Second Quarter 2011 Management's Discussion and Analysis

EX-99.1 2 dex991.htm SECOND QUARTER 2011 MANAGEMENT'S DISCUSSION AND ANALYSIS Second Quarter 2011 Management's Discussion and Analysis

EXHIBIT 99.1

LOGO

Interim Management’s Discussion and Analysis

(All figures are in thousands of Canadian dollars, except per share and convertible debenture amounts or where otherwise noted)

Management of Algonquin Power & Utilities Corp. (“APUC”) has prepared the following discussion and analysis to provide information to assist its shareholders’ understanding of the financial results for the three and six months ended June 30, 2011. This interim Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with APUC’s interim unaudited consolidated financial statements for the three and six months ended June 30, 2011 and 2010. This material is available on SEDAR at www.sedar.com and on the APUC website at www.AlgonquinPowerandUtilities.com. Additional information about APUC, including the most recent Annual Information Form (“AIF”) can be found on SEDAR at www.sedar.com.

This MD&A is based on information available to management as of August 11, 2011.

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, which apply only as of their dates. APUC reviews material forward-looking information it has presented, at a minimum, 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” and “adjusted earnings before interest, taxes, depreciation and amortization” (“Adjusted EBITDA”) are used throughout this MD&A. The terms “adjusted net earnings” and Adjusted EBITDA are not recognized measures under U.S. generally accepted accounting principles (“GAAP”). There is no standardized measure of “adjusted net earnings” and Adjusted EBITDA, consequently APUC’s method of calculating these measures may differ from methods used by other companies and therefore may not be comparable to similar measures presented by other companies. A calculation and analysis of “adjusted net earnings” and Adjusted EBITDA can be found throughout this MD&A.

Overview

APUC is incorporated under the Canada Business Corporations Act. APUC currently conducts its business primarily through two separate subsidiaries: Algonquin Power Co. (“APCo” or “Algonquin”), formerly Algonquin Power Income Fund, owns and operates a diversified portfolio of renewable energy assets and Liberty Utilities Co. (“Liberty Utilities”) owns and operates a portfolio of North American regulated utilities.

APCo generates and sells electrical energy through a diverse portfolio of renewable power generation and clean thermal power generation facilities across North America. As at June 30, 2011, APCo owns or has interests in 44 hydroelectric facilities operating in Ontario, Québec, Newfoundland, Alberta, New Brunswick, New York State, New Hampshire, Vermont, Maine and New Jersey with a combined generating capacity of approximately 165 MW. APCo also owns a 104 MW wind powered generating station in Manitoba and holds exchangeable debt securities in a 26 MW wind powered generating station recently completed in Saskatchewan. Approximately 92% of the installed capacity of the renewable energy facilities sell their electrical output pursuant to long term power purchase agreements (“PPAs”) with major utilities and have a weighted average remaining contract life of 13 years.

APCo’s ownership interest in 12 thermal energy facilities represents approximately 210 MW of installed generating capacity. Approximately 72% of these facilities’ electrical output is sold pursuant to long term PPAs with major utilities and have a weighted average remaining contract life of 8 years.¹

Liberty Utilities provides regulated utility services related to electricity, natural gas and, water distribution and wastewater collection services. Liberty Water Co. (“Liberty Water”), a subsidiary of Liberty Utilities, provides water and wastewater utility services to approximately 75,000 customers through 19 water distribution and wastewater collection and treatment utility systems located in four U.S. States (Arizona, Illinois, Missouri and Texas). These utilities operate under rate regulation, generally overseen by the public utility commissions of the States in which they operate.

Liberty Energy Utilities Co. (“Liberty Energy”), a subsidiary of Liberty Utilities, provides local electrical and natural gas distribution utility services. On January 1, 2011, in partnership with Emera Inc. (“Emera”), Liberty Energy acquired a California-based electricity distribution utility and related generation assets, and now provides electric distribution service to approximately 47,000 customers in the Lake Tahoe region (the “California Utility”). The California Utility is wholly owned by California Pacific Electric Company, LLC (“Liberty Energy (California)”).

Business Strategy

APUC’s business strategy is to maximize long term shareholder value as a dividend paying, growth-oriented corporation in the power and utilities business sectors. APUC is committed to delivering a total shareholder return comprised of dividends augmented by capital appreciation arising through growth in dividends supported by increasing cash flows and earnings. Through an emphasis on sustainable, long-view renewable power and utility investments, over a medium-term planning horizon APUC strives to deliver annualized per share earnings growth of at least 5% and continued growth in its dividend supported by increasing cash flows, earnings and additional investment prospects.

APUC believes the annual dividend payout continues to allow for both an immediate return on investment for shareholders and retention of sufficient cash within APUC to fund growth opportunities, reduce short term debt obligations and mitigate the impact of fluctuations in foreign exchange rates. Any further increases in the level of dividends paid by APUC will be at the discretion of the APUC Board of Directors (the “Board”) and dividend levels shall be 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 the 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.

Independent Power: APCo develops, owns and operates a diversified portfolio of electrical energy generation facilities. This business is comprised of three divisions: Renewable Energy, Thermal Energy and

During the fourth quarter of 2010, APCo determined that the generating capacity reported for each of its facilities was more appropriately reported based on APCo’s effective percentage ownership interest in the facility, rather than the total installed capacity of the facility; as a result, the generating capacity values set out in respect of some of the facilities included in APCo’s generating portfolio have been reduced from prior periods.

Development. The Renewable Energy division operates APCo’s hydroelectric and wind power facilities. The Thermal Energy division operates co-generation, energy-from-waste, and steam production facilities. The Development division seeks to deliver continuing growth to APCo through development of APCo’s greenfield power generation projects, accretive acquisitions of electrical energy generation facilities as well as development of organic growth opportunities within APCo’s existing portfolio of renewable energy and thermal energy facilities.

Utilities: Liberty Utilities owns and operates regulated utilities in the electricity and natural gas distribution and transmission sectors and water distribution and wastewater treatment sectors through its two wholly-owned subsidiaries, Liberty Energy and Liberty Water. These utilities share certain common infrastructure to generate economies of scale to support best-in-class customer care for their utility ratepayers. The underlying business strategy is to be a leading provider of safe, high quality and reliable utility services while providing stable and predictable earnings from these utility operations. In addition to encouraging and supporting organic growth within its service territories, Liberty Utilities is focused on delivering continued growth in earnings by identifying acquisition opportunities which accretively expand its utility business portfolio.

Major Highlights

Corporate Highlights

Dividend Increased to $0.28 Per Common Share Annually

On March 3, 2011, the Board approved an increase in the annual dividend from $0.24 to $0.26 annually. The continuing contributions from our 2010 growth initiatives are evident in our 2011 earnings and cash flows. Since the previous dividend increase, APUC has made significant progress with regards to implementing its existing growth commitments and has announced a number of new initiatives that have raised the growth profile for the Company’s earnings and cash flows, supporting an additional increase in the dividend to shareholders. These new growth initiatives, discussed in more detail below, include the acquisition of additional natural gas and electric utilities as well as new wind power generating projects to be built over the near term. As a result, on August 11, 2011, the Board approved a further dividend increase of $0.02 annually bringing the total annual dividend to $0.28, paid quarterly at the rate of $0.07 per common share.

Management believes that the increase in dividend is consistent with APUC’s stated strategy of delivering total shareholder return comprised of attractive current dividend yield and capital appreciation founded on increased earnings and cash flows.

Strengthened Balance Sheet - Conversion of Series 1A Convertible Debentures to Equity

On May 16, 2011 (“Redemption Date”), APUC redeemed all of the issued and outstanding Series 1A Debentures. Between April 1, 2011 and the Redemption Date, a principal amount of $60,266 of Series 1A Debentures were converted into 14,771,185 shares of APUC.

On May 16, 2011 APUC redeemed the remaining Series 1A Debentures by issuing and delivering 430,666 APUC shares. On June 30, 2011, as a result of the Redemption there were no Series 1A Debentures outstanding.

Strategic Investment Agreement with Emera

On April 29, 2011, APUC announced that it had entered into a strategic investment agreement (the “Strategic Agreement”) with Emera which establishes how APUC and Emera will work together to pursue specific strategic investments of mutual benefit. The Strategic Agreement builds on the strategic partnership effectively established between the two companies in April 2009.

The Strategic Agreement outlines “areas of pursuit” for each of APUC and Emera. For APUC, these include investment opportunities relating to unregulated renewable generation, small electric utilities

and gas distribution utilities. For Emera, these include investment opportunities related to regulated renewable projects within its service territories and large electric utilities. These “areas of pursuit” are intended to represent investment areas in which there is potential overlap between Algonquin and Emera and are not exhaustive of either company’s business focus and do not limit in any way the activities which either APUC or Emera can undertake. Each of APUC or Emera are free to undertake independently investments within their own “area of pursuit” and outside the other party’s “areas of pursuit”. Under the Strategic Agreement, to the extent either APUC or Emera encounter opportunities which fall within the other’s “areas of pursuit”, they are committed to work with the other party in the development of such investment opportunities.

As an element of the Strategic Agreement, Emera’s allowed common equity interest in APUC will be increased from 15% to 25%. The Strategic Agreement was approved by shareholders at the annual and special general meeting held on June 21, 2011.

Liberty Utilities Highlights

Acquisition of 100% Ownership Interest of the California Utility

On April 29, 2011, Emera agreed to sell its 49.999% direct ownership in Liberty Energy (California) to Liberty Utilities, with closing of such transaction subject to regulatory approval. As consideration Emera will receive 8.211 million APUC shares in two tranches. Approximately half of the shares will be issued following regulatory approval of the Liberty Energy (California) ownership transfer and the balance of the shares will be issued following completion of Liberty Energy (California)’s first rate case, expected to be completed in the latter half of 2012.

Utility Acquisitions by Liberty Energy

On May 13, 2011, APUC announced that Liberty Utilities had entered into an agreement with Atmos Energy Corporation (“Atmos”) to acquire their regulated natural gas distribution utility assets (the “Midwest Gas Utilities”) located in Missouri, Iowa, and Illinois. Total purchase price for the Midwest Gas Utilities is approximately U.S. $124 million, subject to certain working capital and other closing adjustments. Liberty Utilities expects to acquire assets for rate making purposes of approximately $112 million, representing a purchase price multiple of 1.106x of the acquired rate base.

The Midwest Gas Utilities currently provide natural gas local distribution service to approximately 84,000 customers. Closing of the transaction is subject to certain conditions including state and federal regulatory approval, and is expected to occur in 2012. Financing of the acquisitions is expected to occur simultaneously with the closing of the transaction. Liberty Utilities will not be assuming any existing indebtedness with this transaction.

Utility Acquisitions by Liberty Water

On April 19, 2011, APUC announced that Liberty Water had entered into asset purchase agreements to acquire three regulated water utility assets in the United States. These acquisitions, Louisiana Land and Water Co. (“LLW”), Noel Water Company (“Noel”), and KMB Utilities Company (“KMB”), will expand Liberty Water’s customer connections by approximately 7,000. Total consideration for the three acquisitions is estimated at approximately U.S. $8 million.

LLW, Noel, and KMB are anticipated to have net regulatory assets for rate making purposes at closing of approximately US$6.5 million, US$0.7 million, and US$0.3 million respectively, representing a consolidated purchase price multiple of net regulatory assets of approximately 1.09x. LLW, the largest of the three utilities serving approximately 6,000 customers near Monroe, LA, and KMB located in Missouri, both own and operate regulated water distribution and waste-water collection and treatment utility systems; Noel participates solely in the regulated water distribution utility business in Missouri.

Closings of the acquisitions are subject to certain conditions including state regulatory approval, and are expected to occur in the fall of 2011. Financing of the acquisitions is expected to occur simultaneously with the closing of the transaction.

Algonquin Power Co. Highlights

New Wind Projects Under Development

Subsequent to the end of the quarter, on July 26, 2011, APCo announced that it had entered into a 25-year power purchase agreement with Manitoba Hydro in respect of a 16.5 MW expansion of its existing St. Leon wind energy project located in the Province of Manitoba.

The expansion will be comprised of 10 Vestas V82-1.65 MW wind turbines, which already have been manufactured and are awaiting shipment to the site from a U.S. storage location. Permitting for the expansion project was completed in 2010 with construction expected to commence in the third quarter of 2011. The project is expected to be commissioned in the first quarter of 2012 with total estimated capital costs of approximately $29.5 million.

In the first full year of production following commissioning, APCo anticipates generating annual gross revenues of $3.8 million. Rates paid under the power purchase agreement are subject to a partial inflation adjustment that will be applied annually.

Acquisition of First Wind’s Northeast Projects

On April 30, 2011, APUC and Emera announced that they have entered into an agreement to jointly construct, own and operate wind energy projects in the Northeast U.S.

First Wind has a 370 MW portfolio of wind energy projects in the Northeast U.S. including five operating projects and two projects near operation. These assets will become part of an operating company of which First Wind will own 51% and, Emera and APUC through a separate joint venture (“Northeast Wind”), will own 49% of the operating company. Emera will initially own 75% of Northeast Wind and APUC will own the balance. Northeast Wind will invest a total of $333 million to acquire the 49% ownership of the operating company. This includes a $150 million loan to the operating company. The loan will be repaid within 5 years, or convert to equity in future projects.

APUC and Emera will work with First Wind to grow the operating company and develop other projects in the region. The transaction provides Northeast Wind access to a pipeline of Northeast US based development projects and provides APUC an effective way to extend its development reach into a geographic area which has historically not been included in its area of focus. APUC is able to leverage its development activities through access to First Wind’s development team within New England. APUC’s involvement includes oversight control over the process which will result in additional projects being acquired by the joint venture. Once projects in the development pipeline meet certain eligibility criteria they will transfer to the operating company.

APUC will finance its investment in Northeast Wind, in part, through a subscription agreement with Emera to issue approximately 6.9 million shares at a price of $5.37 per share for proceeds of $37 million. Delivery of the shares under the subscription receipts is conditional on and is planned to occur simultaneously with the closing of the acquisition of Northeast Wind.

The transaction is expected to be immediately accretive to both Emera and APUC. The transaction requires certain state and federal regulatory approvals, among others, and is expected to close by the end of 2011.

The First Wind projects being transferred to the operating company are:


Project	Location	Commercial Operation	Size
Mars Hill Wind,	Mars Hill, Maine	2007	42 MW
Stetson Wind I,	Danforth, Maine	2009	57 MW
Stetson Wind II,	Danforth, Maine	2010	26 MW
Rollins Wind	Lincoln, Maine	Q3 2011	60 MW
Sheffield Wind	Sheffield, Vermont	Q4 2011	40 MW
Steel Winds I	Lackawanna, New York	2007	20 MW
Cohocton Wind	Cohocton, New York	2009	125 MW

Senior Unsecured Debentures

Subsequent to the end of the quarter, on July 25, 2011, APCo issued $135 million in Senior Unsecured Debentures (the “Senior Unsecured Debentures”. The net proceeds from the Senior Unsecured Debentures were used to repay the outstanding AirSource Senior Debt at the St. Leon facility and to reduce amounts outstanding under APCo’s senior revolving credit facility (the “Facility”). The Senior Unsecured Debentures mature on July 25, 2018, and bear interest at a rate of 5.50% per annum, calculated semi-annually payable on January 25 and July 25 each year, commencing on January 25, 2012.

2011 Six month results from operations

APUC continued to show strong results through to the end of the second quarter of 2011. Over the past two years, APUC has focused its efforts on a number of value creation initiatives that, through their completion, have now created the conditions for growth in APUC revenues, EBITDA and earnings. These value initiatives include Liberty Energy’s acquisition of the California Utility, prosecution of rate cases by Liberty Water, APCo’s refurbishment of the Energy from Waste facility, acquisition by APCo of the Tinker Hydro facility and APCo’s completion of construction and commissioning of the Red Lily I Wind Farm. As a result, for the six months ended June 30, 2011, APUC reported total revenue of $138.5 million as compared to $87.1 million during the same period in 2010, an increase of $51.4 million or 60%. Adjusted EBITDA in the six months ended June 30, 2011 totalled $55.1 million as compared to $36.6 million during the same period in 2010, an increase of $18.5 million or 51%.

Key Selected Six Month Financial Information


	Six months ended June 30
	2011 (millions)		2010 (millions)
Revenue	$	138.5	$	87.1
Adjusted EBITDA¹		55.1		36.6
Cash provided by Operating Activities		35.3		21.0
Net earnings attributable to Shareholders		12.3		1.1
Adjusted net earnings²		13.5		3.1
Dividends to Shareholders		14.5		11.3

Per share
Basic net earnings	$	0.11	$	0.01
Adjusted net earnings²	$	0.12	$	0.02
Diluted net earnings	$	0.11	$	0.01
Cash provided by Operating Activities	$	0.33	$	0.23
Dividends to Shareholders	$	0.13	$	0.12
Total Assets		1,177.7		1,020.0
		328.7		259.9

Long Term Debt (includes current portion)

APUC uses Adjusted EBITDA 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. Adjusted EBITDA is a non-GAAP measure - see applicable section later in this MD&A and the caution regarding non-GAAP measures on page 1.

APUC uses Adjusted net earnings to enhance assessment and understanding of the performance of APUC without the effects of certain accounting adjustments which are derived from a number of non-operating factors, accounting methods and assumptions. Adjusted net earnings is a non-GAAP measure - see applicable section later in this MD&A and the caution regarding non-GAAP measures on page 1.

The major factors resulting in the increase in APUC revenue in the six months ended June 30, 2011 as compared to the corresponding period in 2010 are set out as follows:


	Six months ended June 30, 2011
	(millions)
Comparative Prior Period Revenue	$	87.1

Significant Changes:
California Utility Acquisition – January 1, 2011		40.3
Energy-from-Waste facility		7.8
Liberty Water revenue increases primarily due to rate case approvals		4.7
Effect of wind resource compared to comparable period in prior year		1.3
Effect of hydrology resource compared to comparable period in prior year		3.6
Sanger Facility – Impact of price/volume reductions vs the comparable period		(0.5	)
Tinker Hydro/ESB		(0.5	)
Change in operating model at Windsor Locks		(1.1	)
Impact of the weaker U.S. dollar		(4.0	)
Other		(0.2	)


Current Period Revenue	$	138.5

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

APUC reports its results in Canadian dollars. For the six months ended June 30, 2011, APUC experienced an average U.S. exchange rate of approximately $0.977 as compared to $1.035 in the same period in 2010. As such, any year over year variance in revenue or expenses, in local currency, at any of APUC’s U.S. entities are affected by a change in the average exchange rate, upon conversion to APUC’s reporting currency.

Adjusted EBITDA in the six months ended June 30, 2011 totalled $55.1 million as compared to $36.6 million during the same period in 2010, an increase of $18.5 million or 51%. The increase in Adjusted EBITDA is primarily due to increased earnings from operations primarily resulting from the acquisition of the California Utility, increased revenues from Liberty Water resulting from the completion of rate cases, improved average hydrology and wind resources in the Renewable Energy division and improved results from the EFW facility, partially offset by lower results at Windsor Locks, and the impact of the weaker U.S. dollar as compared to the same period in 2010. 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 six months ended June 30, 2011, net earnings attributable to Shareholders totalled $12.3 million as compared to $1.1 million during the same period in 2010, an increase of $11.3 million. Basic net earnings per share totalled $0.11 for the six months ended June 30, 2011, as compared to $0.01 during the same period in 2010.

For the six months ended June 30, 2011, net earnings totalled $15.0 million as compared to $1.3 million during the same period in 2010, an increase of $13.7 million. A number of factors resulted in increased net earnings for the six months ended June 30, 2011 including an increase of $20.5 million due to increased earnings from operating facilities, $0.1 million due to decreased amortization expense, $1.6 million due to decreased losses on derivative financial instruments and $0.3 million related to decreased losses on foreign exchange as compared to the same period in 2010. These items were partially offset by increased expenses of $2.0 million due to increased management and administration expense, $3.4 million due to increased interest expense, $2.5 million related to decreased recoveries of income tax expense primarily due to the reasons discussed in Annual Corporate and Other Expenses – Income Taxes and $0.7 million due to increased acquisition costs as compared to the same period in 2010.

A more detailed analysis of realized and unrealized mark to market gains and losses on foreign exchange contracts and interest swap contracts can be found later in this report under Treasury Risk Management -Foreign currency risk.

During the six months ended June 30, 2011, cash provided by operating activities totalled $35.3 million or $0.33 per share as compared to cash provided by operating activities of $21.0 million, or $0.23 per share during the same period in 2010, an increase of approximately 43% per share. Cash provided by operating activities exceeded dividends declared by 2.5 times during the six months ended June 30, 2011 as

compared to 1.9 times dividends during the same period in 2010. The change in cash provided by operating activities after changes in working capital in the six months ended June 30, 2011, is primarily due to increased cash from operations, partially offset by increased interest expense and increased management and administration expense as compared to the same period in 2010.

2011 Three month results from operations

Key Selected Second Quarter Financial Information


	Three months ended June 30
	2011		2010
Revenue	$	66.8	$	42.0
Adjusted EBITDA ¹	$	28.2	$	18.7
Cash provided by Operating Activities		16.0		12.6

Net earnings (loss) attributable to Shareholders		7.3		(2.5	)

Adjusted net earnings (loss) ²		8.3		0.2
Dividends to Shareholders		7.8		5.7

Per share
Basic net earnings (loss)	$	0.07	$	(0.03	)
Adjusted net earnings ²	$	0.07	$	0.00
Diluted net earnings (loss)	$	0.07	$	(0.03	)
Cash provided by Operating Activities	$	0.14	$	0.13
Dividends to Shareholders	$	0.065	$	0.06

The major factors resulting in the increase in APUC revenue in the three months ended June 30, 2011 as compared to the corresponding period in 2010 are set out as follows:


	Three months ended June 30, 2011
	(millions)
Comparative Prior Period Revenue	$	42.0

Significant Changes:
California Utility Acquisition – January 1, 2011		17.1
Energy-from-Waste facility		4.4
Effect of hydrology resource compared to comparable period in prior year		3.6
Liberty Water revenue increases primarily due to rate case approvals		2.8
Effect of wind resource compared to comparable quarter		0.3
Change in operating model at Windsor Locks		(0.8	)
Impact of the weaker U.S. dollar		(2.2	)
Other		(0.4	)

Current Period Revenue	$	66.8

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

APUC reports its results in Canadian dollars. For the three months ended June 30, 2011, APUC experienced an average U.S. exchange rate of approximately $0.968 as compared to $1.028 in the same period in 2010. 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.

Adjusted EBITDA in the three months ended June 30, 2011 totalled $28.2 million as compared to $18.7 million during the same period in 2010, an increase of $9.5 million or 51%. The increase in Adjusted EBITDA is primarily due to increased earnings from operations primarily resulting from the acquisition of the California Utility, increased revenues from Liberty Water resulting from the completion of rate cases, improved hydrology in the Renewable Energy division and improved results from the EFW facility, partially

offset by lower results at Windsor Locks, the load supply and energy procurement business in Northern Maine (“ESB”) and the impact of the weaker U.S. dollar as compared to the same period in 2010. 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 June 30, 2011, net earnings attributable to Shareholders totalled $7.3 million as compared to a net loss attributable to Shareholders of $2.5 million during the same period in 2010, an increase of $9.8 million. Net earnings per share totalled $0.07 for the three months ended June 30, 2011, as compared to a net loss attributable to APUC of $0.03 during the same period in 2010.

For the three months ended June 30, 2011, net earnings totalled $8.1 million as compared to a net loss of $2.3 million during the same period in 2010, an increase of $10.4 million. A number of factors resulted in increased net earnings for the three months ended June 30, 2011 including an increase of $10.9 million due to increased earnings from operating facilities, $0.7 million due to decreased amortization expense, $2.1 million due to decreased losses on derivative financial instruments and $0.3 million related to decreased losses on foreign exchange as compared to the same period in 2010. These items were partially offset by increased expenses of $1.2 million due to increased management and administration expense, $1.5 million due to increased interest expense, $0.9 million related to decreased recoveries of income tax expense primarily due to the reasons discussed in Annual Corporate and Other Expenses – Income Taxes and $0.2 million due to decreased interest, dividend and other income as compared to the same period in 2010.

During the three months ended June 30, 2011, cash provided by operating activities totalled $16.0 million or $0.14 per share as compared to cash provided by operating activities of $12.6 million, or $0.13 per share during the same period in 2010, an increase of approximately 8%. Cash provided by operating activities exceeded dividends declared by 2.2 times during the quarter ended June 30, 2011, consistent with the same period in 2010. The change in cash provided by operating activities after changes in working capital in the three months ended June 30, 2011, is primarily due to increased cash from operations, partially offset by increased interest expense and increased management and administration expense as compared to the same period in 2010.

Outlook

APCo

The APCo Renewable Energy division is expected to perform in line with long-term average resource conditions for hydrology and long-term average wind resources in the third quarter of 2011.

The capital upgrade completed in 2010 at the EFW facility is expected to continue to result in higher throughput and lower operating costs at the facility in the third quarter of 2011 consistent with the results experienced in the first half of 2011.

APCo anticipates that the Sanger facility should meet expectations for the third quarter of 2011 and be in line with 2010 results.

APCo Thermal Energy division’s Windsor Locks facility will continue to sell a portion of its electricity capacity and all of its steam capacity to the industrial host with the balance of the electrical capacity available to be sold either into the Independent System Operator New England (“ISO-NE”) day-ahead market or to industrial customers through the ESB. It is anticipated that performance during the third quarter of 2011 will be in line with expectations.

Liberty Utilities

Liberty Water is forecasting continuing modest customer growth in 2011. Revenue increases from rate cases completed in Arizona and Texas are anticipated to contribute additional revenue in Liberty Water in

the third quarter of 2011 as compared to the same period in 2010. Liberty Water attributes approximately U.S. $4.0 million of the revenue increases in the first two quarters of 2011 to the impact of completed rate cases and anticipates that this will continue in the third quarter. In addition, the Bella Vista rate case was completed in the quarter and is expected to contribute an additional U.S. $0.8 million in revenue on an annualized basis.

Liberty Energy expects modest customer growth in 2011. Liberty Energy anticipates that the California Utility should exceed expectations for the third quarter of 2011 through increased load and customer count.

Liberty Utilities is pursuing additional investments in water, wastewater, electric and gas distribution utilities and electric transmission assets, sharing certain common infrastructure between utilities to support best in-class-customer care for its subsidiary utility ratepayers.

LOGO


	Three months ended June 30								Six months ended June 30
	Long Term Average Resource		2011			2010			Long Term Average Resource		2011			2010
Performance (GWhr sold)
Quebec Region		84.2		89.9			76.9			142.0		150.8			141.5
Ontario Region		36.1		35.4			22.8			73.3		68.5			52.7
Manitoba Region		86.0		90.5			85.9			191.0		183.3			165.1
Saskatchewan Region*		15.1		14.2			—			23.4		21.5			0
New England Region		19.3		21.1			13.2			37.9		37.5			32.0
New York Region		27.4		32.5			20.0			54.7		55.1			44.0
Western Region		19.1		21.9			13.6			29.3		31.7			23.0
Maritime Region		57.0		58.5			42.1			82.6		91.3			73.5


Total		344.2		364.0			274.5			634.2		639.7			531.8

Revenue **
Energy sales			$	23,845		$	19,974				$	45,724		$	42,192
Less:
Cost of Sales – Energy***				(561	)		(745	)				(2,333	)		(2,960	)

Net Energy Sales			$	23,284		$	19,229				$	43,391		$	39,232

Other Revenue				727			997					1,228			997

Total Net Revenue			$	24,011		$	20,226				$	44,619		$	40,229

Expenses
Operating expenses				(6,402	)		(5,304	)				(12,216	)		(11,214	)
Interest and Other income				600			264					1,020			402

Division operating profit (including other income)			$	18,209		$	15,186				$	33,423		$	29,417

*	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 six months of production.

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.

***	Cost of Sales – Energy consists of energy purchases by the ESB which is resold to its retail and industrial customers.

2011 Six Month Operating Results

For the six months ended June 30, 2011, the Renewable Energy division produced 639.7 GWhr of electricity, as compared to 531.8 GWhr produced in the same period in 2010, an increase of 20.3%. The increased generation is primarily due to improved average hydrology in the quarter as compared to the comparable period in 2010. This level of production in 2011 represents sufficient renewable energy to supply the equivalent of 70,000 homes on an annualized basis with renewable power. Using new standards of thermal generation, as a result of renewable energy production, the equivalent of 350,000 tons of CO2 gas was prevented from entering the atmosphere in the first and second quarters of 2011.

During the six months ended June 30, 2011, the division generated electricity equal to 101% of long-term projected average resources (wind and hydrology) as compared to 85% during the same period in 2010. In the first and second quarters of 2011, the Maritimes, Western and Quebec regions experienced resources significantly higher than long-term averages, producing between 5 - 10% above long-term average resources. The New York and New England regions experienced resources approximately equal to long-term averages. The Manitoba, Ontario and Saskatchewan regions experienced resources between 5 - 10% below long-term averages.

For the six months ended June 30, 2011, revenue from energy sales in the Renewable Energy division totalled $45.7 million, as compared to $42.2 million during the same period in 2010, an increase of $3.5 million or 8%. As the purchase of energy by the ESB is a significant driver of revenue 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 six months ended June 30, 2011, net revenue from energy sales in the Renewable Energy division totalled $43.4 million, as compared to $39.2 million during the same period in 2010, an increase of $4.2 million or 11%.

Revenue generated from APCo’s Ontario, Quebec and Western regions increased by $3.0 million due to a 16% overall increase in hydrology and an increase weighted average energy rates, primarily in the Quebec region, of approximately 1.5% as compared to the same period in 2010. Revenue from APCo’s New England and New York region facilities increased $0.4 million due to increased average hydrology partially offset by a decrease in weighted average energy rates of approximately 5%. Revenue from the Manitoba region increased $1.3 million primarily due to a stronger wind resource and $0.1 million in the Maritime region primarily due to increased customer demand as compared to the same period in 2010. These increases were partially offset by a $0.6 million decrease in revenue at the ESB primarily due to decreased energy rates and customer demand as compared to the same period in 2010. Revenue at the ESB primarily consists of wholesale deliveries to local electric utilities and retails sales to commercial and industrial customers in Northern Maine ($7.8 million) and merchant sales of production in excess of customer demand and other revenue ($0.4 million). The division reported decreased revenue of $0.8 million from U.S. operations as a result of the weaker U.S. dollar as compared to the same period in 2010.

Red Lily I achieved commercial operations effective February 23, 2011. From commercial operation date to June 30, 2011 Red Lily I produced 21.5 GWhr of electricity which was sold to SaskPower. APCo’s economic return from its investment in Red Lily currently comes in the form of interest payments, fees and other charges. 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. On the expectation that APCo will exercise such option, APCo proportionally includes the performance of Red Lily in its generation report. For the six months ended June 30, 2011, APCo earned fees and interest payments from Red Lily I in the total amount of $2.0 million.

For the six months ended June 30, 2011, energy purchase costs by the ESB totalled U.S. $2.4 million. During the first six months, the ESB purchased approximately 25.3 GWhr of energy at market and fixed rates averaging U.S. $70 per MWhr. The Maritime region generated approximately 80% of the load required to service its customers as well as the ESB’ customers in the six months ended June 30, 2011. The division reported decreased energy purchase costs of $0.2 million as a result of the weaker U.S. dollar as compared to the same period in 2010.

For the six months ended June 30, 2011, operating expenses excluding energy purchases totalled $12.2 million, as compared to $11.2 million during the same period in 2010, an increase of $1.0 million or 9%. Operating expenses were impacted by $0.6 million related to increased operating costs associated with the Tinker Assets and the ESB as compared to the same period in 2010. Operating expenses include costs incurred in the period of $0.7 million associated with the pursuit of various growth and development

activities, consistent with the same period in 2010. In the prior period, APCo recorded a reduction in the development costs due to a reimbursement of $0.9 million in connection with the Red Lily I wind project. The division reported decreased expenses of $0.3 million from U.S. operations as a result of the weaker U.S. dollar as compared to the same period in 2010.

For the six months ended June 30, 2011, interest, dividend and other income totalled $1.0 million, as compared to $0.4 million during the same period in 2010. Interest, dividend and other income primarily consists of interest related to the senior and subordinated senior debt interest in the Red Lily I project. This amount is included as part of APCo’s earnings from its investment in Red Lily, as discussed above.

For the six months ended June 30, 2011, Renewable Energy’s operating profit totalled $33.4 million, as compared to $29.4 million during the same period of 2010, representing an increase of $4.0 million or 14%. For the six months ended June 30, 2011, Renewable Energy’s operating profit exceeded APCo’s expectations primarily due to increased hydrology in the Canadian regions.

2011 Second Quarter Operating Results

For the quarter ended June 30, 2011, the Renewable Energy division produced 364.0 GWhr of electricity, as compared to 274.5 GWhr produced in the same period in 2010, an increase of 33%. The increased generation is due to improved average hydrology in the quarter as compared to the comparable period in 2010. This level of production in 2011 represents sufficient renewable energy to supply the equivalent of 80,000 homes on an annualized basis with renewable power. Using new standards of thermal generation, as a result of renewable energy production, the equivalent of 200,000 tons of CO2 gas was prevented from entering the atmosphere in the second quarter of 2011.

During the quarter ended June 30, 2011, the division generated electricity equal to 106% of long-term projected average resources (wind and hydrology) as compared to 81% during the same period in 2010. In the second quarter of 2011, the New York and Western regions experienced resources significantly higher than long-term averages, producing between 15 - 20% above long-term average resources. In the second quarter of 2011, the New England, Quebec and Manitoba regions experienced resources higher than long-term averages, producing between 5 - 10% above long-term average resources. The Maritimes and Ontario regions experienced resources approximately equal to long-term average resources while the Saskatchewan region experienced resources of approximately 5% below the long-term average.

For the quarter ended June 30, 2011, revenue from energy sales in the Renewable Energy division totalled $23.8 million, as compared to $20.0 million during the same period in 2010, an increase of $3.9 million or 19%. As the purchase of energy by the ESB is a significant driver of revenue 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 June 30, 2011, net revenue from energy sales in the Renewable Energy division totalled $23.3 million, as compared to $19.2 million during the same period in 2010, an increase of $4.1 million or 21%.

Revenue generated from APCo’s Ontario, Quebec and Western regions increased by $2.8 million primarily due to a 30% overall increase in hydrology and increased weighted average energy rates, primarily in the Ontario region, of approximately 5% as compared to the same period in 2010. Revenue from APCo’s New England and New York region facilities increased $0.7 million primarily due to a 60% overall increase in average hydrology, partially offset by a decrease in weighted average energy rates of approximately 6% as compared to the same period in 2010. The ESB experienced a $0.7 million increase in revenue primarily due to increased customer demand partially offset by reduced energy rates as compared to the same period in 2010. Revenue at the ESB primarily consists of wholesale deliveries to local electric utilities and retails sales to commercial and industrial customers in Northern Maine of $4.6 million. Revenue from the Manitoba region increased $0.3 million primarily due to a stronger wind resource, partially offset by a decrease of $0.2 million in the Maritime region primarily due to decreased customer demand as compared to the same period in 2010. The division reported decreased revenue of $0.4 million from U.S. operations as a result of the weaker U.S. dollar as compared to the same period in 2010.

In the three months ended June 30, 2011 Red Lily I produced 14.2 GWhr of electricity which was sold to SaskPower. APCo’s economic return from its investment in Red Lily currently comes in the form of interest payments, fees and other charges. As discussed in the “Six Months Operating Results” above, APCo proportionally includes the performance of Red Lily in its generation report. For the three months ended June 30, 2011, APCo earned fees and interest payments from Red Lily in the total amount of $1.2 million.

For the quarter ended June 30, 2011, energy purchase costs by the ESB totalled U.S. $0.6 million. During the quarter, the ESB purchased approximately 4.1 GWhr of energy at market and fixed rates averaging U.S. $48 per MWhr. The Maritime region generated approximately 93% of the load required to service its customers as well as the ESB’s customers in the three months ended June 30, 2011.

For the quarter ended June 30, 2011, operating expenses excluding energy purchases totalled $6.4 million, as compared to $5.3 million during the same period in 2010, an increase of $1.1 million or 21%. Operating expenses were impacted by $0.4 million related to increased operating costs associated with the Tinker Assets and the ESB and by $0.3 million primarily related to increased water usage and consumables at Canadian hydroelectric facilities as compared to the same period in 2010. Operating expenses include costs incurred in the period of $0.4 million associated with the pursuit of various growth and development activities, consistent with the same period in 2010. In the prior period, APCo recorded a reduction in the development costs due to a reimbursement of $0.9 million in connection with the Red Lily I wind project. The division reported decreased expenses of $0.4 million from U.S. operations as a result of the weaker U.S. dollar as compared to the same period in 2010.

For the quarter ended June 30, 2011, interest, dividend and other income totalled $0.6 million, as compared to $0.3 million during the same period in 2010. Interest, dividend and other income primarily consists of interest related to the senior and subordinated senior debt interest in the Red Lily I project. This amount is included as part of APCo’s earnings from its investment in Red Lily, as discussed above.

For the quarter ended June 30, 2011, Renewable Energy’s operating profit totalled $18.2 million, as compared to $15.2 million during the same period of 2010, representing an increase of $3.0 million or 20%. For the quarter ended June 30, 2011, Renewable Energy’s operating profit exceeded APCo’s expectations primarily due to a stronger wind resource than expected in the Manitoba region and stronger hydrology in both the U.S. and Canadian regions.

Divisional Outlook – Renewable Energy

The APCo Renewable Energy division is expected to perform based on long-term average resource conditions for hydrology and long-term average wind resources in the third quarter of 2011.

The ESB anticipates that, based on the expected load forecast for its existing contracts, it will provide approximately 29,000 MWhrs of energy to its customers in the third quarter of 2011. The ESB anticipates that the Tinker Assets will provide over 60% of the energy required to service its customers in the third quarter of 2011 and that it will need to purchase approximately 11,000 MWhrs of energy from the ISO NE or similar market. The ESB has in place fixed price financial energy contracts to operationally hedge the price of the customer supply obligations which are not expected to be supplied by the Tinker Assets and to minimize the volatility of the energy prices. These contracts in combination with the expected Tinker production are used to balance the monthly customer load.

APCo: Thermal Energy Division


	Three months ended June 30						Six months ended June 30
	2011			2010			2011			2010
Performance (GWhr sold)		127.4			99.9			258.9			239.1
Performance (tonnes of waste processed)		42,150			—			83,525			6,550
Performance (steam sales – billion lbs)		287.7			275.3			633.8			600.6

Revenue
Energy / steam sales	$	9,674		$	11,084		$	22,157		$	24,646
Less:
Cost of sales – fuel *		(4,907	)		(5,294	)		(11,261	)		(11,539	)

Net energy / steam sales revenue	$	4,767		$	5,790		$	10,896		$	13,107

Waste disposal sales		4,266			90			8,286			1,007
Other revenue		264			341			455			544

Total net revenue	$	9,297		$	6,221		$	19,637		$	14,658
Expenses
Operating expenses *		(4,971	)		(4,932	)		(11,046	)		(10,603	)
Interest and other income		(105	)		379			(17	)		518


Division operating profit (including interest and dividend income)	$	4,221		$	1,668		$	8,574		$	4,573

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

2011 Six Month Operating Results

During the six months ended June 30, 2011, the business unit produced 258.9 GWhr of energy as compared to 239.1 GWhr of energy in the comparable period of 2010. During the six months ended June 30, 2011, the business unit’s total production increased by 21.6 GWhr from the Windsor Locks facility and 4.8 GWhr from the EFW facility as compared to the same period in 2010. The comparable period includes 2.5 GWhr of production from landfill gas facilities which ceased generating energy and were closed in 2010.

The EFW facility processed 83,525 tonnes of municipal solid waste as compared to 6,550 tonnes processed in the same period of 2010. During the comparable period, the facility experienced an unplanned outage from January to July 2010 during which minimal waste was processed. The current level of production resulted in the diversion of approximately 59,000 tonnes of waste from municipal solid waste landfill sites in the first and second quarters of 2011.

During the six months ended June 30, 2011, the BCI and Windsor Locks facilities sold 633.8 billion lbs of steam as compared to 600.6 billion lbs of steam in the comparable period of 2010. During the six months ended June 30, 2011, operations at the EFW facility generated 255.0 billion lbs of steam for the BCI facility as compared to 18.0 billion lbs of steam in the same period in 2010.

For the six months ended June 30, 2011, energy / steam revenue in the Thermal Energy division totalled $22.2 million, as compared to $24.6 million during the same period in 2010, a decrease of $2.5 million, or 10%. As natural gas expense is a significant revenue driver and component of operating expenses, the division compares ‘net energy sales revenue’ (energy sales revenue less natural gas expense) as a more appropriate measure of the division’s results. For the six months ended June 30, 2011, net energy / steam sales revenue at the Thermal Energy division totalled $10.9 million, as compared to $13.1 million during the same period in 2010, a decrease of $2.2 million, primarily arising from the termination of the previous power purchase agreements in effect until April 2010 at the Windsor Locks facility and the weaker U.S. dollar.

The overall decrease in revenue from energy / steam sales was primarily due to a decrease of $3.0 million at the Windsor Locks facility as a result of decreased energy rates, in part due to the change in operating model of the facility, partially offset by an increase of $1.9 million as a result of increased production, as compared to the prior year. The Sanger facility experienced a decrease of $0.5 million as a result of decreased energy pricing, in part the result of lower average landed price per mmbtu for natural gas while energy / steam sales revenue decreased $0.2 million as a result of the closure of the LFG facilities, as compared to the prior year. The decrease in revenue was partially offset by $0.2 million at the BCI facility as

a result of increased price for steam and an increase of $0.3 million at the EFW facility as a result of increased production of energy, as compared to the same period in 2010. The natural gas expense at the Sanger and Windsor Locks facilities is discussed in detail below. The division reported decreased energy sales revenue of $1.2 million from operations as a result of the weaker U.S. dollar, as compared to the same period in 2010.

Revenue from waste disposal sales for the six months ended June 30, 2011 totalled $8.3 million, as compared to $1.0 million during the same period in 2010. The increase was a result of the EFW facility shutdown in the comparable period of 2010.

Other revenue for the six months ended June 30, 2011 totalled $0.5 million, consistent with the same period in 2010.

For the six months ended June 30, 2011, fuel costs at Sanger and Windsor Locks totalled U.S $11.5 million, as compared with U.S $11.1 million in the same period in 2010, an increase of U.S. $0.4 million.² The overall natural gas expense at the Windsor Locks facility increased U.S. $0.6 million (8%), primarily the result of a 6% increase in volume of natural gas consumed, as compared to the same period in 2010. The average landed cost of natural gas at the Windsor Locks facility during the six months was U.S. $4.79 per mmbtu. This was partially offset by a decrease in the natural gas expense at Sanger of U.S. $0.3 million (11%), primarily the result of a 12% decrease in the average landed cost of natural gas per mmbtu as compared to the same period in 2010. The average landed cost of natural gas at the Sanger facility during the six months was U.S. $4.58 per mmbtu. The division reported decreased fuel expenses of $0.6 million as a result of the weaker U.S. dollar as compared to the same period in 2010.

For the six months ended June 30, 2011, operating expenses, excluding fuel costs at Windsor Locks and Sanger, totalled $11.0 million, as compared to $10.6 million during the same period in 2010, an increase of $0.4 million. The increase in operating expenses for the six months was primarily due to $3.9 million in increased gas, consumables, repair and maintenance and wages at the EFW facility resulting from the outage at the facility in 2010, partially offset by $1.8 million of reduced natural gas costs at BCI as a result of the EFW facility generating more steam and $0.7 million of reduced operating costs at the LFG facilities as a result of these facilities being closed in 2010, as compared to the same period in 2010. Operating expenses in the comparable period included costs of $0.4 million associated with the pursuit of various growth and development activities. The division reported decreased expenses of $0.7 million from U.S. operations as a result of the weaker U.S. dollar as compared to the same period in 2010.

For the six months ended June 30, 2011, the Thermal Energy division’s operating profit totalled $8.6 million, as compared to $4.6 million during the same period in 2010, representing an increase of $4.0 million or 87%. Operating profit in the Thermal Energy division exceeded expectations for the six months ended June 30, 2011, primarily due to better than expected earnings at the Windsor Locks facility as a result of improved energy pricing.

2011 Second Quarter Operating Results

During the quarter ended June 30, 2011, the business unit produced 127.4 GWhr of energy as compared to 99.9 GWhr of energy in the comparable period of 2010. During the quarter ended June 30, 2011, the business unit’s total production increased by 25.9 GWhr from the Windsor Locks facility, 3.2 GWhr from the EFW facility, and 1.2 GWhr from the Sanger, each as compared to the same period in 2010.

The EFW facility processed 42,140 tonnes of municipal solid waste. No waste was processed in the same period of 2010. The significant increase in throughput is the result of the unplanned outage experienced from January to July 2010. The current level of production resulted in the diversion of approximately 29,000 tonnes of waste from municipal solid waste landfill sites in the second quarter of 2011.

APCo’s Sanger and Windsor Locks generation facilities purchase natural gas from different suppliers and at prices based on different regional hubs. Consequently 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 showing 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. As a result, a facility may record a higher aggregate expense for natural gas as a result of a lower average landed per unit cost for natural gas combined with a consumption of a higher volume of such gas.

During the quarter ended June 30, 2011, the BCI and Windsor Locks facilities sold 287.7 billion lbs of steam as compared to 275.3 billion lbs of steam in the comparable period of 2010. During the quarter ended June 30, 2011, operations at the EFW facility generated 135.0 billion lbs of steam for the BCI facility as compared to nil in the same period in 2010.

For the quarter ended June 30, 2011, energy / steam revenue in the Thermal Energy division totalled $9.7 million, as compared to $11.1 million during the same period in 2010, a decrease of $1.4 million, or 13%. As natural gas expense is a significant revenue driver and component of operating expenses, the division compares ‘net energy sales revenue’ (energy sales revenue less natural gas expense) as a more appropriate measure of the division’s results. For the quarter ended June 30, 2011, net energy / steam sales revenue at the Thermal Energy division totalled $4.8 million, as compared to $5.3 million during the same period in 2010, a decrease of $0.6 million, primarily arising from the termination of the previous power purchase agreements in effect until April 2010 at the Windsor Locks facility and the weaker U.S. dollar.

The decrease in revenue from energy / steam sales was primarily due to a decrease of $3.2 million at the Windsor Locks facility as a result of decreased energy rates, in part due to a lower average landed price per mmbtu for natural gas and the change in operating model of the facility, partially offset by an increase of $2.4 million at the Windsor Locks facility due to increased production and an increase of $0.1 million at the Sanger facility as a result of the change in energy pricing and production as compared to the same period in 2010. The decrease in revenue was partially offset by $0.2 million at the EFW facility as a result of increased production of energy, as compared to the same period in 2010. The natural gas expense at the Sanger and Windsor Locks facilities is discussed in detail below. The division reported decreased energy sales revenue of $0.6 million from operations as a result of the weaker U.S. dollar, as compared to the same period in 2010.

Revenue from waste disposal sales for the quarter ended June 30, 2011 totalled $4.3 million, as compared to $0.1 million during the same period in 2010. The increase was a result of the EFW facility shutdown in the comparable period of 2010.

Other revenue for the quarter ended June 30, 2011 totalled $0.3 million, consistent with the same period in 2010.

For the quarter ended June 30, 2011, fuel costs at Sanger and Windsor Locks totalled U.S $5.1 million, consistent with the same period in 2010.³ The overall natural gas expense at the Windsor Locks facility decreased U.S. $0.2 million (4%), primarily the result of a 19% decrease in the average landed cost of natural gas per mmbtu, partially offset by an 18% increase in volume of natural gas consumed, as compared to the same period in 2010. The average landed cost of natural gas at the Windsor Locks facility during the quarter was U.S. $4.19 per mmbtu. This was partially offset by an increase in the natural gas expense at Sanger of U.S. $0.1 million (12%), primarily the result of a 6% increase in the average landed cost of natural gas per mmbtu, as well as a 6% increase in the volume of natural gas consumed as compared to the same period in 2010. The average landed cost of natural gas at the Sanger facility during the quarter was U.S. $4.83 per mmbtu. The division reported decreased fuel expenses of $0.3 million as a result of the weaker U.S. dollar as compared to the same period in 2010.

For the quarter ended June 30, 2011, operating expenses, excluding fuel costs at Windsor Locks and Sanger, totalled $5.0 million, as compared to $4.9 million during the same period in 2010, an increase of $0.6 million. The increase in operating expenses for the quarter was primarily due to $2.2 million in increased operating costs at the EFW facility resulting from the outage at the facility in 2010 partially offset by $1.0 million of reduced natural gas costs at BCI as a result of the EFW facility generating more steam and $0.3 million of reduced operating costs at the LFG facilities partially offset as compared to the same period in 2010. Operating expenses in the comparable period included costs of $0.2 million associated with the pursuit of various growth and development activities. The division reported decreased expenses of $0.2 million from U.S. operations as a result of the weaker U.S. dollar as compared to the same period in 2010.

For the quarter ended June 30, 2011, the Thermal Energy division’s operating profit totalled $4.2 million, as compared to $1.7 million during the same period in 2010, representing an increase of $2.6 million or 153%. Operating profit in the Thermal Energy division exceeded expectations for the quarter ended June 30, 2011, primarily due to better than expected earnings at the Windsor Locks facility as a result of improved energy pricing.

Divisional Outlook – Thermal Energy

The capital upgrade completed at the EFW facility is expected to continue to result in higher throughput and lower operating costs at the facility in the third quarter of 2011 consistent with the results experienced in the first half of 2011. APCo estimates that the upgrade resulted in higher earnings from operations of approximately $3.6 million in the first two quarters of 2011 as compared to the same period in 2010.

APCo anticipates that the Sanger facility should meet expectations for the third quarter of 2011 and be in line with 2010 results.

APCo Thermal Energy division’s Windsor Locks facility will continue to sell a portion of its electricity capacity and all of its steam capacity to the industrial host with the balance of the electrical capacity available to be sold either into the ISO NE day-ahead market or to industrial customers through the Energy Services Business. It is anticipated that performance during the third quarter of 2011 will be in line with expectations.

Algonquin has completed preliminary engineering for a repowering project at the Windsor Locks facility and is in negotiations with the steam host regarding this project. See APCo Development Division – Windsor Locks for further discussion on the potential repowering project.

APCo: Development Division

Current Development Projects

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		Expected Year of Commissioning	PPA Term		Production MWhr
Amherst Island (Ontario)¹		75	$	230m	2014		25		247,000
St. Damase (Quebec)²		24	$	70m	2013		20		86,000
Val Eo (Quebec)²		24	$	70m	2015		20		66,000
Morse (Saskatchewan) ³^, ⁴		25	$	70m	2013		20		93,000
St. Leon II²		17	$	30m	2012		25		58,000

Total		165	$	470m					550,000

Notes:

1	FIT contract awarded

2	PPA signed

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”).

St. Leon II

In July 2011, APUC announced the execution of a 25-year power purchase agreement with Manitoba Hydro in respect of a 16.5 MW expansion of APUC’s existing St. Leon wind energy project located in the Province of Manitoba.

In the first full year of production following commissioning, APUC anticipates generating annual gross revenues of $3.8 million. This project is expected to produce approximately 56,000 MWhrs annually. Rates paid under the power purchase agreement are subject to a partial inflation adjustment that will be applied annually. The expansion will be comprised of 10 Vestas V82-1.65 MW wind turbines, which already have been manufactured and are awaiting shipment to the site from a U.S. storage location. Permitting for the expansion project was completed in 2010 with construction expected to commence in the third quarter of 2011; commissioning of the expansion project is expected to occur in first quarter of 2012 with total forecast capital costs of $29.5 million.

Amherst Island

The Amherst Island Wind Project is located on Amherst Island in the village of Stella, approximately 25 kilometres southwest of Kingston, Ontario. The 75 MW project was awarded a FIT contract by the OPA as part of the second round of the Ontario Power Authority’s (“OPA”) Feed-in Tariff (“FIT”) program.

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. The FIT contract stated that the OPA had the option to terminate the FIT contract until the OPA had issued a Notice to Proceed (“NTP”) and APCo had paid the incremental security required by the NTP.

APCo exercised this option on August 9, 2011. As required by the waiver, APCo intends to submit a domestic content plan by October 14, 2011 and provide a statutory declaration regarding equipment supply commitments by November 30, 2011. APCo expects to complete the waiver requirements within the time frames set out in the waiver.

The project is currently contemplated to use more efficient Class III wind turbine generator technology and will be developed by APCo. APCo forecasts that the available wind resource could produce approximately 247 GWhr of power annually, depending upon the final turbine selection for the project. Funding for the total capital costs, currently estimated to be $230 million, 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 submission of the renewable energy application is targeted for the summer of 2012. Construction will commence shortly following the approval of the application and is expected to take 12 to 18 months.

Quebec Community Wind Projects

In 2010, APCo worked with Société en Commandite Val-Éo, a cooperative with a development project located in the Lac Saint-Jean region of Quebec, and the community of Saint-Damase to submit proposals into Hydro Quebec’s 250 MW wind Request for Proposal. On December 20, 2010, both projects were awarded power purchase contracts that stipulate the use of ENERCON turbines.

Saint-Damase

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. The first 24 MW phase of the project is expected to be comprised of twelve generators, producing approximately 86,000 MWhr annually. Construction of the first 24 MW phase of the project is estimated to begin in early 2013 with a commercial operations date in late 2013.

The interest of APUC in the project is subject to final negotiations with the municipality but, in any event, 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 studies of flora and fauna and the public consultation process are ongoing. In July 2011, meetings were conducted with participating landowners in addition to an open house to obtain additional community feedback. All major environmental authorizations are targeted for completion by the end of 2012.

Val-Éo

The Val-Éo Wind Project is located in the local municipality of Saint-Gédéon de Grandmont, which is within the regional municipality of Lac-Saint-Jean-Est. The project proponents include the Val-Éo wind cooperative formed by community based landowners and APCo. The first 24 MW phase of the project is expected to be comprised of eight generators, producing approximately 66,000 MWhr annually. Construction of the first 24 MW phase of the project is expected to begin in early 2015 with commercial operations occurring in late 2015.

The interest of APUC in the project is subject to final negotiations with the 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 met, 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 with all major authorizations targeted for completion by the end of 2012.

Morse Wind Project

The Morse Wind Project is composed of three contiguous projects amounting to 25 MW in total generating capacity. APCo executed an asset purchase agreement with Kineticor to acquire assets related to two adjacent 10 MW wind energy development projects in Saskatchewan and a further 5 MW was developed by Algonquin independently.

All of the Morse Projects were selected by SaskPower for award of PPAs in accordance with the SaskPower Green Options Partners Program. Two 10 MW PPA’s were awarded in May 2010 and a further 5 MW in June of this year. Upon SaskPower’s approval and execution of the Kineticor PPAs, Kineticor will then assign the PPAs to APCo. All three of the projects are expected to be completed in late 2013.

The Morse Projects are to be constructed near Morse, Saskatchewan, approximately 180 km west of Regina. It is contemplated that they will have additional land under lease or option in order to facilitate future expansion.

The total annual energy production for the Morse Projects is estimated to be 93,000 MWhr. The capital cost to construct the Morse Projects is currently estimated to be $65-$70 million, inclusive of acquisition costs. The first year PPA rate is set at $101.98 per MWhr 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.

Red Lily II Wind Project

APCo has secured additional land options related to property around the Red Lily I project to facilitate a 106 MW expansion (“Red Lily II”). The viability of the expanded project will be conditional upon a review of the actual operating results from Red Lily I. During the first quarter of 2010, APCo responded to the request for quotations issued by SaskPower by submitting requested information pertaining to Red Lily II.

Windsor Locks Repowering

The Windsor Locks Facility is a 54 MW natural gas power generating station located in Windsor Locks, Connecticut. This Facility delivers 100% of its steam capacity and a portion of its electrical generating capacity to Ahlstrom pursuant to the energy services agreement (“ESA”).

APCo has completed preliminary engineering and environmental permitting work for the installation of a 14.2 MW combustion gas turbine which is more appropriately sized to meet the electrical and steam requirements of Ahlstrom. The total expected capital cost for this project is estimated at approximately U.S. $25 million. APCo believes it is eligible to receive a one-time non-recurring grant from the State of Connecticut equivalent to U.S. $450/KW to a maximum of U.S. $6.6 million which would offset the cost of such re-powering. An additional benefit of the State of Connecticut grant program is that local distribution charges for natural gas used by the new turbine are waived, with an estimated benefit to the Windsor Locks Facility of approximately $500,000/year. In addition to installing the new gas turbine, APCo would expect to continue to operate the existing electrical generating equipment in the ISO NE market. APCo also believes that this project would qualify for a combined heat and power Investment Tax Credit (“ITC”) sponsored by the U.S. Federal Government. The benefit of the ITC grant is approximately U.S. $1 million in addition to the Connecticut DPUC grant.

APCo has entered into negotiations with Ahlstrom to amend and extend the terms of the existing ESA. The new terms would be based on the economics of a smaller, more appropriately sized, combustion gas turbine. APCo’s decision to make any investment in new capital for this site will be based on an assessment of the incremental earnings against such additional investment and in the context of any extension to the existing ESA with Ahlstrom. The existing generation equipment will be maintained to function as a capacity and reserve resource to be bid into the ISO NE market.

LOGO


	Six months ended June 30						Six months ended June 30
	2011			2010			2011			2010
Number of
Wastewater connections								36,535			35,060
Wastewater treated (millions of gallons)								1,000			1,000

Water distribution connections								37,930			37,357
Water sold (millions of gallons)								2,400			2,300

		U.S. $			U.S. $			Can $			Can $
NBV of Assets for regulatory purposes (U.S. $)		158,381			152,069

Revenue
Wastewater treatment	$	11,618		$	9,555		$	11,341		$	9,944
Water distribution		9,839			7,226			9,604			7,520
Other Revenue		317			278			321			289

	$	21,774		$	17,059		$	21,266		$	17,753
Expenses
Operating expenses		(11,163	)		(10,463	)		(10,892	)		(10,908	)
Other income		190			10			186			11


Business Unit operating profit	$	10,801		$	6,606		$	10,560		$	6,856

Liberty Water is committed to being a leading utility provider of safe, high quality and reliable water and wastewater services while providing stable and predictable earnings from its utility operations. Liberty Water has presented the division’s results in both the reporting currency and its functional currency. Liberty Water believes that since the division’s operations are entirely in the U.S., it is useful to show the results in Liberty Water’s functional currency without the impact of foreign exchange.

Liberty Water reports total connections, inclusive of vacant connections rather than customers. Liberty Water had 36,535 wastewater connections as at June 30, 2011, as compared to 35,060 as at June 30, 2010, an increase of 1,475 connections in the period or 4.2%. Liberty Water had 37,930 water distribution connections as at June 30, 2011, as compared to 37,357 as at June 30, 2010, representing an increase of 573 in the period or 1.5%. Total connections include approximately 2,200 vacant wastewater connections and 1,500 vacant water distributions connections as at June 30, 2011. Liberty Water’s change in water distribution and wastewater treatment customer base during the period is primarily due to modest customer growth at Liberty Water’s facilities.

Liberty Water has investments in regulatory assets with a net book value of U.S. $158.4 million across four states as at June 30, 2011, as compared to U.S. $152.1 million as at June 30, 2010.

2011 Six Month Operating Results

During the six months ended June 30, 2011, Liberty Water provided approximately 2.4 billion U.S. gallons of water to its customers, treated approximately 1.0 billion U.S. gallons of wastewater and sold approximately 125 million U.S. gallons of treated effluent.

For the six months ended June 30, 2011, Liberty Water’s revenue totalled U.S. $21.8 million as compared to U.S. $17.1 million during the same period in 2010, an increase of U.S. $4.7 million or 28%. The increased revenues were primarily due to the implementation of rate increases from rate cases filed with state legislators over the past two years. Rate cases ensure that a particular facility has the opportunity to recover its operating costs and earn a fair and reasonable return on its capital investment as allowed by the regulatory authority under which the facility operates.

Revenue from wastewater treatment totalled U.S. $11.6 million, as compared to U.S. $9.6 million during the same period in 2010, an increase of U.S. $2.1 million or 22%. The six month wastewater treatment revenue was impacted by increased revenue, primarily from the implementation of rate increases of U.S. $1.5 million at the LPSCo facility and U.S. $0.3 million at the Black Mountain facility as compared to the same period in 2010. In addition, revenue increased U.S. $0.3 million at nine wastewater treatment facilities primarily due to increased customer demand as compared to the same period in 2010.

Revenue from water distribution totalled U.S. $9.8 million, as compared to U.S. $7.2 million during the same period in 2010, an increase of U.S. $2.6 million or 36%. The six month water distribution revenue was impacted, primarily due to the implementation of rate increases of U.S. $1.7 million at the LPSCo facility, U.S. $0.5 million at the Rio Rico facility and U.S. $0.3 million at the Bella Vista facility as compared to the same period in 2010. In addition, revenue increased U.S. $0.1 million at seven water distribution facilities primarily due to increased customer demand as compared to the same period in 2010.

For the six months ended June 30, 2011, operating expenses totalled U.S. $11.2 million, as compared to U.S. $10.5 million during the same period in 2010. Overall expenses increased U.S. $0.7 million or 7% as compared to the same period in 2010. Operating expenses increased due to increased utilities, consumable and insurance expenses of U.S. $0.4 million and U.S. $0.3 million related to increased wages, salary and other operating costs as compared to the same period in 2010.

For the six months ended June 30, 2011, Liberty Water’s operating profit totalled U.S. $10.8 million as compared to U.S. $6.6 million in the same period in 2010, an increase of U.S. $4.2 million or 64%. Liberty Water’s operating profit exceeded expectations for the six months ended June 30, 2011.

Measured in Canadian dollars, for the six months ended June 30, 2011, Liberty Water’s revenue totalled $21.3 million, as compared to $17.8 million during the same period in 2010. Revenue from wastewater treatment totalled $11.3 million, as compared to $9.9 million during the same period in 2010, an increase of $1.4 million. Revenue from water distribution totalled $9.6 million, as compared to $7.5 million in the same period in 2010, an increase of $2.1 million. Liberty Water reported decreased revenue from operations of $1.2 million in the first six months of 2011 as a result of the weaker U.S. dollar as compared to the same period in 2010.

Measured in Canadian dollars, for the six months ended June 30, 2011, operating expenses totalled $10.9 million, consistent with same period in 2010. Liberty Water reported lower expenses from operations of $0.7 million as a result of the weaker U.S. dollar, as compared to the same period in 2010.

For the six months ended June 30, 2011, Liberty Water’s operating profit totalled $10.6 million as compared to $6.9 million in the same period in 2010, an increase of $3.7 million. Liberty Water’s operating profit exceeded expectations for the six months ended June 30, 2011.


	Three months ended June 30						Three months ended June 30
	2011			2010			2011			2010
Number of
Wastewater treated (millions of gallons)								500			500
Water sold (millions of gallons)								1,500			1,400

		U.S. $			U.S. $			Can $			Can $
Revenue
Wastewater treatment	$	5,839		$	4,914		$	5,652		$	5,085
Water distribution		5,864			4,152			5,676			4,297
Other Revenue		151			122			154			121

	$	11,854		$	9,188		$	11,482		$	9,503

Expenses
Operating expenses		(5,661	)		(5,279	)		(5,471	)		(5,480	)
Other income		79			—			77			—


Business Unit operating profit	$	6,272		$	3,909		$	6,088		$	4,023

2011 Second Quarter Operating Results

During the quarter ended June 30, 2011, Liberty Water provided approximately 1.5 billion U.S. gallons of water to its customers, treated approximately 500 million U.S. gallons of wastewater and sold approximately 85 million U.S. gallons of treated effluent.

For the quarter ended June 30, 2011, Liberty Water’s revenue totalled U.S. $11.9 million as compared to U.S. $9.2 million during the same period in 2010, an increase of U.S. $2.7 million or 29%. The increased revenues were primarily due to the implementation of rate increases from rate cases filed with state legislators over the past two years.

Revenue from wastewater treatment totalled U.S. $5.8 million, as compared to U.S. $4.9 million during the same period in 2010, an increase of U.S. $0.9 million or 19%. The second quarter wastewater treatment revenue increased primarily from the implementation of rate increases of U.S. $0.7 million at the LPSCo facility and U.S. $0.2 million at the Black Mountain facility as compared to the same period in 2010. In addition, revenue increased U.S. $0.1 million at six wastewater treatment facilities primarily due to increased customer demand as compared to the same period in 2010.

Revenue from water distribution totalled U.S. $5.9 million, as compared to U.S. $4.2 million during the same period in 2010, an increase of U.S. $1.7 million or 40%. The second quarter water distribution revenue increased primarily due to the implementation of rate increases of U.S. $1.1 million at the LPSCo facility, U.S. $0.4 million at the Rio Rico facility and U.S. $0.3 million at the Bella Vista facility as compared to the same period in 2010.

For the quarter ended June 30, 2011, operating expenses totalled U.S. $5.7 million, as compared to U.S. $5.3 million during the same period in 2010. Overall expenses increased U.S. $0.4 million or 8% as compared to the same period in 2010. Operating expenses increased due to increased utilities, consumable, property tax and insurance expenses of U.S. $0.2 million and U.S. $0.1 million related to wages, salary and other operating costs as compared to the same period in 2010.

For the quarter ended June 30, 2011, Liberty Water’s operating profit totalled U.S. $6.3 million as compared to U.S. $3.9 million in the same period in 2010, an increase of U.S. $2.4 million or 62%. Liberty Water’s operating profit exceeded expectations for the three months ended June 30, 2011.

Measured in Canadian dollars, for the quarter ended June 30, 2011, Liberty Water’s revenue totalled $11.5 million, as compared to $9.5 million during the same period in 2010. Revenue from wastewater treatment totalled $5.7 million, as compared to $5.1 million during the same period in 2010, an increase of $0.6 million. Revenue from water distribution totalled $5.7 million, as compared to $4.3 million in the same period in 2010, an increase of $1.4 million. Liberty Water reported decreased revenue from operations of $0.7 million in the second quarter of 2011 as a result of the weaker U.S. dollar as compared to the same period in 2010.

Measured in Canadian dollars, for the quarter ended June 30, 2011, operating expenses totalled $5.5 million, consistent with same period in 2010. Liberty Water reported lower expenses from operations of $0.4 million as a result of the weaker U.S. dollar, as compared to the same period in 2010.

For the quarter ended June 30, 2011, Liberty Water’s operating profit totalled $6.1 million as compared to $4.0 million in the same period in 2010, an increase of $2.1 million. Liberty Water’s operating profit exceeded expectations for the three months ended June 30, 2011.

Outlook – Liberty Water

Liberty Water provides water distribution and wastewater collection and treatment services, primarily in the southern and southwestern U.S. where communities have experienced periods of long-term growth and that management believes provides continuing future opportunities for organic growth. Liberty Water expects continuing modest customer growth in 2011.

Revenue increases from rate cases completed in Arizona and Texas are anticipated to contribute additional revenue in Liberty Water in the third quarter of 2011 as compared to the same period in 2010. Liberty Water attributes approximately U.S. $4.0 million of the revenue increases in the six months ended June 30, 2011 to the impact of completed rate cases and anticipates that this will continue in the third quarter. In addition, the Bella Vista rate case was completed during the first quarter, with new rates effective April 1, 2011, and is expected to contribute an additional U.S. $0.8 million in revenue on an annualized basis.

Liberty Water continues to work with key stakeholders, including regulators, to help manage issues related to the issuance of decisions in its rate cases in a timely manner.

At an Arizona Corporate Commission (“ACC”) open meeting held on December 10, 2010 to consider the LPSCo recommended order (“ROO”), it was determined that the rate increase will be phased in with 50% of the increase being applied in the first 6 months, increasing to 75% for 6 months thereafter, and 100% of the rate increase being realized from month 12 forward. LPSCo is entitled to recover the foregone revenue from the phase in of rates including carrying charges under terms to be finalized in a ROO for a second phase of the LPSCo rate case. A hearing on the 2nd phase was held on June 27, 2011 where all parties agreed that the recovery of phased in amounts shall be at the regulatory weighted average cost of capital determined in the rate case. This recovery is expected to begin in Q4 2011 and commence for 18 months, or until LPSCo is made whole for the foregone revenue.

LOGO


	Six months ended June 30					Six months ended June 30
	2011			2010		2011			2010
Number of Customer Accounts
Residential							41,260			—
Commercial - Small							5,500			—
Commercial – Large							55			—
Total Customer Accounts							46,815

Customer Usage (MWhr)
Residential							160,300			—
Commercial – Small							83,800			—
Commercial – Large							68,100			—
Total Customer Usage (MWhr)							312,200

		U.S. $			U.S. $		Can $			Can $
Assets for regulatory purposes (U.S. $)		137,204			—

Revenue
Utility energy sales and distribution	$	40,314		$	—	$	39,419		$	—
Less:
Cost of Sales – Fuel *		(23,590	)		—		(23,064	)

	$	16,724		$	—	$	16,355		$	—

Expenses
Operating expenses		(7,492	)		—		(7,316	)		—
Other income		—			—		—			—


Business Unit operating profit**	$	9,232		$	—	$	9,039		$	—

*	Cost of Sales – Energy consists of energy purchases.

**	Represents 100% of investment in the California Utility.

Liberty Energy’s business strategy is to build its nationwide portfolio of electric and natural gas distribution utilities and electric transmission assets, sharing certain common infrastructure between utilities to support best-in-class customer care for its utility ratepayers and building constructive positive regulatory relationships.

Liberty Energy’s investment as at June 30, 2011 is a 50.001% controlling interest in Liberty Energy (California). On April 29, 2011, it was announced that Emera has agreed to sell its 49.999% ownership interest to Liberty Energy, with closing of such transaction subject to regulatory approval. As a result, upon completion of the transaction, Liberty Energy will own 100% of Liberty Energy (California). Liberty Energy believes that consolidating 100% of the California Utility under the Liberty Energy brand will provide the flexibility and control necessary to fully implement its approach to meeting the needs of customers, employees and regulators.

Liberty Energy has presented the division’s results in both the reporting currency and its functional currency. Liberty Energy believes that since the division’s operations are entirely in the U.S., it is useful to show the results in Liberty Energy’s functional currency without the impact of foreign exchange.

Liberty Energy reports active connections, exclusive of vacant connections rather than total connections. Liberty Energy had approximately 41,260 residential customer accounts and 5,550 commercial customer accounts, as at June 30, 2011 as compared to nil during the same period in 2010.

2011 Six Month Operating Results

As Liberty Energy (California) was acquired on January 1, 2011 there are no comparable results for 2010. During the six months ended June 30, 2011, Liberty Energy’s customer usage totalled approximately 312,100 MWhr of energy.

For the six months ended June 30, 2011, Liberty Energy’s revenue from utility energy sales totalled U.S. $40.3 million. The purchase of energy by Liberty Energy (California) 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 energy sales revenue’ (energy sales revenue less energy purchases) as a more appropriate measure of the division’s results. For the six months ended June 30, 2011, net utility energy sales revenue for Liberty Energy totalled U.S. $16.7 million.

For the six months ended June 30, 2011, energy purchases for Liberty Energy totalled U.S $23.6 million. During the six months, Liberty Energy (California) purchased approximately 312,000 MWhr of energy at rates averaging U.S. $75.6 per MWhr.

For the six months ended June 30, 2011, operating expenses, excluding energy purchases, totalled U.S. $7.5 million.

For the six months ended June 30, 2011, Liberty Energy’s operating profit totalled U.S. $9.2 million. Liberty Energy’s operating profit exceeded expectations for the six months ended June 30, 2011 due to higher customer count, customer energy usage and baseline rates.

Measured in Canadian dollars, for the six months ended June 30, 2011, Liberty Energy’s revenue from energy sales totalled $39.4 million. As the purchase of energy by Liberty Energy (California) is a significant revenue driver and component of operating expenses, the division compares ‘net energy sales revenue’ (energy sales revenue less energy purchases) as a more appropriate measure of the division’s results. For the six months ended June 30, 2011, net energy sales revenue for Liberty Energy totalled $16.4 million.

Measured in Canadian dollars, for the six months ended June 30, 2011, energy purchases for Liberty Energy totalled $23.1 million.

Measured in Canadian dollars, for the six months ended June 30, 2011, operating expenses excluding energy purchases totalled $7.3 million.

For the six months ended June 30, 2011, Liberty Energy’s operating profit totalled $9.0 million. Liberty Energy’s operating profit exceeded expectations for the six months ended June 30, 2011.


	Three months ended June 30					Three months ended June 30
	2011			2010		2011			2010
Customer Usage (MWhr)
Residential							69,800			—
Commercial – Small							37,700			—
Commercial – Large							29,300			—
Total Customer Usage (MWhr)							136,800

		U.S. $			U.S. $		Can $			Can $
Revenue
Utility energy sales and distribution	$	17,133		$	—	$	16,569		$	—
Less:
Cost of Sales – Fuel *		(10,157	)		—		(9,822	)

	$	6,976		$	—	$	6,747		$	—

Expenses
Operating expenses		(3,954	)		—		(3,576	)		—
Other income		—			—		—			—


Business Unit operating profit**	$	3,022		$	—	$	3,171		$	—

*	Cost of Sales – Energy consists of energy purchases.

**	Represents 100% of investment in the California Utility.

2011 Second Quarter Operating Results

As Liberty Energy (California) was acquired on January 1, 2011 there are no comparable results for 2010. For the quarter ended June 30, 2011, Liberty Energy’s customer usage totalled approximately 136,800 MWhr of energy.

For the quarter ended June 30, 2011, Liberty Energy’s revenue from utility energy sales totalled U.S. $17.1 million. The purchase of energy by Liberty Energy (California) 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 energy sales revenue’ (energy sales revenue less energy purchases) as a more appropriate measure of the division’s results. For the quarter ended June 30, 2011, net utility energy sales revenue for Liberty Energy totalled U.S. $7.0 million.

For the quarter ended June 30, 2011, energy purchases for Liberty Energy totalled U.S $10.2 million. During the quarter, Liberty Energy (California) purchased approximately 136,800 MWhr of energy at rates averaging U.S. $74.2 per MWhr.

For the quarter ended June 30, 2011, operating expenses, excluding energy purchases, totalled U.S. $10.2 million.

For the quarter ended June 30, 2011, Liberty Energy’s operating profit totalled U.S. $3.0 million. Liberty Energy’s operating profit met expectations for the three months ended June 30, 2011.

Measured in Canadian dollars, for the quarter ended June 30, 2011, Liberty Energy’s revenue from energy sales totalled $16.6 million. As the purchase of energy by Liberty Energy (California) is a significant revenue driver and component of operating expenses, the division compares ‘net energy sales revenue’ (energy sales revenue less energy purchases) as a more appropriate measure of the division’s results. For the quarter ended June 30, 2011, net energy sales revenue for Liberty Energy totalled $6.7 million.

Measured in Canadian dollars, for the quarter ended June 30, 2011, energy purchases for Liberty Energy totalled $9.8 million.

Measured in Canadian dollars, for the quarter ended June 30, 2011, operating expenses excluding energy purchases totalled $3.6 million.

For the quarter ended June 30, 2011, Liberty Energy’s operating profit totalled $3.2 million as compared to nil in the same period in 2010. Liberty Energy’s operating profit met expectations for the three months ended June 30, 2011.

Outlook – Liberty Energy

Liberty Energy expects modest customer growth in 2011. Liberty Energy anticipates that Liberty Energy (California) should exceed expectations for the third quarter of 2011.

On April 29, 2011, Liberty Energy has announced it had reached an agreement with Emera to acquire the interest in the California Utility held by Emera. Emera agreed to sell its 49.999% direct ownership in Liberty Energy (California), with closing of such transaction subject to regulatory approval. As consideration Emera will receive 8.211 million APUC shares in two tranches. Approximately half of the shares will be issued following regulatory approval of the Liberty Energy (California) ownership transfer and the balance of the shares will be issued following completion of Liberty Energy (California)’s first rate case, expected to be completed in the latter half of 2012.

Liberty Energy has entered into agreements to acquire three additional utilities, discussed in further detail below, which currently provide electric and natural gas distribution services to approximately 210,000 customers in New Hampshire, Missouri, Iowa and Illinois.

On December 9, 2010, Liberty Energy’s wholly owned subsidiary Liberty Energy (New Hampshire) Inc entered into agreements to acquire all issued and outstanding shares of Granite State Electric Company (“Granite State”), a regulated New Hampshire electric utility, and EnergyNorth Natural Gas Inc. (“EnergyNorth”), a regulated New Hampshire natural gas utility for a total purchase price of U.S. $285 million. Granite State and EnergyNorth are anticipated to have regulatory assets at closing of approximately U.S. $72.0 million and U.S. $178.8 million, respectively.

Granite State provides electric service to over 43,000 customers in 21 communities in New Hampshire. EnergyNorth provides natural gas services to over 83,000 customers in five counties and 30 communities in New Hampshire. Closings of the transactions are subject to certain conditions including state and federal regulatory approval, and are expected to occur in the fall of 2011. Liberty Energy (New Hampshire) is actively pursuing such approvals with the New Hampshire Public Utilities Commission (NHPUC). Following the preliminary hearing held the NHPUC on April 20, 2011, the parties reached agreement on a procedural schedule establishing final hearings (if necessary) for January 2012.

On May 13, 2011, Liberty Energy had entered into an agreement with Atmos to acquire the Midwest Gas Utilities located in Missouri, Iowa, and Illinois. Total purchase price for the Midwest Gas Utilities is approximately U.S. $124 million, subject to certain working capital and other closing adjustments. Liberty Energy expects to acquire assets for rate making purposes of approximately $112 million, representing a purchase price multiple of 1.106x. The Midwest Gas Utilities currently provide natural gas local distribution service to approximately 84,000 customers (57,000 in Missouri, 23,000 in Illinois, and 4,000 in Iowa). Closing of the transaction is subject to certain conditions including state and federal regulatory approval, and is expected to occur in 2012.

Financing of these acquisitions is expected to occur simultaneously with the closing of the transactions. Liberty Energy is targeting a capital structure of not more than 50% debt to total capitalization consistent with investment grade utilities.

APUC: Corporate


	Three months ended June 30						Six months ended June 30
	2011			2010			2011			2010
Corporate and other expenses:
Administrative expenses		4,209			2,990			7,931			5,905
Loss on foreign exchange		63			404			98			366
Interest expense		7,426			5,966			15,441			12,031
Interest, dividend and other Income		(734	)		(852	)		(1,464	)		(1,677	)
Loss on derivative financial instruments		960			3,052			531			2,140
Income tax expense (recovery)		584			(285	)		31			(2,435	)

2011 Six Month Corporate and Other Expenses

During the six months ended June 30, 2011, management and administrative expenses totalled $7.9 million, as compared to $5.9 million in the same period in 2010. The expense increase in the six months ended June 30, 2011 primarily results from increased salaries and bonuses related to the management and administering APUC’s operations, stock option expense, franchise taxes and other costs as compared to the same period in 2010.

For the six months ended June 30, 2011, interest expense totalled $15.4 million as compared to $12.0 million in the same period in 2010. Interest expense increased primarily as a result of higher levels of borrowings resulting from the acquisition of Liberty Energy (California) and higher long term rates associated with Liberty Water’s long term debt private placement compared to the short term rates that are associated with a short term bank credit facility. In addition, there was higher average variable interest expense, partially offset by lower average borrowings and the conversion of the Series 1A Debentures, as compared to the same period in 2010.

For the six months ended June 30, 2011, interest, dividend and other income totalled $1.5 million, as compared to $1.7 million in the same period in 2010. Interest, dividend and other income primarily consists of dividends from APUC’s share investment in the Kirkland and Cochrane facilities.

Gain on derivative financial instruments consists of realized and unrealized mark-to-market losses on foreign exchange forward contracts, interest rate swaps and forward energy contracts during the first and second quarters of 2011. The unrealized portion of any mark-to-market gains or losses on derivative instruments does not impact APUC’s current cash position.

An income tax expense of $30 was recorded in the six months ended June 30, 2011, as compared to a recovery of $2.4 million during the same period in 2010. The primary reason for the increase is related to higher pre-tax earnings in 2011 compared to the same period a year ago. The future income tax recovery for the six months ended June 30, 2011 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, and the reversal of deferred tax liabilities offset against the utilization of the carry forward losses and increase in valuation allowance.

2011 Second Quarter Corporate and Other Expenses

During the quarter ended June 30, 2011, management and administrative expenses totalled $4.2 million, as compared to $3.0 million in the same period in 2010. The expense increase in the three months ended June 30, 2011 primarily results from the reasons discussed in “Six Month Corporate and Other Expenses” above as compared to the same period in 2010.

For the quarter ended June 30, 2011, interest expense totalled $7.4 million as compared to $6.0 million in the same period in 2010. Interest expense increased primarily as a result of higher levels of borrowings resulting from the acquisition of Liberty Energy (California) and higher long term rates associated with Liberty Water’s long term debt private placement compared to the short term rates that are associated with a short term bank credit facility. In addition, there was higher average variable interest expense, partially offset by lower average borrowings and the conversion of the Series 1A Debentures, as compared to the same period in 2010.

For the quarter ended June 30, 2011, interest, dividend and other income totalled $0.7 million, as compared to $0.9 million in the same period in 2010. Interest, dividend and other income primarily consists of dividends from APUC’s share investment in the Kirkland and Cochrane facilities.

Gain on derivative financial instruments consists of realized and unrealized mark-to-market losses on foreign exchange forward contracts, interest rate swaps and forward energy contracts during the quarter. The unrealized portion of any mark-to-market gains or losses on derivative instruments does not impact APUC’s current cash position.

An income tax expense of $0.6 million was recorded in the three months ended June 30, 2011, as compared to a recovery of $0.3 million during the same period in 2010. The primary reason for the increase is related to higher pre-tax earnings in 2011 compared to the same period a year ago. The future income tax recovery for the six months ended June 30, 2011 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, and the reversal of deferred tax liabilities offset against the utilization of the carry forward losses and increase in valuation allowance.

NON-GAAP PERFORMANCE MEASURES

Reconciliation of Adjusted EBITDA to net earnings

EBITDA is a non-GAAP metric used by many investors to compare companies on the basis of ability to generate cash from operations. APUC uses these calculations to monitor the amount of cash generated by APUC as compared to the amount of dividends paid by APUC. APUC uses Adjusted EBITDA to assess the operating performance of APUC without the effects of depreciation and amortization expense which are non-cash and derived from a number of non-operating factors, accounting methods and assumptions. APUC believes that presentation of this measure will enhance an investor’s understanding of APUC’s operating performance. Adjusted EBITDA is not intended to be representative of cash provided by operating activities or results of operations determined in accordance with GAAP.

The following table is derived from and should be read in conjunction with the unaudited Interim 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 June 30					Six months ended June 30
	2011		2010			2011		2010
Net earnings (loss) attributable to Shareholders	$	7,330	$	(2,471	)	$	12,346	$	1,060
Add (deduct):

Net earnings attributable to the non controlling interest		743		146			2,647		211
Income tax expense (recovery)		584		(285	)		31		(2,435	)
Interest expense		7,426		5,966			15,441		12,031
Acquisition Costs		259		308			1,014		352
Loss (Gain) on derivative financial instruments		960		3,052			531		2,140
Loss (gain) on foreign exchange		63		404			98		366
Amortization		10,849		11,618			23,021		22,893

Adjusted EBITDA	$	28,214	$	18,738		$	55,129	$	36,618

For the six months ended June 30, 2011, Adjusted EBITDA totalled $55.1 million as compared to $36.6 million, a net increase of $18.5 million or 51% as compared to the same period in 2010. For the quarter ended June 30, 2011, Adjusted EBITDA totalled $28.2 million as compared to $18.7 million, a net increase of $9.5 million or 51% as compared to the same period in 2010.

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 June 30, 2011			Six months ended June 30, 2011
	(millions)			(millions)
Comparative Prior Period Adjusted EBITDA	$	18.7		$	36.6

Significant Changes:
Acquisition of the California Utility		3.3			10.6
EFW facility		3.2			5.8
Liberty Water revenue increases primarily due to rate case approvals		2.4			4.0
St. Leon - primarily due to an increased wind resource		0.3			1.3
Hydro Renewable due to improved hydrology		3.5			3.6
Administration and management costs		(1.2	)		(2.0	)
Lower results from the weaker U.S. dollar		(0.5	)		(2.7	)
Tinker Hydro / ESB primarily due to lower energy demand		(0.4	)		(0.6	)
Windsor Locks – change in operating model		(0.5	)		(1.7	)
Other		(0.6	)		0.2


Current Period Adjusted EBITDA	$	28.2		$	55.1

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 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, energy forward contracts as well as to movements in foreign exchange rates on foreign currency denominated debt and working capital balances. APUC uses adjusted net earnings to assess the performance of APUC without the effects of gains or losses on derivatives as these are not reflective of the performance of the underlying business of APUC. APUC believes that analysis and presentation of net earnings or loss on this basis will enhance an investor’s understanding of the operating performance of APUC’s businesses. It is not intended to be representative of net earnings or loss determined in accordance with GAAP.

The following table is derived from and should be read in conjunction with the Interim Unaudited Consolidated Statement of Operations. This supplementary disclosure is intended to more fully explain disclosures related to adjusted net earnings and provides additional information related to the operating performance of APUC. Investors are cautioned that this measure should not be construed as an alternative to consolidated net earnings in accordance with GAAP.

The following table shows the reconciliation of net earnings to adjusted net earnings exclusive of these items:


	Three months ended June 30					Six months ended June 30
	2011		2010			2011		2010
Net earnings (loss) attributable to Shareholders	$	7,330	$	(2,471	)	$	12,346	$	1,060

Add:
Loss on derivative financial instruments, net of tax		698		2,102			401		1,474
Loss (gain) on foreign exchange, net of tax		63		404			98		366
Acquisition costs, net of tax		158		188			618		215


Adjusted net earnings	$	8,249	$	223		$	13,463	$	3,115

Adjusted net earnings per share	$	0.07	$	0.00		$	0.12	$	0.03

For the six months ended June 30, 2011, adjusted net earnings totalled $13.5 million as compared to adjusted net earnings of $3.1 million, an increase of $10.3 million as compared to the same period in 2010. The increase in adjusted net earnings in the six months ended June 30, 2011 is primarily due to increased earnings from operations, partially offset by increased interest and administrative expenses as compared to the same period in 2010.

For the three months ended June 30, 2011, adjusted net earnings totalled $8.3 million as compared to adjusted earnings of $0.2 million, an increase of $8.0 million as compared to the same period in 2010. The increase in adjusted net earnings in the three months ended June 30, 2011 is primarily due to increased earnings from operations, partially offset by increased interest and administrative expenses as compared to the same period in 2010.

SUMMARY OF PROPERTY, PLANT AND EQUIPMENT EXPENDITURES


	Three months ended June 30				Six months ended June 30
	2011		2010		2011		2010
APCo	(millions)		(millions)		(millions)		(millions)
Renewable Energy Division
Capital expenditures	$	1.1	$	0.7	$	2.0	$	0.9
Acquisition of operating entities		—		—		—		40.4

Total	$	1.1	$	0.7	$	2.0	$	41.3
Thermal Energy Division
Capital expenditures	$	0.3	$	6.1	$	0.1	$	9.9

Total	$	0.3	$	6.1	$	0.1	$	9.9
LIBERTY WATER
Capital Investment in regulatory assets	$	3.7	$	1.0	$	5.1	$	1.0
Acquisition of operating entities		—		—		—		2.0

	$	3.7	$	1.0	$	5.1	$	3.0
LIBERTY ENERGY
Capital Investment in regulatory assets	$	1.6	$	—	$	3.0	$	—
Acquisition of operating entities		1.3		—		99.4		—

	$	2.9	$	—	$	102.4	$	—
Consolidated (includes Corporate)
Capital expenditures	$	1.6	$	6.8	$	2.4	$	11.0
Capital investment in regulatory assets		5.3		1.0		8.1		1.0
Acquisition of operating entities		1.3		0.3		99.4		42.4

Total	$	8.2	$	8.1	$	109.9	$	54.4

APUC’s consolidated capital expenditures in the six months ended June 30, 2011 increased as compared to the same period in 2010 primarily due to the acquisition of the California Assets.

Property, plant and equipment expenditures for the remainder of the 2011 fiscal year are anticipated to be between $20 million and $23 million for ongoing operations, including approximately $4.0 million related to ongoing investments by Liberty Water, $1.5 million related to Liberty Energy’s share of ongoing investments at Liberty Energy (California), $10.5 million related to the APCo Thermal division, and $3.5 million related to the APCo Renewable Energy division. In addition APCo expects to invest approximately $25 million related to the development of the expansion to the St. Leon wind 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.

2011 Six Month Property Plant and Equipment Expenditures

During the six months ended June 30, 2011, APCo incurred net capital expenditures of $2.4 million, as compared to $11.0 million during the comparable period in 2010. APCo also invested $40.4 million to acquire operating assets/entities during the comparable period in 2010.

During the six months ended June 30, 2011, APCo Renewable Energy division’s capital expenditures were $2.0 million, as compared to $0.9 million in the comparable period in 2010. With the exception of a previously anticipated turbine overhaul project at the Tinker facility, there were no individual projects in excess of $0.5 million initiated in the current period. The APCo Renewable Energy division’s acquisition of operating assets in 2010 relate to the Tinker Assets located in New Brunswick and Maine.

During the six months ended June 30, 2011, APCo Thermal Energy division’s net capital expenditures were ($0.1) million, as compared to $9.9 million in the comparable period in 2010. The recovery in the six months primarily relates to proceeds from the sale of the turbine at the Crossroads facility. In the comparable period, the capital expenditures primarily relate to the EFW facility where major capital maintenance was underway.

During the six months ended June 30, 2011, Liberty Water invested maintenance capital of $5.1 million into regulatory assets, as compared to an investment of 1.0 in the comparable period. In the comparable period in 2010, Liberty Water acquired a water and wastewater utility near Galveston Texas for approximately $2.0 million.

During the six months ended June 30, 2011, Liberty Energy recorded capital expenditures of $3.0 million associated with the acquisition by Liberty Energy (California) of the California Utility. Liberty Energy invested $99.4 million to acquire the California Utility on January 1, 2011.

2011 Second Quarter Property Plant and Equipment Expenditures

During the quarter ended June 30, 2011, APCo incurred net capital expenditures of $1.6 million, as compared to $6.8 million during the comparable period in 2010.

During the quarter ended June 30, 2011, APCo Renewable Energy division’s capital expenditures were $1.1 million, as compared to $0.7 million in the comparable period in 2010. With the exception of a previously anticipated turbine overhaul project at the Tinker facility, there were no individual projects in excess of $0.5 million initiated in the current period.

During the quarter ended June 30, 2011, APCo Thermal Energy division’s net capital expenditures were $0.3 million, as compared to $6.1 million in the comparable period in 2010. In the comparable period, the capital expenditures primarily relate to the EFW facility where major capital maintenance was underway. During the quarter ended June 30, 2011, Liberty Water invested maintenance capital of $3.7 million into regulatory assets, as compared to an investment of $1.0 million in the comparable period.

During the quarter ended June 30, 2011, Liberty Energy recorded capital expenditures of $1.6 million associated with the acquisition by Liberty Energy (California) of the California Utility. Liberty Energy recorded an additional $1.3 million as a purchase price adjustment related to the acquisition of the California Utility on January 1, 2011.

Quebec Dam Safety Act

As a result of the dam safety legislation passed in Quebec (Bill C93), APCo’s Renewable Energy division is required to undertake technical assessments of eleven of the twelve hydroelectric facility dams owned or leased within the Province of Quebec. All eleven dam safety evaluations have now been completed. Out of these, nine remedial plans have been submitted to the Quebec government and two are undergoing options analysis by APCo. Eight remedial plans have been accepted by the Quebec government and one is still being reviewed. APCo has spent approximately $1.1 million to date on dam safety evaluations, engineering, permitting and civil works related to the Bill C93 requirements. APCo currently estimates further capital expenditures of approximately $17.1 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		2011		2012		2013		2014		2015+
Estimated Bill C-93 Capital Expenditures	$	17,100	$	300	$	5,500	$	5,500	$	3,000	$	2,800

The majority of these capital costs are associated with the Donnacona, St. Alban, Belleterre, and Mont-Laurier facilities.

•

The dam safety evaluation for the Mont Laurier facility was completed in 2008 and APCo’s proposed remediation plan has now been accepted by the Quebec government. APCo has been performing engineering and permitting since 2010 and is presently waiting for a Certificate of Authorization from the Quebec government before being able to proceed with the work. APCo anticipates completing the on-site remediation work in 2012.

•

In respect of the Donnacona facility, APCo completed the dam safety evaluation in 2007 and has been investigating alternative engineering designs to minimize the cost of the remediation work in 2012 and 2013. APCo is now pursuing a design that may result in a cost savings of 20% of the original estimates, representing a potential reduction in the above estimated costs of approximately $1.8 million. APCo anticipates completing the engineering in 2011 and performing the remedial work in 2012 and 2013.

•

The dam safety study for the St. Alban facility was completed in 2010. APCo has decided to perform a more detailed condition assessment before finalizing the remediation plan for this dam. APCo anticipates condition assessment, engineering, and regulatory review to be performed between 2011 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 has been corresponding with the Quebec government and other stakeholders about these options since 2007. APCo anticipates any required work on these dams to be completed by 2015.

•

Dam remediation work related to Rawdon is anticipated to be completed in 2011 while dam remediation work related to the Chute Ford and Ste. Raphael facilities is anticipated to be completed in 2012. No dam remediation work is required at the Arthurville, Hydraska, and Ste-Brigitte facilities.

LIQUIDITY AND CAPITAL RESERVES

The following table sets out the amounts drawn, letters of credit issued and outstanding amounts available to APUC and its subsidiaries as at June 30, 2011 under the senior banking facility (the “Facility”):


	2011 Q2			2011 Q1			2010 Q4			2010 Q3			2010 Q2
	(millions)			(millions)			(millions)			(millions)			(millions)
Committed and available Facility	$	120.0	*	$	142.0		$	142.0	**	$	163.4		$	162.8

Funds Drawn on Facility		(3.0	)*		(65.0	)		(64.5	)		(108.9	)		(102.8	)
Letters of Credit issued		(32.5	)		(32.9	)		(33.1	)		(33.8	)		(34.6	)


Remaining available Facility	$	84.5		$	44.1		$	44.4	*	$	20.7		$	25.4


Cash on Hand		8.7			2.5			5.1			3.1			2.4


Total liquidity and capital reserves	$	93.2		$	46.6		$	49.5		$	23.8		$	27.8

*	Reflects availability under the Facility following a $135 million senior unsecured debenture offering completed on July 25, 2011. The Facility was reduced to $120 million and the majority of the outstanding balance repaid subsequent to the completion of the Offering.

**	Reflects availability under the terms of a three year Facility with a maturity of February 14, 2014 and which was renewed subsequent to December 31, 2010.

As at and for the period ended June 30, 2011, Algonquin was in compliance with the covenants under the Facility. As at June 30, 2011, $70.0 million had been drawn on the Facility as compared to $64.5 million as at December 31, 2010. In addition to amounts actually drawn, there were $32.5 million in letters of credit outstanding as at June 30, 2011.

On July 25, 2011, APCo completed the Senior Unsecured Debenture offering of $135 million, the net proceeds of which have been used to repay the Airsource senior debt financing having a principal amount outstanding of $67.8 million with the balance being used to reduce amounts outstanding on the Facility. On the same day, the available Facility was reduced to $120 million. Therefore, APUC currently has $84.5 million of committed and available bank facilities remaining and $8.7 million of cash resulting in total liquidity and capital reserves of $93.2 million.

CONTRACTUAL OBLIGATIONS

Information concerning contractual obligations as of June 30, 2011 is shown below:


	Total		Due less than 1 year		Due 1 to 3 years		Due 4 to 5 years		Due after 5 years
Long-term debt obligations ¹	$	328,667	$	1,522	$	3,359	$	69,048	$	254,738
Convertible Debentures	$	122,477		—		—		—		122,477
Interest on long-term debt obligations	$	177,086		23,963		45,016		38,274		69,833
Long Term Service Agreements	$	94,854		3,798		7,993		8,390		74,673
Purchase obligations	$	35,327		35,327		—		—		—
Capital Projects	$	1,767		1,767		—		—		—
Derivative financial instruments:
Interest rate swap	$	5,331		1,982		2,522		827		—
Lease obligations	$	4,331		1,875		1,321		357		778
Other obligations	$	9,983		1,123		516		516		7,828

Total obligations	$	779,823	$	71,357	$	60,727	$	117,412	$	530,327

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

SHAREHOLDERS’ EQUITY AND CONVERTIBLE DEBENTURES

APUC’s shares are publicly traded on the Toronto Stock Exchange (“TSX”). As at June 30, 2011, APUC had 119,199,940 issued and outstanding shares on a fully diluted basis.

As at June 30, 2011, APUC had issued to Emera a treasury subscription of subscription receipts convertible into 12.0 million APUC common shares upon closing of the transactions at a purchase price of $5.00. Delivery of the shares under the subscription receipts is conditional on and is planned to occur simultaneously with the closing of the acquisition of Granite State and EnergyNorth. The proceeds of the subscription receipts are to be utilized to fund a portion of the cost to acquire Granite State and EnergyNorth.

On April 29, 2011, APUC agreed to issue to Emera 8.2 million shares with regards to the acquisition by Liberty Energy of Emera’s 49.999% direct ownership in Liberty Energy (California). The approval on the ownership transfer is expected in late 2011. The payment of shares is to be made in two tranches with approximately half of the shares being issued following regulatory approval of the ownership transfer and the balance of the shares being issued following completion of Liberty Energy (California)’s first rate case which is expected to be completed in mid 2012.

On April 30, 2011, APUC committed to issuance to Emera of a treasury subscription of subscription receipts convertible into approximately 6.9 million APUC common shares upon closing of the transaction related to the acquisition of an interest in a portfolio of 370MW wind projects (see Major Highlights - Acquisition of First Wind’s Northeast Projects for more details on the acquisition) at a purchase price of $5.37 per subscription receipt. Total gross proceeds to APUC of $37 million will be utilized to fund a portion of the cost to acquire the interest in Northeast Wind.

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.

The Series 1A Debentures previously due November 30, 2014 were redeemed on the Redemption Date. Between April 1, 2011 and the Redemption Date, a principal amount of $60,266 of Series 1A Debentures were converted into 14,771,185 shares of APUC.

On May 16, 2011 the redemption was effected in accordance with the terms and definitions of the trust indenture governing the Debentures. APUC satisfied its obligation to pay the remaining holders of Debentures (“Debentureholders”) by issuing and delivering 430,666 APUC shares, which represented the number of freely tradeable APUC shares obtained by dividing the aggregate principal amount of

Debentures, by 95% of the current market price of APUC shares on the Redemption Date. Unpaid accrued interest on the Debentures in the amount of $59 was paid in cash at the time of redemption. On June 30, 2011, as a result of the Redemption there were nil Series 1A Debentures outstanding.

The convertible unsecured subordinated debentures bearing interest at 6.35%, maturing on November 30, 2016 (“Series 2A Debentures”) pay interest semi-annually in arrears on April 1 and October 1 each year and are convertible into shares of APUC at the option of the holder at a conversion price of $6.00 per share. On June 30, 2011, there were 59,967 Series 2A Debentures outstanding with a face value of $59,967.

The convertible unsecured debentures maturing on June 30, 2017 (“Series 3 Debentures”) bear interest at 7.0% per annum, payable semi-annually in arrears on June 30 and December 30 each year, and are convertible into shares of APUC at the option of the holder at a conversion price of $4.20 per share.

During the six months ended June 30, 2011, a principal amount of $145 of Series 3 Debentures was converted into 34,523 APUC shares. During the three months ended June 30, 2011, a principal amount of $40 of Series 3 Debentures was converted into 9,522 APUC shares. On June 30, 2011, there were 62,760 Series 3 Debentures outstanding with a face value of $62,760. Subsequent to the end of the quarter, $50 Series 3 Debentures were converted to 11,904 APUC shares.

STOCK OPTION PLAN

On June 23, 2010, APUC’s shareholders approved a stock option plan (the “Plan”) that permits the grant of share options to key officers, directors, employees and selected service providers. On June 21, 2011, APUC’s shareholders approved amendments to the Plan to limit non-employee director participation in the Plan and to require shareholder approval to make further amendments to the plan with respect to a number of items as more fully described in the management information circular for the 2011 annual and special meeting of shareholders.

On March 22, 2011, the Board approved the grant of 892,107 options to select senior executives of APUC. The options allow for the purchase of common shares at a price of $5.23, the market price of the underlying common share at the date of grant. One-third of the options vest on each of January 1, 2012, 2013 and 2014. Options may be exercised up to eight years following the date of grant.

On June 21, 2011, the Board approved the grant of 171,642 options to a senior executive of APCo. The options allow for the purchase of common shares at a price of $5.64, the market price of the underlying common share at the date of grant. One-third of the options vest on each of January 1, 2012, 2013 and 2014. Options may be exercised up to eight years following the date of grant.

Subsequent to the end of the second quarter, on July 28, 2011 the Board approved the grant of 90,909 options to a senior executive of APUC. The options allow for the purchase of common shares at a price of $5.74, the market price of the underlying common share at the date of grant. One-third of the options vest on each of January 1, 2012, 2013 and 2014. Options may be exercised up to eight years following the date of the grant.

The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on the 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.

For the three and six month period ended June 30, 2011, APUC recorded, respectively $96 and $217 (2010 - $0), in stock option compensation expense. As at June 30, 2011, there was $1,189 (December 31, 2010 -$562) of total unrecognized compensation costs related to stock options granted under the Plan. The cost is expected to be recognized over a period of 2.1 years.

As at June 30, 2011, 386,735 options with an intrinsic value of $642 are exercisable. No share options were exercised in 2011 or 2010. The intrinsic value of the 1,837,218 non-vested options as at June 30, 2011 was $1,724 (December 31, 2010 - $1,069).

DIVIDEND REINVESTMENT PLAN

Effective October 1, 2011, APUC is introducing a shareholder dividend reinvestment plan (the “Reinvestment Plan”) which will be offered to registered holders of shares (“Shareholders”) of APUC.

The purpose of the Reinvestment Plan is to enable Shareholders to invest all cash dividends on Shares in additional shares of APUC (“Plan Shares”). All such Plan Shares will be, at APUC’s election, either (i) Shares purchased on the open market through the facilities of the TSX (“Market Purchase”) or (ii) newly issued Shares purchased from APUC (“Treasury Purchase”).

The price at which Plan Shares will be purchased with such cash dividends will be (i) in the case of a Market Purchase, the average price paid (excluding brokerage commissions, fees and transaction costs) per Plan Share by the Agent for all Plan Shares purchased in respect of a Dividend Payment Date under the Reinvestment Plan, or (ii) in the case of a Treasury Purchase, the weighted average of the trading price for Shares of APUC on TSX for the five (5) trading days immediately preceding the relevant dividend payment date less a discount, if any, of up to five percent (5%), at APUC’s election. No commissions, service charges or brokerage fees are payable by Shareholders in connection with the Reinvestment Plan.

RELATED PARTY TRANSACTIONS

•

Certain executives of APUC and members of the Board are shareholders of Algonquin Power Management Inc. (APMI), the former manager of APCo. A member of the Board is an executive at Emera.

•

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 three months and six months ended June 30, 2011 were $81 and $163 (2010 - $81 and $163). Based on a review of the real estate leasing market at the time, APUC believes the lease was entered into on terms equivalent to fair market value for prime office space of similar size and quality.

•

APUC utilizes chartered aircraft, including the use of an aircraft owned by an affiliate of APMI, Algonquin Airlink Inc. In 2004, APUC entered into an agreement and remitted $1,300 to the affiliate as an advance against expense reimbursements (including engine utilization reserves) for APUC’s business use of the aircraft. Under the terms of this arrangement, APUC has priority access to make use of the aircraft for a specified number of hours at a cost equal solely to the third party direct operating costs incurred when flying the aircraft. During the three and six months ended June 30, 2011, APUC incurred costs in connection with the use of the aircraft of $53 and $124 (2010 - $60 and $208) and amortization expense related to the advance against expense reimbursements of $87 and $128 (2010 - $6 and $63). At June 30, 2011, the remaining amount of the advance was $426 (2010 - $554) and is recorded in other assets.

•

Affiliates of APMI hold 60% of the outstanding Class B limited partnership units issued by the St. Leon Wind Energy LP (“St. Leon LP”), an indirect subsidiary of APUC and the legal owner of the St. Leon facility. The holders of the Class B Units are entitled to 2.5% of the income allocations and cash distributions from St. Leon LP for a 5 year period commencing June 17, 2008 growing to a maximum of 10% by year 15. In any particular period, cash distributions to the holders of the Class B Units are only to be made after distributions have been made to the other partners, in an aggregate amount, equal to the debt service on the outstanding debt in respect of such period. The related holders of the Class B units have received cash distributions of $43 and $87 for the three and six months ended June 30, 2011 (2010 - $87 and $126).

•

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. The royalty fee is initially equal to 0.75% of gross energy revenue, increasing every five years up to 2% after twenty-five years. During the six months ended June 30, 2011, APUC acquired APMI’s interest in this royalty for an amount of $600. This amount has been recorded as a purchase of intangible assets and the amount is included in accrued liabilities at June 30, 2011. APMI is also entitled to a development fee of up to $400 following commercial operation of the project and has agreed to permit the Board to determine the portion of such fee which will be paid following commercial operation of the facility.

•

APUC has operation and maintenance service agreements with three hydroelectric generating facilities owned by affiliates of APMI. As a result of these agreements, APUC employees operate these hydroelectric generating facilities owned by affiliates of APMI. These facilities are charged on a cost recovery basis for time and material incurred at these sites.

•

The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions. As at June 30, 2011 amount due from the above related party transactions was $509 (December 31, 2010 -$718) and amounts due to related parties was $1,485 (December 31, 2010 - $901).

•

A contract with a subsidiary of Emera to purchase energy on ISO NE and provide scheduling services on ISO NE was included as part of the acquisition of the ESB associated with the Tinker Acquisition. The contract expired March 31, 2010 and was not renewed. As a result of this contract, during 2010 a subsidiary of Emera provided services to and purchased energy on ISO NE on behalf of the ESB. In this capacity, for the three and six months ended June 30, 2011 APUC paid a subsidiary of Emera an amount of $0 (2010 -$1,368) which was included as an operating expense on the consolidated statement of operations.

•

In 2010, APUC entered into a one year contract with a subsidiary of Emera to provide lead market participant services for fuel capacity and forward reserve markets in ISO NE for the Windsor Locks facility. During the three and six months ended June 30, 2011 APUC paid U.S. $42 and $103 (2010 - $0) in relation to this contract. In the same period, APUC provided a corporate guarantee to a subsidiary of Emera in an amount of U.S. $1,000 in conjunction with this contract.

•

On December 21, 2010, a subsidiary of Emera acquired Maine & Maritimes Corporation, the parent company of Maine Public Service Company (“MPS”). For the three and six months ended June 30, 2011, the ESB sold electricity of $1,550 and $3,562 to MPS. In the same period, 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 June 30, 2011, included in amounts due from related parties is $1,548 (2010 - $0) owed from Emera related to the unpaid contribution of their share of Liberty Energy (California) costs. APUC believes that the transactions with Emera noted above were in accordance with normal commercial terms. The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.

•

In May 2011, APUC received $339 from CJIG Management Inc. (“CJIG”), as its share of 50% of the additional proceeds received by CJIG from the further liquidation of the assets held by Highground Capital Corporation. This has been recorded as an increased amount assigned to the equity originally issued in connection with the Highground transaction. Subsequent to June 30, 2011 APUC received an additional $734 from CJIG.

Business Associations with APMI and Senior Executives.

There are a number of continuing business relationships between APUC and one of Ian Robertson and Chris Jarratt (“Senior Executives”), APMI and related affiliates. These relationships include joint ownership of certain generating facility assets, business relationships between the parties and payment of fees associated with previous transactions. The Board has initiated a process to review all of the remaining business associations with Senior Executives, APMI and related affiliates in order to reduce, streamline and simplify these relationships. Any transaction associated with this process will only proceed if they are expected to be accretive to APUC.

The Board has formed a special committee and has engaged independent consultants to assist with this process and expects to conclude this process by the end of 2011.

The co-owned assets and remaining business associations consist of the following:

Rattlebrook hydroelectric generating facility

Rattlebrook is a 4 MW hydroelectric generating station owned 45% by APUC and 27.5% by Senior Executives and the remaining percentage by third parties.

ii)

St. Leon wind power generating facility

St. Leon is a 104 MW wind power generating facility which has issued Class B units to external parties and Senior Executives.

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. In 2008, APUC accrued $100 as an estimate of the final fee owed to APMI.

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.

Chartered aircraft

APUC utilizes chartered aircraft owned by an affiliate of APMI. APUC entered into an agreement and remitted $1.3 million to the affiliate as an advance against expense reimbursements. At June 30, 2011, $426 of the advance remained. The Board has undertaken an independent review of the relationship and believes that continuing the original arrangement is beneficial to the company. The current arrangement is expected to end in approximately 2016 when the capital advance will be repaid.

vi)

Office lease

APUC has leased its head office facilities on a triple net basis from an entity partially owned by Senior Executives. The original lease was due to expire in December 31, 2012. Effective April 1, 2011, a subsidiary of APUC leased its head office facilities from a third party in a new stand alone building immediately adjacent to APUC’s head office for a term of 5 years ending December 31, 2015 with an additional 5 year renewal option. APUC has amended its lease at its existing premises to be co-terminus with its subsidiary’s new lease. The majority of terms in the amended lease are identical. Based on a review of the real estate leasing market in the fall of 2010, APUC believes the amended lease is on terms equivalent to fair market value for prime office space of similar size and quality.

vii)

Operations services

Staff managed by APUC have historically operated an additional three hydroelectric generating facilities where Senior Executives hold an interest. Effective January 1, 2011, management of these facilities has now being undertaken by Algonquin Power Systems Inc. (“APS”) which is a non-APUC entity. APUC and APS have agreed to provide some transition services to each other until December 31, 2011. Costs for providing such transition services are intended to be on a cost recovery basis with no mark-up for profit.

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. In 2008, APUC accrued U.S. $0.6 million as an estimate of the final fee owed to APMI.

ix)

Clean Power Income Fund

During 2007, Algonquin allowed its offer to acquire Clean Power Income Fund 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 June 30, 2011 this amount is accrued and included in accounts payable on the consolidated balance sheet.

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. APUC has acquired APMI’s interest in these royalties for an amount of $0.6 million. APMI is also entitled to a development fee of up to $0.4 million following commercial operation of the project and has agreed to permit the Board to determine whether it will retain this fee following commercial operation of the facility.

xi)

Trafalgar

APCo owns debt on seven hydroelectric facilities owned by Trafalgar Power Inc. and an affiliate (“Trafalgar”). In 1997, Algonquin 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. The Second Circuit Court of Appeals recently dismissed all the claims against APCo in the civil proceedings and remanded one issue to the District Court. The bankruptcy proceedings are continuing.

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, any credit risk associated with a reliance on key customers, interest rate, liquidity and commodity price risk considerations. The risks discussed below are not intended as a complete list of all exposures that APUC may encounter. A further assessment of APUC and its subsidiaries’ business risks is also set out in the most recent 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 55% of EBITDA in 2011 and 65% of cash flow from operations is generated in U.S. dollars. APUC estimates that, on an unhedged basis, a $0.10 increase in the strength of the U.S. dollar relative to the Canadian dollar would result in increased reported revenue from U.S. operations of approximately $19.2 million and increased reported expenses from U.S. operations of approximately $13.1 million or a net impact of $6.1 million ($0.05 per share) on an annual basis.

The change in mark-to-market losses/(gains) on derivative financial instruments results from changes in foreign exchange rates, changes in interest rates or forward energy prices and relate to long term contract periods which extend to fiscal 2015. The following chart provides a summary of the six month over six month changes between realized and unrealized mark-to-market gains and losses of derivative financial instruments:


	Six months ended June 30
	2011			2010			Change
Foreign Exchange Contracts:
Change in unrealized mark-to-market loss/(gain) on derivative financial instruments	$	(45	)	$	143		$	( 188	)
Realized loss/(gain) on derivative financial instruments		691			(425	)		1,116

	$	646		$	( 282	)	$	928

Interest Rate Swap Contracts:
Change in unrealized mark-to-market loss/(gain) on derivative financial instruments	$	(108	)	$	(799	)	$	691
Realized loss on derivative financial instruments		1,068			3,182			(2,114	)

	$	960		$	2,383		$	(1,423	)

Energy Forward Purchase Contracts:
Change in unrealized mark-to-market gain on derivative financial instruments	$	(1,403	)	$	(1,915	)	$	512
Realized loss on derivative financial instruments		328			1,953			(1,625	)

	$	(1,075	)	$	38		$	(1,113	)

Derivative Financial Instruments Total:
Change in unrealized mark-to-market gain on derivative financial instruments	$	(1,556	)	$	(2,571	)	$	1,015
Realized loss on derivative financial instruments		2,087			4,710			(2,623	)

Total loss/(gain) on derivative financial instruments	$	531		$	2,139		$	(1,608	)

The following chart provides a summary of the quarter over quarter changes between realized and unrealized mark-to-market gains and losses of derivative financial instruments:


	Three months ended June 30
	2011			2010			Change
Foreign Exchange Contracts:
Change in unrealized mark-to-market loss on derivative financial instruments	$	—		$	1,226		$	(1,226	)
Realized gain on derivative financial instruments		(4	)		(293	)		289

	$	(4	)	$	933		$	(937	)

Interest Rate Swap Contracts:
Change in unrealized mark-to-market loss on derivative financial instruments	$	873		$	488		$	385
Realized loss on derivative financial instruments		535			1,586			(1,051	)

	$	1,408		$	2,074		$	666

Energy Forward Purchase Contracts:
Change in unrealized mark-to-market gain on derivative financial instruments	$	(453	)	$	(80	)	$	373
Realized loss on derivative financial instruments		9			125			(116	)

	$	(444	)	$	45		$	257

Derivative Financial Instruments Total:
Change in unrealized mark-to-market loss on derivative financial instruments	$	420		$	1,634		$	(1,214	)
Realized loss on derivative financial instruments		540			1,418			(878	)

Total loss/(gain) on derivative financial instruments	$	960		$	3,052		$	(2,092	)

Interest rate risk

APCo has a number of project specific and other debt facilities that are subject to a variable interest rate. These facilities and the sensitivity to changes in the variable interest rates charged are discussed below:

•

The banking credit facility provided to APCo by a consortium of Canadian chartered banks has an outstanding balance drawn of $70.0 million as at June 30, 2011. The outstanding balance was substantially repaid subsequent to June 30, 2011 using proceeds from the Senior Unsecured Debenture offering. Assuming the adjusted level of borrowings over an annual basis, a 100 basis point change in the variable rate charged would impact interest expense by $30 annually.

•

APCo’s project debt at the St. Leon facility has a balance of $67.8 million as at June 30, 2011. The outstanding balance was repaid subsequent to June 30, 2011 using proceeds from the Senior Unsecured Debenture offering. Accordingly there is no further interest rate risk associated with this debt facility.

•

APCo’s project debt at its Sanger cogeneration facility has a balance of U.S. $19.2 million as at June 30, 2011. 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.

Liberty Water’s project debt at the Litchfield and Bella Vista Facilities are subject to a fixed rate of interest and thus are not subject to interest rate risk. Liberty Water’s U.S. $50 million senior unsecured notes with a 10 year term bearing a fixed rate of interest at 5.6% are subject to a fixed rate of interest and are not subject to interest rate risk.

Liberty Energy’s U.S. $70 million senior unsecured private debt placement at the California Utility is split into two tranches, U.S. $45 million of ten year 5.19% notes and U.S. $25 million of 5.59% fifteen year notes. As such these notes are not subject to interest rate risk.

Liquidity risk

Liquidity risk is the risk that APUC and its subsidiaries will not be able to meet their financial obligations as they become due. APUC’s approach to managing liquidity risk is to ensure, to the extent possible, that it will always have sufficient liquidity to meet liabilities when due.

APUC currently pays a dividend of $0.26 per share per year. On August 11, 2011, the Board approved a dividend increase of $0.02 annually bringing the total annual dividend to $0.28, paid quarterly at the rate of $0.07 per common share. 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, ensure APUC’s long-term success. Based on the level of dividends paid during the three months ended June 30, 2011, cash provided by operating activities exceeded dividends declared by 2.5 times.

As at June 30, 2011, after adjusting for the proceeds of the Senior Unsecured Debentures, APUC had cash on hand of $8.7 million and $84.5 million available to be drawn on the Facility. APUC reduced its level of short-term borrowings through the renewal of the Facility on February 14, 2011 for a three year term and through a U.S. $50 million private placement debt financing at Liberty Water on December 22, 2010. In addition, on July 25, APCo completed a private placement offering of the Senior Unsecured Debentures with a principal amount of $135 million. Net proceeds from the debentures were used to repay the project debt on APCo’s AirSource senior debt financing which would have matured on October 2011, and to reduce amounts outstanding under APCo’s senior credit facility. See the Liquidity and Capital Reserves section for a more detailed discussion and chart of the funds available to APUC and its subsidiaries under the Facility.

The Facility and project specific debt total approximately $328.7 million with maturities set out in the Contractual Obligation table. In the event that APUC was required to replace the Facility and project debt with borrowings having less favourable terms or higher interest rates, the level of cash generated for dividends and reinvestment into the company may be negatively impacted. APUC attempts to manage the risk associated with floating rate interest loans through the use of interest rate swaps.

The cash flow generated from several of APUC’s operating facilities is subordinated to senior project debt. In the event that there was a breach of covenants or obligations with 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. See APUC’s audited consolidated financial statements for the years ended December 31, 2010 and 2009 for discussion of this risk.

Liberty Water is not subject to any material commodity price risk.

Liberty Energy is exposed to energy price risk which is mitigated through the certain regulatory constructs. Liberty Energy (California) provides electric service to the Lake Tahoe basin and surrounding areas at rates approved by the CPUC. The utility purchases the energy requirements for its customers from NV Energy at rates reflecting NV Energy’s system average costs. In the event that these rates change, each $10.00 change per MWhr would result in a change in expense of approximately U.S. $6.5 million on an annualized basis.

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 does not exceed 5%. In the event that the cumulative variance exceeds 5%, the ECAC allows for an adjustment to Liberty Energy (California)’s approved rates (including carrying charges associated therewith), substantially eliminating the commodity risk associated with the purchase of power.

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. The risks discussed below are not intended as a complete list of all exposures that APUC and its subsidiaries may encounter. A more detailed assessment of APUC’s business risks is also set out in the most recent AIF.

Mechanical and Operational Risks

APUC is entirely dependant 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 the Liberty Water 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 Energy 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.

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. In addition, APCo’s existing long term PPAs minimize the risk of reductions in average energy pricing.

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 Energy’s facilities are subject to rate setting by State regulatory agencies. The time between the incurrence of costs and the granting of the rates to recover those costs by State regulatory agencies is known as regulatory lag. As a result of regulatory lag, inflationary effects may impact the ability to recover expenses, and profitability could be impacted. 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 Energy, and while Liberty Energy 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 Energy 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.

Based on its assessments, APUC’s businesses do not have any significant retirement obligation liabilities and APUC has not recorded any liability in its financial statements.

Environmental Risks

APUC and its subsidiaries face a number of environmental risks that are normal aspects of operating within the renewable power generation, thermal power generation and utilities business segments which have the potential to become environmental liabilities. Many of these risks are mitigated through the maintenance of adequate insurance which include property, boiler and machinery, environmental and excess liability policies.

Liberty Energy 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 Energy 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 Energy 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.

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 June 30, 2011.

Cycles and Seasonality

For Liberty Electric, 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 Electric 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.

Disclosure Controls

At the end of the fiscal year ended December 31, 2010, APUC carried out an evaluation, under the supervision of and with the participation of the APUC’s management, including the Chief Executive Officer (“CEO”) and the Chief Financial Officer (“CFO”), of the effectiveness of the design and operations of the Company’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, 2010, APUC’s disclosure controls and procedures were adequately designed and effective in ensuring that: (i) information required to be disclosed by APUC in reports that it files or submits to the Securities and Exchange Commission under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in applicable rules and forms and (ii) material information required to be disclosed in its reports filed under the Exchange Act is accumulated and communicated to management, including the CEO and CFO, as appropriate, to allow for accurate and timely decisions regarding required disclosure.

Internal controls over financial reporting

Management, including the CEO and the CFO, is responsible for establishing and maintaining internal control over financial reporting as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings. Management, as at the end of the period covered by this interim filing, designed internal control over financial reporting to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP. The control framework management used to design the issuer’s internal control over financial reporting is that established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Changes in internal controls over financial reporting

During the six months ended June 30, 2011, 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’s transition to U.S. GAAP in the period did not result in any significant changes to the APUC’s internal controls.

Quarterly Financial Information

The following is a summary of unaudited quarterly financial information for the two years ended June 30, 2011.


Millions of dollars (except per share amounts)	3^rd Quarter 2010*		4^th Quarter 2010*			1^st Quarter 2011		2^nd Quarter 2011
Revenue	$	45.4	$	48.9		$	71.7	$	66.8
Net earnings /(loss) attributable to Shareholders		1.5		16.9			5.0		7.3
Basic net earnings / (loss) per share		0.02		0.18			0.05		0.07
Total Assets		969.4		980.9			1,175.8		1,177.7
Long term debt**		452.8		461.0			461.0		530.0
Dividend per share		0.06		0.06			0.065		0.065

	3^rd Quarter 2009*		4^th Quarter 2009*			1^st Quarter 2010*		2^nd Quarter 2010*
Revenue	$	45.1	$	43.4		$	45.9	$	42.7
Net earnings / (loss) attributable to Shareholders/Unitholders		13.1		(1.4	)		3.5		(2.2	)
Basic net earnings / (loss) per share/trust unit		0.17		(0.03	)		0.04		(0.02	)
Total Assets		925.7		1,013.4			966.2		983.2
Long term debt**		445.4		439.9			434.0		446.7
Dividends/distribution per share/trust unit		0.06		0.06			0.06		0.06

*	Based on Canadian Generally Accepted Accounting Principals

**	Long term debt includes long term liabilities, the Facility, convertible debentures and other long term obligations

The quarterly results are impacted by various factors including seasonal fluctuations and acquisitions of facilities as noted in this MD&A.

Quarterly revenues have fluctuated between $42.7 million and $71.7 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 significant fluctuation in the strength of the Canadian dollar which has resulted in significant changes in reported revenue from U.S. operations.

Quarterly net earnings have fluctuated between net earnings of $16.9 million and a net loss of $2.2 million over the prior two year period. Earnings have been significantly impacted by non-cash factors such as future tax expense due to the enactment of Bill C-52 and mark-to-market gains and losses on financial instruments.

Critical Accounting Estimates

APUC prepared its Interim Consolidated Financial Statements in accordance with U.S. GAAP. An understanding of APUC’s accounting policies is necessary for a complete analysis of results, financial position, liquidity and trends. Refer to Note 1 to the Interim Consolidated Financial Statements for additional information on accounting principles. The Interim Consolidated Financial Statements are presented in Canadian dollars rounded to the nearest thousand, except per share amounts and except where otherwise noted.

Additional disclosure of APUC’s critical accounting estimates is also available in APUC’s MD&A for the year ended December 31, 2010 available on SEDAR at www.sedar.com and on the APUC website at www.AlgonquinPowerandUtilities.com.

Changes in Accounting Policies

APUC’s accounting policies are described in Note 1 to the Interim Unaudited Consolidated Financial Statements for the period ended June 30, 2011.

Accounting framework

The unaudited consolidated interim financial statements and accompanying notes have been prepared in accordance with generally accepted accounting principles in the United States (U.S. GAAP) and follow disclosures required per Regulation S-X Rule 10-10, Interim Financial Statements provided by the Securities and Exchange Commission (SEC) Guidance. These are the Company’s U.S. GAAP consolidated interim financial statements for part of the period covered by the first U.S. GAAP annual financial statements.

The Company’s consolidated financial statements were prepared in accordance with Canadian Generally Accepted Accounting Principles (“Canadian GAAP”) until December 31, 2010. Canadian GAAP differs in some areas from U.S. GAAP as was disclosed in the reconciliation to U.S. GAAP included in the audited annual financial statements for the year ended December 31, 2010. Descriptions of the effect of the transition from Canadian GAAP to U.S. GAAP on the Company’s financial position, financial performance and cash flows as at and for the two years ended December 31, 2010 are provided in note 24 of the audited consolidated financial statements for the year ended December 31, 2010. The accounting policies set out in the Interim Consolidated Financial Statements for the period ended June 30, 2011 have been consistently applied to all the periods presented. The comparative figures in respect of 2010 were restated to reflect the adoption of U.S. GAAP.

There was no significant impact of the transition to U.S. GAAP on APUC’s internal controls, information technology systems and financial reporting expertise requirements. No financial covenants were impacted by APUC’s conversion to U.S. GAAP given the few differences that exist with Canadian GAAP.