) was received from the CPUC. As an element of the decision, a revenue decoupling mechanism and a vegetation management memorandum account was agreed upon. The revenue decoupling mechanism will decouple base revenues from fluctuations caused by weather and economic factors. The vegetation management memorandum account allows for the tracking and pass through of vegetation management expenses, one of the largest expenses of the utility. Primarily as a result of the rate case at the Calpeco Electric Utility, additional EBITDA of $7.1 million is expected in 2013.

On February 28, 2013, Liberty Utilities (West) filed a general rate case with the Arizona Corporation Commission related to the Litchfield Park Service Company facilities 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 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.

In the first half of 2013, Liberty Utilities (East)’s electric utility will file a rate case with the NHPUC seeking an increase in distribution base rates for Granite State Electric Utility. The filing is based on a 2012 test year, with revenues and expenses adjusted to reflect known and measurable changes. In addition, Granite State Electric Utility will request approval to implement a “rate year” step adjustment to reflect certain capital additions to rate base after the test year. Among other things, Granite State Electric Utility will also seek to continue current cost-recovery tracking mechanisms, including long-term continuation of the REP/VMP Program and a modification to allow for recovery of pre-staging personnel and equipment for qualifying storms. The case is expected to be concluded in mid-2014; in accordance with general New Hampshire regulatory practice, interim rates are expected to be implemented on or about July 1, 2013.

APUC: Corporate and Other Expenses


	Three months ended December 31						Year ended December 30
	2012			2011			2012			2011
	(millions)			(millions)			(millions)			(millions)
Corporate and other expenses:
Administrative expenses	$	5.4		$	4.8		$	19.6		$	17.5
(Gain)/Loss on foreign exchange		(1.6	)		0.4			(0.6	)		(0.7	)
Interest expense		11.3			7.6			35.9			30.4
Interest, dividend and other Income		(0.4	)		(0.8	)		(2.1	)		(3.0	)
Write down of long lived assets		—			15.2			—			15.2
Acquisition-related costs		1.3			1.2			7.7			3.0
(Gain)/Loss on derivative financial instruments		(0.4	)		1.6			(0.2	)		5.8
Income tax recovery		(6.6	)		(6.0	)		(13.6	)		(22.5	)

2012 Annual Corporate and Other Expenses

During the year ended December 31, 2012, administrative expenses totalled $19.6 million, as compared to $17.5 million in the same period in 2011. The expense increase in the year ended December 31, 2012 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 2011.

For the year ended December 31, 2012, interest expense totalled $35.9 million as compared to $30.4 million in the same period in 2011. The increased interest expense is due to new indebtedness as a result of the U.S. $225 million private placement used to fund a portion of the New Hampshire and Midwest Gas Utilities acquisitions, the $135 million senior unsecured debentures placed in the third quarter of 2011 and an $1.7 million in 2012 related to the Quebec water lease litigation as compared to the same period in 2011. These amounts were partially offset by reduced interest expense related to convertible debentures due to the conversion of the Series 1A Debentures in the prior year and the Series 2A Debentures in the first quarter of 2012 and lower interest expense related to the Air Source debt which was retired in 2011.

For the year ended December 31, 2012, interest, dividend and other income totalled $2.1 million as compared to $3.0 million in the same period in 2011. 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, 2012, acquisition related costs totalled $7.7 million as compared to $3.0 million in the same period in 2011. The increase was primarily driven by the closing of Sandy Ridge Wind Facility on July 1, 2012, Granite State Electric Utility and EnergyNorth Gas Utility acquisitions on July 3, 2012, the Midwest Gas Utilities on August 1, 2012, and Minonk and Senate Facilities on December 10, 2012.

An income tax recovery of $13.6 million was recorded in the year ended December 31, 2012, as compared to a recovery of $22.5 million during the same period in 2011. The income tax recovery for the year ended December 31, 2012 primarily resulted from 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, changes in tax rates, losses in subsidiaries and production tax credits.

2012 Fourth Quarter Corporate and Other Expenses

During the quarter ended December 31, 2012, administrative expenses totalled $5.4 million, as compared to $4.8 million in the same period in 2011. The expense increase in the quarter ended December 31, 2012 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 2011.

For the quarter ended December 31, 2012, interest expense totalled $11.3 million as compared to $7.6 million in the same period in 2011. The increased interest expense is due new indebtedness as a result of the U.S. $225 million private placement used to fund a portion of the EnergyNorth Gas Utility, Granite State Electric Utility, and Midwest Gas Utilities acquisitions, and the $135 million senior unsecured debentures placed in the third quarter of 2011. These amounts were partially offset by reduced interest expense related to convertible debentures due to the conversion of the Series 1A Debentures in the prior year and the Series 2A Debentures in the first quarter of 2012.

For the quarter ended December 31, 2012, interest, dividend and other income totalled $0.4 million, as compared to $0.8 million in the same period in 2011. Interest, dividend and other income primarily consists of dividends from APUC’s share investment in the Kirkland and Cochrane facilities.

An income tax recovery of $6.6 million was recorded in the three months ended December 31, 2012, as compared to a recovery of $6.0 million during the same period in 2011. The income tax recovery for the three months ended December 31, 2012 primarily resulted from 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, changes in tax rates, losses in subsidiaries and production tax credits.

NON-GAAP PERFORMANCE MEASURES

Reconciliation of Adjusted EBITDA to net earnings

EBITDA is a non-GAAP metric used by many investors to compare companies on the basis of ability to generate cash from operations. APUC uses these calculations to monitor the amount of cash generated by APUC as compared to the amount of dividends paid by APUC. APUC uses Adjusted EBITDA to assess the operating performance of APUC without the effects of depreciation and amortization expense, income tax expense or recoveries, acquisition costs, 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. 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.

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
	2012 (millions)			2011 (millions)			2012 (millions)			2011 (millions)

Net earnings/(loss) attributable to Shareholders	$	6.4		$	(8.5	)	$	14.5		$	23.4
Add (deduct):

Net earnings attributable to the non-controlling interest		6.2			0.5			7.4			3.9
Loss from discontinued operations		0.1			0.9			1.2			0.8
Income tax recovery		(6.6	)		(6.0	)		(13.6	)		(22.5	)
Interest expense*		10.2			7.6			34.8			30.4
Acquisition costs		1.3			1.2			7.7			3.0
Write down of long-lived assets		—			15.2			—			15.2
Quebec water lease litigation		—			—			0.5			—
(Gain)/Loss on derivative financial instruments		(0.4	)		1.6			(0.2	)		5.8
(Gain)/Loss on foreign exchange		(1.6	)		0.4			(0.6	)		(0.7	)
Depreciation and amortization		17.8			11.4			54.5			44.4


Adjusted EBITDA	$	33.4		$	24.3		$	106.2		$	103.7

*	Interest expense is net of AFUDC Allowance for equity funds. See note 1(i) of notes to the financial statements.

For the year ended December 31, 2012, Adjusted EBITDA totalled $106.2 million as compared to $103.7 million, an increase of $2.5 million or 2% as compared to the same period in 2011. For the quarter ended December 31, 2012, Adjusted EBITDA totalled $33.4 million as compared to $24.3 million, an increase of $9.1 million or 37% as compared to the same period in 2011.

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


	Three months ended December 30			Year ended December 30
	(millions)			(millions)

Comparative Prior Period Adjusted EBITDA	$	24.3		$	103.7

Significant Changes:
Liberty Utilities (West) – (Reduced)/Increased electricity sales due to different weather patterns compared to prior year		1.9			(3.5	)
Liberty Utilities (Central) – Midwest Gas Utilities acquisition		3.7			4.4
Liberty Utilities (East) – EnergyNorth Gas Utility acquisition		4.7			6.1
Liberty Utilities (East) – Granite State Electric Utility acquisition		0.4			2.3
Renewable – Decreased hydrologic resource		—			(3.8	)
Renewable – Acquisition of U.S. Wind assets		1.9			2.0
Renewable – St Leon – Reduced wind resource compared to prior year		(1.4	)		(0.5	)
Renewable – St Leon II – Operations from facility expansion		0.7			1.1
Renewable – Tinker Hydro/AES – Increased demand for retail sales overshadowed by higher energy costs		(1.0	)		(1.7	)
Thermal – Windsor Locks – Reduced energy sales due to market conditions		0.1			(2.9	)
Thermal – EFW – Lower production due to expiry of Region of Peel contract		(1.2	)		(0.7	)
Administrative expense		(0.5	)		(2.1	)
Increased/(decreased) results from the stronger U.S. dollar		(0.7	)		0.6
Other		0.5			1.2


Current Period Adjusted EBITDA	$	33.4		$	106.2

Reconciliation of adjusted net earnings to 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 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 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.

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
	2012			2011			2012			2011
	(millions)			(millions)			(millions)			(millions)

Net earnings/(loss) attributable to Shareholders	$	6.4		$	(8.5	)	$	14.5		$	23.4

Add (deduct):
Loss from discontinued operations, net of tax		0.1			0.9			1.2			0.8
(Gain)/Loss on derivative financial instruments, net of tax		(0.3	)		1.0			(0.2	)		3.9
Write down of long-lived assets, net of tax		—			9.1			—			9.1
Quebec water lease litigation and interest, net of tax		—			—			1.5			—
(Gain)/Loss on foreign exchange, net of tax		(1.6	)		0.4			(0.6	)		(0.7	)
Acquisition costs, net of tax		0.8			0.7			4.7			1.8


Adjusted net earnings	$	5.4		$	3.6		$	21.1		$	38.3

Adjusted net earnings per share	$	0.03		$	0.03		$	0.14		$	0.33

For the year ended December 31, 2012, adjusted net earnings totalled $21.1 million as compared to adjusted net earnings of $38.3 million, a decrease of $17.2 million as compared to the same period in 2011. The decrease in adjusted net earnings for the year ended December 31, 2012 is primarily due to higher depreciation and amortization expense, higher interest expense, higher administration costs and decreased income tax recovery amounts, partially offset by higher income from operations, and interest and dividends as compared to the same period in 2011.

For the three months ended December 31, 2012, adjusted net earnings totalled $5.4 million as compared to adjusted net earnings of $3.6 million, an increase of $1.8 million as compared to the same period in 2011. The increase in adjusted net earnings for the three months ended December 31, 2012 is primarily due to increased earnings from operations, and increased income tax recovery amounts, partially offset by higher depreciation and amortization expense, higher administration costs, and higher interest expense as compared to the same period in 2011.

Reconciliation of adjusted funds from operations to cash flows from operating activities

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 and litigation expense. 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 changes in working capital balances, acquisition and litigation expense 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.

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
	2012		2011			2012		2011
	(millions)		(millions)			(millions)		(millions)

Cash flows from operating activities	$	16.1	$	1.4		$	63.0	$	69.7

Add (deduct):
Changes in non-cash operating items		7.2		11.6			3.9		1.5
Cash provided/(used) in discontinued operation		0.4		(1.5	)		0.4		(1.5	)
Quebec water lease litigation accrual		1.9		—			1.9		—
Acquisition costs		1.3		1.2			7.7		3.0


Adjusted funds from operations	$	26.9	$	12.7		$	76.9	$	72.7

Adjusted funds from operations per share	$	0.16	$	0.10		$	0.52	$	0.62

For the year ended December 31, 2012, adjusted funds from operations totalled $76.9 million as compared to adjusted funds from operations of $72.7 million, an increase of $4.2 million as compared to the same period in 2011.

For the three months ended December 31, 2012, adjusted funds from operations totalled $26.9 million as compared to adjusted funds from operations of $12.7 million, an increase of $14.2 million as compared to the same period in 2011.

Summary of Property, Plant and Equipment Expenditures


	Three months ended December 31					Year ended December 31
	2012 (millions)			2011 (millions)		2012 (millions)		2011 (millions)
APCo

Renewable Energy Division
Capital expenditures	$	7.5		$	6.7	$	21.1	$	25.6
Acquisition or development of new operating facilities		217.0			—		245.7		—

Total	$	224.5		$	6.7	$	266.8	$	25.6


Thermal Energy Division
Capital expenditures, net	$	(2.0	)	$	4.5	$	10.3	$	13.6

Total	$	(2.0	)	$	4.5	$	10.3	$	13.6


LIBERTY UTILITIES
West
Capital Investment in regulatory assets	$	9.6		$	9.3	$	23.2	$	20.4
Acquisition of new operating utilities		—			2.9		—		100.1

Total	$	9.6		$	12.2	$	23.2	$	120.5


Central
Capital Investment in regulatory assets	$	8.8		$	0.2	$	10.8	$	0.8
Acquisition of new operating utilities		—			—		128.9		—

Total	$	8.8		$	0.2	$	139.7	$	0.8


East
Capital Investment in regulatory assets	$	8.9		$	—	$	12.5	$	—
Acquisition of new operating utilities		—			—		295.3		—

Total	$	8.9		$	—	$	307.8	$	—


CONSOLIDATED
Total APCo
Capital expenditures	$	5.5		$	11.2	$	31.4	$	39.2
Acquisition or development of new operating facilities		217.0			—		245.7		—
Total Liberty Utilities
Capital investment in regulatory assets		27.3			9.5		46.5		21.2
Acquisition of operating entities		—			2.9		424.2		100.1
Corporate		—			—		—		0.4
Total	$	249.8		$	23.6	$	747.8	$	160.9

APUC’s consolidated capital expenditures in the year ended December 31, 2012 increased as compared to the same period in 2011 primarily due to APCo’s acquisition of the Gamesa Wind Facilities and Liberty Utilities’ acquisitions of EnergyNorth Gas Utility, Granite State Electric Utility and the Midwest Gas Utilities.

Property, plant and equipment expenditures for the 2013 fiscal year are anticipated to be between $130 million and $145 million. Capital expenditures for Liberty Utilities include: approximately $34 million at Liberty Utilities

(East) related maintenance and installation pipe in New Hampshire; approximately $20 million at Liberty Utilities (Central) related to pipe expansion and replacement; and, approximately $24 million at Liberty Utilities (West) related to major line rebuilds for the Calpeco Electric Utility and meter and overall improvements related to the water utilities. For APCo, capital expenditures includes: approximately $10 million related to the APCo Renewable Energy Division, $45 million related the development of the Cornwall Solar project; and, approximately $3 million related to the APCo Thermal Division primarily related to routine maintenance at the Windsor Locks facility and a turbine overhaul at the EFW facility.

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

2012 Annual Property Plant and Equipment Expenditures

During the year ended December 31, 2012, APCo incurred capital expenditures of $31.4 million, as compared to $39.2 million during the comparable period in 2011 in addition to $245.7 million to acquire operating entities.

During the year ended December 31, 2012, APCo’s Renewable Energy Division spent $21.1 million in capital expenditures as compared to $25.6 million in the comparable period in 2011. The capital expenditures primarily relate to the St. Leon II expansion, capitalized maintenance and upgrades at the Tinker, Long Sault, and Clement Dam hydro facilities, and project costs related to the Cornwall Solar, St. Damase and Amherst Island developments. Additionally, APCo’s Renewable Energy Division spent $245.7 million on property plant and equipment in the acquisition of Sandy Ridge, Minonk, and Senate Wind Facilities. APCo’s Thermal Energy Division net capital expenditures were $10.3 million, as compared to $13.6 million in the comparable period in 2011. The capital expenditures primarily relate to the Windsor Locks repowering and the major maintenance at the Sanger facility offset by two one-time non-recurring items: 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 year ended December 31, 2012, Liberty Utilities invested $46.5 million in capital expenditures as compared to $21.2 million during the comparable period in 2011. Additionally, Liberty Utilities spent $424.2 million to acquire operating entities as compared to $100.1 million during the comparable period in 2011. Liberty Utilities (West)’s spend was primarily related to maintenance and refurbishment needs at the Calpeco Electric Utility and the expansion of the LPSCo facility. Liberty Utility (Central)’s $10.8 million in capital expenditures was primarily a result of the $128.9 million acquisition of the Midwest Gas Utility. Liberty Utility (East)’s $12.5 million in capital expenditures was primarily a result of the $295.3 million acquisition of Granite State Electric Utility and EnergyNorth Gas Utility.

2012 Fourth Quarter Property Plant and Equipment Expenditures

During the quarter ended December 31, 2012, APCo incurred capital expenditures of $5.5 million, as compared to $11.2 million during the comparable period in 2011 in addition to $217.0 million to acquire operating entities.

During the quarter ended December 31, 2012, APCo Renewable Energy Division’s capital expenditures were $7.5 million, as compared to $6.7 million in the comparable period in 2011. The capital expenditures primarily relate to the capitalized maintenance of the Long Sault hydro facilities, and project costs related to the Cornwall Solar, St. Damase and Amherst Island developments. APCo Thermal Energy Division’s net capital expenditures were ($2.0) million as a result of a $2.4 million ITC sponsored by the U.S. Federal Government related to the repowering of the facility earlier in the year.

During the quarter ended December 31, 2012, Liberty Utilities invested $27.3 million in capital expenditures as compared to $9.5 million during the comparable period in 2011. Liberty Utilities (West)’s spend was primarily related to maintenance and refurbishment needs at the Calpeco Electric Utility and the expansion of the LPSCO facility. Liberty Utility (Central)’s $8.8 million in capital expenditures was primarily a result of the acquisition of the Midwest Gas Utility. Liberty Utility (East)’s $8.9 million in capital expenditures was primarily a result of the Granite State Electric Utility and EnergyNorth Gas Utility acquisition.

Quebec Dam Safety Act

As a result of the dam safety legislation passed in Quebec (Bill C93), APCo’s Renewable Energy Division completed technical assessments on its hydroelectric facility dams owned or leased within the Province of Quebec. Out of these, nine remedial plans have been submitted to the Quebec government and two are undergoing options analysis by APCo. The nine remedial plans have been accepted by the Quebec government and one is still being reviewed.

APCo currently estimates further capital expenditures of approximately $16.9 million related to compliance with the legislation. It is anticipated that these expenditures will be invested over a period of several years approximately as follows:


	Total		2013		2014		2015		2016

Future Estimated Bill C-93 Capital Expenditures		16,900		5,600		8,000		3,000		300

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

•

APCo’s proposed remediation plan for the Mont Laurier facility has been accepted by the Quebec government. APCo received the Certificate of Authorization from the Quebec government in November 2011. APCo completed the majority of the on-site remediation work in 2012 at a capital cost of approximately $0.3 million. Phase two of the on-site remediation work is scheduled for Q3-Q4 of 2013 at an estimated cost of $0.1 million.

•

APCo completed the dam safety evaluation for the Donnacona facility and is continuing to explore alternative engineering designs to minimize the cost of the remediation work. APCo is now pursuing a design that may result in a cost savings of 20% of the original estimates. APCo completed the engineering in 2012 and submitted the rehabilitation plan to the Quebec government to obtain the Certificate of Authorization. The remedial on-site work is anticipated to start in mid to late 2013 and be completed in 2014.

•

The dam safety study and a detailed condition assessment for the St. Alban facility have been completed. APCO is reviewing the results of the condition assessment and expects to finalize the remediation plan for this dam in 2012. APCo anticipates engineering and regulatory review to be performed in 2012 and 2013, with remedial work in 2014 to 2015.

•

APCo is presently reviewing options with respect to the Belleterre 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 2015.

•

Engineering for the Riviere-du-Loup facility was completed in Q4 of 2012. Following a geotechnical investigation the remediation work is now estimated at $1.1million.

•

The dam remediation work related to Chute Ford was completed in 2012 while the work related to the St. Raphael facility is anticipated to be completed in 2013.

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”).

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, 2012 under the Facilities:


	As at December 31, 2012												As at Sept 30, 2012 Total			As at Dec 31, 2011 Total
	APUC			APCo			Liberty Utilities			Total			As at Sept 30, 2012 Total			As at Dec 31, 2011 Total
	(millions)			(millions)			(millions)			(millions)			(millions)			(millions)
Committed Facilities	$	30.0		$	200.0		$	99.5		$	329.5		$	253.3		$	120.0


Funds drawn on Facilities		—			(27.1	)		(27.4	)		(54.5	)		(80.6	)		—
Letters of Credit issued		(1.3	)		(47.4	)		(2.0	)		(50.7	)		(52.2	)		(39.6	)

Funds available for draws on the Facilities	$	28.7		$	125.5		$	70.1		$	224.3		$	120.5		$	80.4

Cash on Hand											53.1			16.4			72.9


Total liquidity and capital reserves	$	28.7		$	125.5		$	70.1		$	277.4		$	136.9		$	153.3

On November 19, 2012, APUC entered into an agreement for a three year $30.0 million senior unsecured revolving credit facility (“APUC Facility”) with a Canadian chartered bank. The credit facility will be used for general corporate purposes and will provide APUC with additional financial flexibility. As at December 31, 2012, the APUC facility was undrawn and had $1.3 million of outstanding letters of credit.

During the fourth quarter of 2012, APCo concluded discussions with its banking syndicate to increase its senior credit facility (the “APCo Facility”) to $200 million. The amendment to the facility also resulted in security previously held over certain APCo entities to be released by the banking syndicate and the facility is now unsecured. As at December 31, 2012, APCo had drawn $27.1 million had $47.4 million in outstanding letters of credit under the APCo Facility.

During the third quarter of 2012, Liberty Utilities senior unsecured revolving credit facility (the “Liberty Facility”) was increased to $100 million. The Liberty Facility is unsecured and is for a three year term with a maturity of January 18, 2015. As at December 31, 2012, Liberty Utilities had $27.4 million was drawn to support working capital requirements and had $2.0 million of outstanding letters of credit under the Liberty Facility.

Long Term Debt

On December 3, 2012, APCo issued $150 million 4.82% senior unsecured debentures with a maturity date of February 15, 2021 pursuant to a private placement in Canada and the United States. The APCo Debentures were sold at a price of $99.94 per $100.00 principal amount, resulting in an effective yield to maturity of 4.83% per annum. Concurrent with the offering, APCo entered into a cross currency swap, coterminous with the APCo Debentures, to convert the Canadian dollar denominated debentures into U.S. dollars, resulting in an effective interest rate throughout the term of 4.4%. Net proceeds from the APCo Debentures were used primarily to fund the 400MW investment in U.S wind portfolio assets which closed on December 10, 2012.

On January 1, 2013, in conjunction with the acquisition of the Shady Oaks Wind Facility, APCo assumed a U.S. $150 million dollar variable rate long term credit facility. The facility is secured by the assets of the Wind Farm. APCo will be required to make a one-time principal payment of U.S. $25 million in the second quarter of 2013 and semi-annual principal payments ranging between U.S. $3 million and U.S. $6 million thereafter. The facility matures in 2026. Funds advanced against the facility are repayable at any time without penalty. APCo intends to refinance the facility in a manner consistent with APCo’s long term capital structure of between 45% and 50% debt. The permanent financing is expected to be issued through APCo’s existing unsecured bond platform.

During the third quarter, Liberty Utilities completed a U.S. $225 million private placement debt financing. The financing was closed in two tranches contemporaneously with the closing of the Granite State Electric Utility and EnergyNorth acquisitions. The notes are senior unsecured notes with an average life maturity of over ten years and a weighted average coupon of 4.38%. The notes have been assigned a rating of “BBB high” by DBRS Limited. Proceeds from the private placement were used to partially fund the aforementioned acquisitions.

Subsequent to the year end, on March 14, 2013 Liberty Utilities completed a U.S. $15 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 March 14, 2013, Liberty Utilities entered in an agreement for a U.S. $100 million variable rate short-term acquisition facility with a U.S. Bank. The loan facility is available for acquisition and general corporate purposes and matures on December 31, 2013.

Contractual Obligations

Information concerning contractual obligations as of December 31, 2012 is shown below:


	Total		Due less than 1 year		Due 1 to 3 years		Due 4 to 5 years		Due after 5 years
	(millions)		(millions)		(millions)		(millions)		(millions)
Long-term debt obligations¹	$	770.9		1.8		58.5		14.9		695.7
Advances in aid of construction	$	72.2		0.6		—		—		71.6
Interest on long-term debt obligations	$	329.8		41.1		80.4		71.6		136.7
Purchase obligations	$	135.6		135.6		—		—		—
Environmental Obligations	$	59.8		2.4		32.2		15.2		10.0
Derivative financial instruments:
Cross Currency Swap	$	2.1		—		—				2.1
Interest rate swap	$	4.8		2.0		2.8		—		—
Energy derivative contracts	$	10.9		0.2		1.7		0.4		8.6
Capital lease obligations	$	0.2		0.1		0.1		—		—
Capital projects	$	3.6		3.1		0.5		—		—
Long term service agreements	$	675.7		27.1		36.4		45.3		566.9
Purchased power	$	140.6		56.3		84.3		—		—
Gas delivery, service and supply agreements	$	120.5		25.2		31.8		11.0		52.5
Operating leases	$	88.4		4.4		7.9		6.5		69.6
Other obligations	$	23.7		4.2		3.1		0.4		16.0


Total obligations	$	2,438.8	$	304.1	$	339.7	$	165.3	$	1,629.7

¹	Long term obligations include regular payments related to long term debt and other obligations.

Equity

The shares of APUC are publicly traded on the Toronto Stock Exchange (“TSX”). As at December 31, 2012, APUC had 188,763,486 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, 2012, APUC had issued 4,800,000 cumulative rate reset preferred shares, Series A (the “Series A Shares”), yielding 4.5% per cent annually for the initial six-year period ending on December 31, 2018.

APUC has a shareholder dividend reinvestment plan (the “Reinvestment Plan”) for registered holders of shares (“Shareholders”) of APUC.

As at December 31, 2012, 28.7 million common shares representing approximately 15% of total shares outstanding had been registered with the Reinvestment Plan and during the quarter 325,341 common shares were issued under the Reinvestment Plan. Subsequent to the end of the quarter, on January 15, 2013, an additional 324,051 common shares were issued under the Reinvestment Plan.

On November 9, 2012, APUC issued 4.8 million cumulative rate reset preferred shares, Series A (the “Series A Shares”) at a price of $25 per share, for aggregate gross proceeds of $120 million. The shares will yield 4.5% per cent annually for the initial six-year period ending on December 31, 2018. The preferred shares have been assigned a rating of P-3 and Pfd-3(low) by S&P and DBRS respectively. The proceeds of the offering were used primarily to partially fund the acquisition of the Gamesa Wind Facilities interests which closed on December 10, 2012.

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, 2012, APUC issued a total of 26.4 million common shares for proceeds of $142.6 million pursuant to the exercise of subscription receipts issued to Emera in contemplation of certain previously announced transactions, as outlined below:

•

On May 14, 2012, in connection with the acquisition of Granite State Electric Utility and EnergyNorth Gas Utility, APUC issued 12.0 million common shares at a price of $5.00 per share to Emera pursuant to a subscription receipt agreement. The $60.0 million cash proceeds of the subscription receipts were used to fund a portion of the cost of the acquisitions.

•

On June 29, 2012, in connection with the acquisition of Sandy Ridge Wind Facility, APUC received $15.0 million relating to 2.6 million subscription receipts representing a price of $5.74 per share and issued the common shares related to these subscription receipts on July 13, 2012.

•

On July 31, 2012, in connection with the acquisition of the Midwest Gas Utilities, APUC issued 7.0 million common shares at a price of $6.45 per share to Emera pursuant to a subscription receipt agreement. The $45.0 million cash proceeds of the subscription receipts were used to fund a portion of the cost of the Midwest Gas Utilities acquisition.

•

On December 21, 2012, in connection with the acquisition of Emera’s noncontrolling interest in Calpeco, APUC received $38.7 million from Emera related to the issuance of 8.2 million subscription receipts at a price of $4.72 per subscription receipt pursuant to a subscription receipt agreement. On December 27, 2012, APUC issued 4.8 million common shares at a price of $4.72 for share proceeds of $22.6 million. Subsequent to year end, on February 14, 2013, APUC issued 3.4 million common shares at a price of $4.72 for share proceeds of $16.1 million.

Subsequent to the end of the year, 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 on February 7, 2013, and 5.2 million common shares at a price of $5.74 on February 14, 2013. The total $45 million in cash proceeds from the exercise of the subscription receipts were used at the time of the acquisition closing to fund a portion of the cost of the acquisition.

On February 22, 2013, in connection with the acquisition of the Georgia Utility, APUC issued 4.0 million subscription receipts at a price of $7.40 per share to Emera for total proceeds of approximately $29 million.

As at March 14, 2013, in total Emera now owns 46.2 million APUC common shares representing approximately 23.02% of the total outstanding common shares of the Company. 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, 2012, APUC recorded $570 and $1,833 (2011 - $287 and $732) 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, 2012, total unrecognized compensation costs related to non-vested options and share unit awards were $1,724 and $219 respectively, and are expected to be recognized over a period of 1.67 years and 1.80 years respectively.

STOCK OPTION PLAN

APUC has a stock option plan that permits the grant of share options to key officers, directors, employees and selected service providers. Except in certain circumstances, the term of an Option shall not exceed ten (10) years from the date of the grant of the Option.

For the year ended December 31, 2012, 1,263,622 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 $6.24. One third of the options will vest on each of January 1, 2013, 2014, and 2015.

As at December 31, 2012, APUC had 3,750,727 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.

PERFORMANCE SHARE UNITS

In October 2011, APUC issued 21,123 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.

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, 2012, 50,172 DSUs had been granted.

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, 2012, a total of 61,403 shares had been issued under the ESPP.

MANAGEMENT OF CAPITAL STRUCTURE

APUC views its capital structure in terms of its debt levels, both at a project and an overall company level, in conjunction with its equity balances.

APUC’s objectives when managing capital are:

•

To maintain 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

Certain executives of APUC are shareholders of Algonquin Power Management Inc. (“APMI”), the former manager of the Company. A member of the Board of Directors of APUC is an executive at Emera.

Transactions with APMI and Senior Executives

•

APUC has leased its head office facilities since 2001 from an entity owned by the shareholders of APMI on a triple net basis. Base lease costs for the year ended December 31, 2012 were $333 (2011 - $327).

•

APUC utilizes chartered aircraft, including the use of an aircraft owned by an affiliate of APMI, Algonquin Airlink Inc. In 2004, APUC remitted $1,300 to the affiliate as an advance against expense reimbursements (including engine utilization reserves) for APUC’s business use of the aircraft. During the year ended December 31, 2012, APUC incurred costs in connection with the use of the aircraft of $598 (2011 - $453)

and amortization expense related to the advance against expense reimbursements of $279 (2011 - $274). At December 31, 2012, the remaining amount of the advance was $nil (December 31, 2011 - $279).

•

Affiliates of APMI hold 60% of the outstanding Class B limited partnership units issued by the St. Leon LP, a subsidiary of APUC and the legal owner of the St. Leon facility. The related holders of the Class B units received cash distributions of $292 for the year ended December 31, 2012 (2011 - $314). Subsequent to year-end, on January 1, 2013, the Company issued 100 redeemable Series C preferred shares and exchanged such shares for the Class B units (see note 13 and 14 (b) of the consolidated financial statements).

•

APUC provided supervisory management services on a cost recovery basis to a hydroelectric generating facility not owned by APUC where Senior Executives hold an equity interest.

•

Rattle Brook is a hydroelectric generating facility in which APUC owns a 45% interest and Senior Executives hold an equity interest in. Rattle Brook is operated on a cost recovery basis by an entity which is partially owned by Senior Executives.

•

APMI is one of the two original developers of Red Lily I and both developers are entitled to a royalty fee based on a percentage of operating revenue and a development fee from the equity owner of Red Lily I. In 2011, APUC acquired APMI’s interest in this royalty for an amount of $600.

•

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. An amount of U.S. $550 has been accrued as an estimate of the final fee owed to APMI.

•

During 2007, APUC allowed its offer to acquire Clean Power Income Fund to expire and earned a termination fee of $1,800. As part of its role in the process, APUC has agreed to pay APMI a fee of U.S. $100 which has been accrued as an estimate of the final fee owed to APMI.

•

As at December 31, 2012, included in amounts due from related parties is $816 (2011 - $663) owed to APUC from APMI and included in amounts due to related parties is $1,811 (2011 - $1,795) owed to APMI. These amounts arise from the transactions described above.

•

Long Sault is a hydroelectric generating facility in which APUC acquired its interest by way of subscribing to two notes from the original developers. An affiliate of APMI is one of the original partners in the facility and is entitled to receive 5% of the after tax equity cash flows commencing in 2014.

•

In March, 2012, APUC and APMI’s Senior Executives (the “Parties”) reached a term sheet agreement to resolve a number of the historic joint business associations between the Parties. The transaction is subject to finalization of definitive agreements which are expected to be completed in the first quarter of 2013.

•

Under the term sheet, it is proposed that APUC will exchange its 45% interest in the 4MW Rattlebrook hydroelectric facility (including a $0.5 million positive working capital adjustment) in return for the Parties’ residual partnership interest in the Long Sault Rapids hydroelectric facility and the equity interest in the Brampton cogeneration plant. The agreement also settles outstanding fees owing to APMI.

Transactions with Emera

•

In 2011, a subsidiary of Emera provided lead market participant services for fuel capacity and forward reserve markets in ISO NE for the Windsor Locks facility. During the year ended December 31, 2012 APUC paid U.S. $nil (2011 – U.S. $260) 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 year ended December 31, 2012, the Energy Services Business sold electricity to Maine Public Service Company (“MPS”), a subsidiary of Emera, amounting to U.S. $6,096 (2011 – U.S. $6,564). 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.

•

As of December 31, 2012, included in amounts due from related parties is $nil (2011 - $1,612) owed from Emera related to the unpaid contribution of their share of Calpeco Electric Utility costs.

•

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

Business Associations with APMI and Senior Executives

There have been a number of business relationships between Ian Robertson and Chris Jarratt (“Senior Executives”), APMI and related affiliates (collectively the “Parties”) and APUC. These relationships include joint ownership of certain generating facility assets, business relationships between the parties and payment of fees associated with previous transactions. In 2011, the Board initiated a process to review all of the remaining business associations with the Parties in order to reduce, streamline and simplify these relationships. The Board formed a special committee and engaged independent consultants to assist with this process.

The co-owned assets and remaining business associations as at December 31, 2012 are listed below. During the quarter ended March 31, 2012, APUC and the Parties reached an agreement to resolve a number of the business associations and relationships (the “Agreement”). The transaction is subject to finalization of definitive agreements which are expected to be completed in the first quarter of 2013. A more detailed description of the Agreement has been set out below in Settlement of Other Business Associations.

Rattlebrook hydroelectric generating facility

Rattlebrook is a 4 MW hydroelectric generating station owned 45% by APUC, 27.5% by Senior Executives and the remaining percentage by third parties. This relationship was addressed pursuant to the Agreement. See Settlement of Other Business Associations below for more details.

ii)

St. Leon wind power generating facility

St. Leon is a 104 MW wind power generating facility which was structured as a limited partnership and has issued Class B units to external parties and Senior Executives. APUC and the Class B unit holders completed a transaction effective January 1, 2013 whereby the Class B units were exchanged for Class C preferred shares of APUC. The characteristics of the Class C preferred shares will provide approximately the same after tax cash to individuals holding such shares as what was estimated to have been expected from the Class B units. The external parties and Senior Executives who formerly held the Class B units are no longer partners in the St Leon limited partnership. The special committee of the Board retained the services of an independent advisor to review the historic financial performance of the St Leon facility, provide a valuation of the Class B units, provide estimation of distributions to Class B unit holders, and to provide advice to APUC in respect thereof.

iii)

Brampton Cogeneration Inc.

BCI is an energy supply facility which sells steam produced from APCo’s EFW facility. APMI maintains a carried interest equal to 50% of the annual returns on the project greater than 15%. No amounts have ever been paid under this carried interest. In 2008, APMI earned a construction supervision fee of $100 in relation to the development of this project which has been accrued. This relationship was addressed pursuant to the Agreement.

iv)

Long Sault Rapids hydroelectric generating facility

Long Sault is a hydroelectric generating facility in which APUC acquired its interest in the facility by way of subscribing to two notes from the original developers. An affiliate of APMI is one of the original partners in the facility and is entitled to receive 5% of the equity cash flows commencing in 2014. This relationship was addressed pursuant to the Agreement.

Chartered aircraft

APUC utilizes chartered aircraft owned by an affiliate of APMI. At December 31, 2012, the remaining amount of the advance was $nil (December 31, 2011 - $279).

vi)

Office lease

APUC has leased its head office facilities on a triple net basis from an entity partially owned by Senior Executives. The lease expires on December 31, 2015.

vii)

Operations services

APUC has historically provided supervisory management on a cost recovery basis for one small hydro facility in which Senior Executives hold an indirect equity interest. The board has agreed to extend the existing relationship pursuant to an agreement that can be terminated by either party upon 30 days written notice until December 31, 2013.

viii)

Sanger construction management

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. An amount of U.S. $0.6 million has been accrued as an estimate of the final fee owed to APMI. This was settled pursuant to the Agreement.

ix)

Clean Power Income Fund

During 2007, Algonquin allowed its offer to acquire Clean Power Income Fund (“Clean Power”) to expire and earned a termination fee of $1.8 million. As part of its role in the process, APUC has agreed to pay APMI a fee of $0.1 million. As of December 31, 2011 this amount is accrued and included in accounts payable on the consolidated balance sheet. This was settled pursuant to the Agreement.

Red Lily I

APMI was an early developer of the 26 MW Red Lily I wind power generation facility. As such it is entitled to a royalty fee based on a percentage of operating revenue and a development fee from Red Lily I. This relationship was settled pursuant to the Agreement.

xi)

Trafalgar

APCo owns debt on seven hydroelectric facilities owned by Trafalgar Power Inc. and an affiliate (“Trafalgar”). In 1997, an affiliate of APMI moved to foreclose on the assets, and subsequently Trafalgar went into bankruptcy. Trafalgar was previously awarded a U.S. $10.0 million claim in respect of a lawsuit related to faulty engineering in the design of these facilities, and these funds are held in the bankruptcy estate. As previously disclosed, Trafalgar, APUC and an affiliate of APMI are involved in litigation over, among other things, a civil proceeding on the foreclosure on the assets and in bankruptcy proceedings. APMI funded the initial $2 million in legal fees. An agreement was reached in 2004 between APMI and APUC whereby APUC would reimburse APMI 50% of the legal costs to date in an amount of approximately $1 million, and going forward APUC would fund the legal fees, third party costs and other liabilities with the proceeds from the lawsuits being shared after reimbursement of legal fees, third party costs and other liabilities. The Board has determined that any proceeds from the lawsuit will be shared between APMI and APUC proportionally to the quantum of such costs funded by each party.

Settlement of Other Business Associations

During the quarter ended March 31, 2012, APUC and APMI’s Senior Executives (the “Parties”) reached agreement (“Agreement”) to resolve a number of the historic joint business associations between APUC and the Parties. The Agreement is based on an effective date of January 1, 2012 and the transaction is subject to finalization of definitive agreements which are expected to be completed in the first quarter of 2013.

Under the Agreement, APUC will exchange its 45% interest in the 4MW Rattlebrook hydroelectric facility (including a $0.5 million positive working capital adjustment) in return for the Parties’ residual partnership interest in the Long Sault Rapids hydroelectric facility and the equity interest in the Brampton cogeneration plant. The agreement also terminates outstanding fees potentially owing to APMI in respect of the following: the historic transactions including the Sanger repowering project, the offer to acquire Clean Power Income Fund and the development of the Red Lily I wind project.

The special committee of the Board retained the services of an independent advisor to review the historic financial performance of the Rattlebrook and Long Sault Rapids facilities, provide a valuation of these assets and to provide advice to APUC in respect thereof.

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 59% of EBITDA in 2012 and 75% 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 $6.3 million ($0.04 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

The majority of APCo’s electricity generating facilities sell their output pursuant to long-term PPAs. However, certain of APCo’s hydroelectric facilities in the New England and New York regions sell energy at current spot market rates. In this regard, each $10.00 per MW-hr change in the market prices in the New England and New York regions would result in a change in revenue of $1.0 million on an annualized basis.

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 hydroelectric 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 commences 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.

The December 10, 2012 acquisition of Senate Wind Facility included a physical hedge which commences 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 commences 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.

The January 1, 2013 acquisition of the Shady Oaks Wind Facility included a power sales contract which commences on January 1, 2013 for a 20 year period. The power sales contract is structured to provide pricing certainty for approximately 85% 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 $0.5 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 82% of APCo Renewable Energy division’s revenue, approximately 78% of APCo Thermal Energy division’s revenue, and over 80% 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 *	Approximate Annual Revenues		Percent of Divisional Revenue
Renewable Energy Division
Manitoba Hydro	AA		26.2		28	%
Hydro – Quebec	A+		20.8		23	%
Ontario Electricity Financial Corporation	Aa2		10.0		11	%
Maine Public Service**	BBB+		8.8		10	%
ISO New England			3.8		4	%
TransAlta Corp – Dickson Dam	BBB-		3.8		4	%
Public Service Company of New Hampshire	BBB		1.4		2	%
Total – Renewable		$	74.8		82	%

Thermal Energy Division

Pacific Gas and Electric Company	BBB		12.4		39	%
Connecticut Light and Power	A-		12.3		39	%
Total – Thermal		$	24.7		78	%

Total – APCo		$	99.5		80	%

*	Ratings by Moody’s or Standard & Poor’s as of February 2013.

**	Maine Public Service is a subsidiary of Emera.

The remaining revenue is primarily earned by Liberty Utilities. In this regard, the credit risk related to Liberty Utilities (West) and Liberty Utilities (Central)’s accounts receivable balances related to the water and wastewater utilities total U.S. $6.3 million which is spread over approximately 77,000 connections, resulting in an average outstanding balance of approximately $80.00 per connection. Liberty Utilities (East) and Liberty Utilities (Central)’s accounts receivable balances related to the natural gas utilities total U.S. $33.8 million, while the Liberty Utilities (East) and Liberty Utilities (West)’s accounts receivable balances related to the electric utilities total U.S. $21.1 million. The natural gas and electrical utilities derive over 80% 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. We manage our 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:

•

APUC’s operating credit facility is subject to a variable interest rate. The APUC Facility has no amounts outstanding as at December 31, 2012. As a result, a 100 basis point change in the variable rate charged would not impact interest expense.

•

The APCo Facility had $27.1 million outstanding as at December 31, 2012. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.3 million annually.

•

APCo’s project debt at its Sanger cogeneration facility has a balance of U.S. $19.2 million as at December 31, 2012. 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 $27.4 million outstanding as at December 31, 2012. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.3 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, 2012, APUC and its subsidiaries had a combined $224.3 million of committed and available credit facilities remaining and $53.1 million of cash resulting in $277.4 million of total liquidity and capital reserves.

APUC currently pays a dividend of $0.31 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, 2012, cash provided by operating activities exceeded dividends declared by 1.8 times and exceeds Adjusted Cash From Operations by 2.1 times.

The long term portion of debt totals approximately $770.9 million with maturities set out in the Contractual Obligation table. In the event that APUC was required to replace the Facilities and project debt with borrowings having less favorable terms or higher interest rates, the level of cash generated for dividends and reinvestment may be negatively impacted.

The cash flow generated from several of APUC’s operating facilities is subordinated to senior project debt. In the event that there was a breach of covenants or obligations with regard to any of these particular loans which was not remedied, the loan could go into default which could result in the lender realizing on its security and APUC losing its investment in such operating facility. APUC actively manages cash availability at its operating facilities to ensure they are adequately funded and minimize the risk of this possibility.

Commodity price risk

APCo’s exposure to commodity prices is primarily limited to exposure to natural gas price risk. Liberty Water is not subject to any material commodity price risk. In this regard, a discussion of this risk is set out as follows:

•

APCo’s Sanger facility’s PPA includes provisions which reduce its exposure to natural gas price risk. In this regard, a $1.00 increase in the price of natural gas per MMBTU, based on expected production levels, would result in an increase in net revenue by approximately $0.2 million on an annual basis.

•

APCo’s Windsor Locks 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.

•

APCo’s BCI facility’s energy services agreement includes provisions which reduce its exposure to natural gas price risk. In this regard, a $1.00 increase in the price of natural gas per MMBTU, based on expected production levels, would result in an increase in net revenue by approximately $0.1 million.

•

AES provides short-term energy requirements to various customers at fixed rates. The energy requirements of these customers are estimated at approximately 250,000 MW-hrs in fiscal 2013. While the Tinker facility is expected to provide a significant portion of the energy required to service these customers, AES anticipates having to purchase a portion of its energy requirements at the ISO-NE spot rates to supplement self-generated energy. In the event that AES was required to purchase all of its energy requirements at ISO-NE spot rates, each $10.00 change per MW-hr in the market prices in ISO-NE would result in a change in expense of $2.5 million on an annualized basis. This risk is mitigated through the use of short-term financial energy hedge contracts. AES has committed to acquire approximately 72,000 MW-hrs of net energy over the next 12 months at an average rate of

approximately U.S. $52 per MW-hr. The mark-to-market value of these forward energy purchase contracts at December 31, 2012 was a net liability of U.S. $0.3 million.

Liberty Utilities is exposed to energy price risk in its Liberty Utilities (West) region which is mitigated through certain regulatory constructs. Liberty Utilities (West) provides electric service to the Lake Tahoe California basin and surrounding areas at rates approved by the CPUC. The utility 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 rate structure in California allows for a pass-through of energy costs to rate payers on a dollar for dollar basis, through the energy cost adjustment clause (“ECAC”) mechanism, which is designed to recoup power supply costs that are caused by the fluctuations in the price of fuel and purchased power. Actual power supply costs incurred by the facility are tracked and compared to the base rate power supply costs to ensure the cumulative variance, including carrying charges, does not exceed 5%. In the event that the cumulative variance exceeds 5%, the ECAC allows for an adjustment to the Calpeco Electric Utility’s approved rates (including carrying charges associated therewith), substantially eliminating the commodity risk associated with the purchase of power. In the 2012 California Utility’s general rate case, a revenue decoupling mechanism and a vegetation management memorandum account were agreed upon. The revenue decoupling mechanism will decouple 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, Granite 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, GSEC provides a Default Service offering to each class of customers through a competitive bidding process. This process is undertaken semi-annually for residential and small use customers and quarterly for large customers. The winning bidder is obligated to provide a full requirements service based on the actual needs of GSEC’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 GSEC which in turns receives pass-through rate recovery through a formal filing and approval process with the NHPUC each quarter. GSEC is only committed to the winning Default Service supplier(s) after approval by the NH PUC so that there is no risk of commodity commitment without pass-through rate recovery.

In the Liberty Utilities (East) region, EnergyNorth Gas Utility purchases pipeline capacity, storage and commodity from a variety of counterparties. EnergyNorth Gas Utility’s portfolio of assets, planning and forecasting methodology is approved by the NHPUC bi-annually through an Integrated Resource Plan filing. In addition, EnergyNorth Gas Utility 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. EnergyNorth Gas Utility 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, EnergyNorth Gas Utility 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 commodity prices increase or decrease relative to the initial semi-annual COG rate filing, EnergyNorth Gas Utility 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.

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. Liberty Utilities (Central) 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, Liberty Utilities (Central) 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. Liberty Utilities (Central) 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 detailed 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 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 significant risks which may lead to fire and/or explosion which may have serious impact on life and property. Risks include third party damage, significant leaks, 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, maintaining adequate insurance and the establishment of reserves for expenses.

Regulatory Risk

Profitability of APUC businesses is in part dependant 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. 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) remove of wind farm 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.

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 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 heavily 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 annual inspections by State Regulatory Agency to ensure strict adherence to applicable regulations. PHMSA reviews 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.

Liberty Utilities (East)’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 and 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, EnergyNorth Gas Utility and Granite State Electric Utility 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 $68,180 which at a discount rate of 3.5% represents $56,587 at December 31, 2012, 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, 2012 the Company has reflected a regulatory asset of $55,721 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. There are no known material environmental liabilities as at December 31, 2012.

Cycles and Seasonality

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.

Liberty Utilities (West) and Liberty Utilities (Central)’s demand for water is affected by weather conditions and temperature. Demand for water during warmer months is generally greater than cooler months due to requirements for irrigation, swimming pools, cooling systems and other outside water use. If there is above normal rainfall or rainfall is more frequent than normal the demand for water may decrease adversely affecting revenues.

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. 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.

Prior to January 1, 2013, Liberty Utilities (West) was exposed to volume sales risk related to seasonal weather variations. Effective on January 1, 2013, pursuant to a CPUC approved Rate Case decision, a Base Revenue Requirement Balancing Account (BRAAM) rate mechanism has been implemented. The BRAAM removes the seasonal variations of the revenues and flattens the net revenue (minus Fuel, Purchased Power, ECAC) to a monthly rate of $3.0 million or $35.5 million annually. This substantially eliminates the risk of revenue variations associated with seasonal weather changes.

Liberty Utilities (East) and Liberty Utilities (Central) 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, Liberty Utilities (East) and Liberty Utilities (Central)’s natural gas demand profiles typically crests in the winter months of January and February and declines in the summer months of July and August.

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.

APCo owns debt on seven hydroelectric facilities owned by Trafalgar. In 1997, an affiliate of APMI moved to foreclose on the assets, and subsequently Trafalgar went into bankruptcy. Trafalgar, APUC and an affiliate of APMI are involved in litigation over, among other things, a civil proceeding on the foreclosure on the assets and in bankruptcy proceedings.

With respect to the civil proceedings, the Second Circuit Court of Appeal dismissed all the claims against APCo 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 has filed a notice of appeal of the Memorandum-Decision and Order. Algonquin filed its brief on October 19, 2012 with a hearing dated anticipated in the first quarter of 2013. 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 Algonquin does not have a security interest in the monies transferred by Trafalgar before it filed for bankruptcy protection.

With respect to the bankruptcy proceedings, on January 30, 2013, the U.S Second Circuit Court of Appeals held that APCo 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 U.S, Second Circuit Court of Appeals.

On October 21, 2011 the Québec Court of Appeal ordered a subsidiary of APUC to pay approximately $5.4 million (including interest) to the government of Québec relating to water lease payments that the APUC subsidiary has been paying to the St. Lawrence Seaway Management Corporation (“Seaway Management”) under its water lease with Seaway Management 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 $5.8 million. The parties are attempting to resolve this matter through good faith negotiations.

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.

Quarterly Financial Information

The following is a summary of unaudited quarterly financial information for the eight quarter ended December 31, 2012:


Millions of dollars (except per share amounts)	1^st Quarter 2012		2^nd Quarter 2012		3^rd Quarter 2012			4^th Quarter 2012
Revenue	$	63.3	$	64.6	$	98.7		$	143.1
Adjusted EBITDA		23.0		25.1		24.8			33.4
Net earnings / (loss) attributable to shareholders from continuing operations		2.5		6.3		0.04			6.6
Net earnings / (loss) attributable to shareholders		2.3		6.1		(0.2	)		6.4
Net earnings / (loss) per share from continuing operations		0.02		0.04		0.00			0.04
Net earnings / (loss) per share		0.02		0.04		0.00			0.04
Adjusted net earnings		4.3		7.1		3.9			5.4
Adjust net earnings per share		0.03		0.05		0.02			0.03

Total Assets		1,265.6		1,416.0		1,967.1			2,778.2
Long term debt*		403.7		473.8		705.1			771.8

Dividend declared per common share		0.07		0.07		0.08			0.08

	1^st Quarter 2011		2^nd Quarter 2011		3^rd Quarter 2011			4^th Quarter 2011
Revenue	$	70.1	$	64.9	$	65.1		$	70.5
Adjusted EBITDA		26.7		27.9		25.8			24.3
Net earnings / (loss) attributable to shareholders from continuing operations		4.8		7.0		19.6			(7.7	)
Net earnings/(loss) attributable to shareholders		5.0		7.3		19.6			(8.5	)
Net earnings / (loss) per share from continuing operations		0.05		0.06		0.16			(0.6	)
Net earnings/(loss) per share		0.05		0.06		0.16			(0.07	)
Adjusted net earnings		5.1		7.9		22.4			3.6
Adjust net earnings per share		0.05		0.07		0.19			0.03

Total Assets		1,175.8		1,177.7		1,263.1			1,282.6
Long term debt*		507.0		451.1		472.2			455.0

Dividend declared per common share		0.07		0.07		0.07			0.07

*	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 $63.3 million and $143.1 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 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 $19.6 million and a net loss of $8.5 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.

Disclosure Controls

At the end of the fiscal year ended December 31, 2012, 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, 2012, 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, 2012, APUC acquired EnergyNorth Gas Utility, Granite State Electric Utility, the Midwest Gas Utilities, and the Sandy Ridge, Minonk and Senate Wind Facilities. 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, 2012 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, 2012 based on the criteria set forth in Internal Control – Integrated Framework 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, 2012.

During the year ended December 31, 2012, 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 postretirement benefits, and fair value of derivatives. 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

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. Unforeseen events and changes in circumstances and market conditions and material differences in the value of long-lived assets and intangibles due to changes in estimates of future cash flows, interest rates, regulatory matters and operating costs could negatively affect the fair value 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 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.

Pension and Postretirement Benefits

In conjunction with recent utilities acquisitions, the Company assumed defined benefit pension and post-retirement 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. In addition, the determination of the fair value of pension and postretirement benefits assets and liabilities acquired in the business acquisitions has been based upon management’s preliminary estimates and assumptions. The Company will continue to review information and perform further analysis. The actual fair values of the assets acquired and liabilities assumed may differ from the amounts noted.

Additional disclosure of APUC’s critical accounting estimates is also available SEDAR atwww.sedar.com and on the APUC website atwww.AlgonquinPowerandUtilities.com.

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	H.S. freshman Bad

Algonquin Power & Utilities (AQN) 40-F2012 FY Annual report (Canada)

Content analysis