EX-99.3 4 d587781dex993.htm EX-99.3

EX-99.3

Exhibit 99.3

Interim Management’s Discussion and Analysis

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

Management of Algonquin Power & Utilities Corp. (“APUC” or the “Company”) has prepared the following discussion and analysis to provide information to assist its shareholders’ understanding of the financial results for the three and six months ended June 30, 2013. The 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, 2013 and 2012. This material is available on SEDAR at www.sedar.com and on the APUC website at www.AlgonquinPowerandUtilities.com. Additional information about APUC, including the most recent Annual Information Form (“AIF”) can be found on SEDAR at www.sedar.com.

Caution concerning forward-looking statements and non-GAAP Measures

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

Since forward-looking statements relate to future events and conditions, by their very nature they require APUC to make assumptions and involve inherent risks and uncertainties. APUC cautions that although it believes its assumptions are reasonable in the circumstances, these risks and uncertainties give rise to the possibility that actual results may differ materially from the expectations set out in the forward-looking statements. Material risk factors include the impact of movements in exchange rates and interest rates; the effects of changes in environmental and other laws and regulatory policy applicable to the energy and utilities sectors; decisions taken by regulators on monetary policy; and the state of the Canadian and the United States (“U.S.”) economies and accompanying business climate. APUC cautions that this list is not exhaustive, and other factors could adversely affect results. Given these risks, undue reliance should not be placed on these forward-looking statements. In addition, such statements are made based on information available and expectations as of the date of this MD&A and such expectations may change after this date. APUC reviews material forward-looking information it has presented, not less frequently than on a quarterly basis. APUC is not obligated to nor does it intend to update or revise any forward-looking statements, whether as a result of new information, future developments or otherwise, except as required by law.

The terms “adjusted net earnings”, “adjusted earnings before interest, taxes, depreciation and amortization” (“Adjusted EBITDA”), “adjusted funds from operations”, “per share cash provided by adjusted funds from operations” and “per share cash provided by operating activities” are used throughout this MD&A. The terms “adjusted net earnings”, “per share cash provided by operating activities”, “adjusted funds from operations”, “per share cash provided by adjusted funds from operations” and Adjusted EBITDA are not recognized measures under GAAP. There is no standardized measure of “adjusted net earnings”, Adjusted EBITDA, “adjusted funds from operations”, “per share cash provided by adjusted funds from operations” and “per share cash provided by operating activities” consequently APUC’s method of calculating these measures may differ from methods used by other companies and therefore may not be comparable to similar measures presented by other companies. A calculation and analysis of “adjusted net earnings”, Adjusted EBITDA, “adjusted funds from operations”, “per share cash provided by adjusted funds from operations” and “per share cash provided by operating activities” can be

found throughout this MD&A. Per share cash provided by operating activities is not a substitute measure of performance for earnings per share. Amounts represented by per share cash provided by operating activities do not represent amounts available for distribution to shareholders and should be considered in light of various charges and claims against APUC.

Overview and Business Strategy

APUC is incorporated under the Canada Business Corporations Act. APUC owns and operates a diversified portfolio of regulated and non-regulated generation, distribution and transmission utility assets which deliver predictable earnings and cash flows. APUC seeks to maximize total shareholder value through a quarterly dividend augmented by share price appreciation arising from dividend growth supported by increasing per share cash flows and earnings. APUC targets to deliver annualized per share earnings and cash flow growth of more than 5%.

APUC’s current quarterly dividend to shareholders is $0.085 per share or $0.34 per share per annum. APUC believes its annual dividend payout allows for both an immediate return on investment for shareholders and retention of sufficient cash within APUC to fund growth opportunities and mitigate the impact of fluctuations in foreign exchange rates. Further increases in the level of dividends paid by APUC are at the discretion of the APUC Board of Directors (the “Board”) with dividend levels being reviewed periodically by the Board in the context of cash available for distribution and earnings together with an assessment of the growth prospects available to APUC. APUC strives to achieve its results in the context of a moderate risk profile consistent with top-quartile North American power and utility operations.

APUC conducts its business primarily through two autonomous subsidiaries: Algonquin Power Co. (“APCo”) which owns and operates a diversified portfolio of non-regulated renewable and clean energy electric generation utility assets; and Liberty Utilities Co. (“Liberty Utilities”), a diversified rate regulated utility which owns and operates a portfolio of North American electric, natural gas and water distribution utility systems.

Algonquin Power Co.

APCo generates and sells electrical energy produced by its diverse portfolio of non-regulated renewable and clean energy power generation facilities located across North America. APCo delivers continuing growth through development of new greenfield power generation projects and accretive acquisitions of additional electrical energy generation facilities.

APCo owns or has interests in hydroelectric facilities with a combined generating capacity of approximately 120 MW. APCo also owns or has interests in wind powered generating stations with a combined generating capacity of 650 MW. Approximately 84% of the electrical output from the hydroelectric and wind generating facilities is sold pursuant to long term, stipulated price contractual arrangements which have a weighted average remaining contract life of 15 years.

APCo owns or has interests in thermal energy facilities with approximately 335 MW of installed generating capacity. Approximately 95% of the electrical output from the owned thermal facilities is sold pursuant to long term power purchase agreements (“PPA”) with major utilities and which have a weighted average remaining contract life of 7 years.

Liberty Utilities Co.

Liberty Utilities is a diversified rate regulated utility providing electricity, natural gas, water distribution and wastewater collection utility services. Liberty Utilities provides safe, high quality and reliable services to its ratepayers through its nationwide portfolio of utility systems and delivers stable and predictable earnings to APUC. In addition to encouraging and supporting organic growth within its service territories, Liberty Utilities delivers continued growth in earnings through accretive acquisitions of additional utility systems.

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

The Liberty Utilities (West) region is comprised of regulated electrical and water distribution and wastewater collection utility systems. The regulated electrical distribution utility systems serve approximately 47,000 active electric connections in the State of California. Liberty Utilities (West) region’s regulated water and wastewater utility systems serve approximately 68,000 water and wastewater connections located in the State of Arizona.

The Liberty Utilities (Central) region is comprised of regulated natural gas and water distribution and wastewater collection utility systems. The regulated natural gas utilities serve approximately 81,000 active natural gas connections located in the States of Missouri, Illinois, and Iowa and the regulated water distribution and wastewater collection utilities serve approximately 29,000 water and wastewater customers located in the States of Arkansas, Illinois, Missouri, and Texas.

Liberty Utilities (East) region is comprised of regulated natural gas and electric distribution utility systems located in the State of New Hampshire, and regulated natural gas distribution utility systems located in the State of Georgia. In New Hampshire, Liberty Utilities provides regulated local electrical utility services to approximately 44,000 active electric connections; and regulated local gas distribution utility services to approximately 84,000 active natural gas connections. In Georgia, Liberty Utilities provides regulated local gas distribution utility services to approximately 58,000 active natural gas connections. Upon completion of the acquisition of a natural gas utility system located in Massachusetts, over 50,000 active natural gas connections will be added to the Liberty Utilities (East) region.

Major Highlights

Corporate Highlights

Strong second quarter results

APUC has completed several acquisitions and has announced a number of other initiatives that have raised the growth profile for APUC’s earnings and cash flows. The growth arose from the acquisition of several regulated utilities in the U.S. serving over 290,000 customers together with the acquisition of 509.5 MW of wind farms also in the U.S. The increased earnings and cash flows from these acquisitions continued through the second quarter. Adjusted EBITDA totaled $56.5 million in the second quarter and $118.9 million year to date compared to $22.2 million and $43.4 million respectively.

Dividend Increased to $0.34 Per Common Share Annually

The increased earnings and cash flows in APUC’s second quarter results have supported an increase in the dividend to shareholders. As a result, on May 9, 2013, the Board approved a dividend increase of $0.03 annually bringing the total annual dividend to $0.34, paid quarterly at the rate of $0.085 per common share.

Management believes that the increase in 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.

Liberty Utilities Highlights

Agreement to Acquire New England Gas System

On February 11, 2013, Liberty Utilities entered into an agreement with The Laclede Group, Inc. (“Laclede”) to assume Laclede’s rights to purchase the assets of New England Gas Company (the “New England Gas System”) from an affiliate of Southern Union Company. New England Gas System is a natural gas distribution utility serving over 50,000 active connections in Massachusetts. The acquisition is subject to certain approvals and conditions, including state and federal regulatory approval, and is expected to close in the fourth quarter of 2013. The results of the New England Gas System will be reported in the Liberty Utilities (East) region upon completion of the transaction.

Total consideration for the utility asset purchase is approximately U.S. $74 million, subject to working capital and closing adjustments. The acquisition will be funded using a targeted 52% equity, 48% debt capital structure and will include the assumption of $19.5 million of existing debt.

Acquisition of Georgia Gas System

On April 1, 2013 Liberty Utilities completed the acquisition of regulated natural gas distribution utility systems serving Columbus and Gainesville, Georgia (the “Columbus/Gainesville Gas System”). Consideration for the utility asset purchase was approximately U.S. $140.7 million plus working capital and closing adjustments for a total consideration of U.S. $153.0 million. The regulated natural gas distribution utilities provide natural gas service to approximately 64,000 total connections in Georgia.

U.S. Debt Private Placement

On July 31, 2013, Liberty Utilities issued U.S. $125,000 of debt through a private placement. The financing is the third series of notes issued pursuant to Liberty Utilities’ master indenture. The notes are senior unsecured with an average life maturity of ten years and a weighted average coupon of 3.81%. The proceeds of the private placement financing were used to repay the U.S. $100,000 short term acquisition facility and reduce the drawn amount on Liberty’s revolving credit facility.

Granite State Electric System Rate Case

On March 29, 2013, Granite State Electric System filed a rate case with the New Hampshire Public Service Commission seeking an increase in EBITDA of U.S. $13.2 million, and an additional U.S. $1.2 million increase in 2014 subject to the completion of certain capital projects. The filing is based on a 2012 test year, with revenues and expenses adjusted to reflect known and measurable changes. Among other things, Granite State Electric Company requested and received approval to continue the current cost-recovery tracking mechanism related to the Reliability Enhancement and Vegetation Management Plan and was granted an annual increase of $0.4 million starting July 1, 2013. Granite State Electric also requested a modification to allow for recovery of pre-staging personnel and equipment for qualifying storms. The case is expected to be concluded in mid-2014. In June 2013, Granite State received approval to implement interim rate tariffs which provide an annualized increase in revenues of $6.5 million and an expected increase in storm recovery costs, effective in November 2013, which provides an additional annualized revenue increase of $1.6 million.

Algonquin Power Co. Highlights

Construction Commencement of Cornwall Solar

During the quarter APCo began construction of the 10 MWac solar projected located near Cornwall, Ontario. The facility is the first solar project in APCo’s portfolio and is expected to add 13,900 MW-hrs of production annually. Completion of construction is expected late in the fourth quarter of 2013.

Sale of Small U.S. Hydro Facilities

On March 14, 2013, APCo entered into an agreement to sell ten small U.S. hydroelectric generating facilities that were no longer considered strategic to the ongoing operations of the Company for gross proceeds of U.S. $27 million. APCo closed the sale of nine of the ten facilities on June 28, 2013 for total proceeds of approximately $23.4 million with the tenth facility expected to be sold in Q4, 2013. The operating results from these facilities for current and prior periods are therefore disclosed as discontinued operations on the consolidated statements of operations.

Energy From Waste Facility

During the quarter, the Company conducted a strategic review of the Company’s business plan and opportunities available for its Energy from Waste (“EFW”) and Brampton Cogeneration Inc. (“BCI”) facilities. The review concluded that EFW and BCI are no longer considered strategic to

the ongoing operations of the Company and that management should pursue options to divest the facilities. The nets assets of the facilities have been written down to their estimated fair value less costs of sale which resulted in a one-time write down of $35.7 million, net of tax, in the second quarter of 2013. The operating results from these facilities are also disclosed as discontinued operations on the consolidated statements of operations and prior periods have been reclassified to conform to this presentation.

2013 Six months results from operations

Key Selected Six months Financial Information

		Six months ended June 30
(millions of dollars except per share information)		2013				2012
Revenue		$	342.1			$	116.9
Adjusted EBITDA 1, 3			118.9				43.4
Cash provided by operating activities			52.7				28.4
Adjusted funds from operations 1, 3			84.8				29.6
Net earnings attributable to Shareholders from continuing operations			36.2				7.3
Net earnings attributable to Shareholders			1.1				8.3
Adjusted net earnings 1, 3			34.7				11.8
Dividends declared to Common Shareholders			33.3				21.6
Weighted Average number of common shares outstanding			202,802,827				146,998,173
Per share
Basic net earnings from continuing operations		$	0.18			$	0.05
Basic net earnings		$	0.01			$	0.06
Adjusted net earnings 1, 2, 3		$	0.17			$	0.08
Diluted net earnings		$	0.01			$	0.06
Cash provided by operating activities 1, 2, 3		$	0.26			$	0.19
Adjusted funds from operations 1, 2, 3		$	0.42			$	0.20
Dividends declared to Common Shareholders		$	0.16			$	0.14
Total Assets			3,201.8				1,416.0
Total Liabilities4			1,091.5				461.8

¹  APUC uses adjusted EBITDA, adjusted net earnings and adjusted funds from operations to enhance assessment and understanding of the operating performance of APUC without the effects of certain accounting adjustments which are derived from a number of non-operating factors, accounting methods and assumptions.

²  APUC uses per share adjusted net earnings, cash provided by operating activities and adjusted funds from operations to enhance assessment and understanding of the performance of APUC.

³ Non-GAAP measure - see applicable section later in this MD&A and the caution regarding non-GAAP measures on page 1.

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

For the six months ended June 30, 2013, APUC experienced an average U.S. exchange rate of approximately $1.0161 as compared to $0.9994 in the same period in 2012. As such, any period over period variance in revenue or expenses, in local currency, at any of APUC’s U.S. entities are affected by a change in the average exchange rate, upon conversion to APUC’s reporting currency.

For the six months ended June 30, 2013, APUC reported total revenue of $342.1 million as compared to $116.9 million during the same period in 2012, an increase of $225.2 million. The major factors resulting in the increase in APUC revenue in the six months ended June 30, 2013 as compared to the corresponding period in 2012 are set out as follows:

		Six months ended June 30, 2013
		(Millions)
Comparative Prior Period Revenue		$	116.9
Significant Changes:
Liberty Utilities:
West – Implementation of decoupling mechanism and increased customer demand			3.1
Central – Revenue increase due to Midwest Gas Systems, and Pine Bluff Water System acquisitions			48.3
East – Additional revenue due to EnergyNorth Gas System, Granite State Electric System, and Columbus/Gainesville Gas System acquisitions			132.3
APCo:
Renewable:
Acquisition of Sandy Ridge, Minonk, Senate and Shady Oaks Wind Facilities			30.6
(collectively, the “U.S. Wind Facilities”)
Sale of Renewable Energy Credits generated from the U.S. Wind Facilities			2.5
St Leon II Wind Facility – Revenue increase from expansion			1.8
Thermal:
Sanger Facility – Increase due to planned shutdown in 2012			3.1
Impact of the stronger U.S. dollar			3.9
Other			(0.4	)
Current Period Revenue		$	342.1

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

Adjusted EBITDA in the six months ended June 30, 2013 totalled $118.9 million as compared to $43.4 million during the same period in 2012, an increase of $75.5 million.

The increase in Adjusted EBITDA was primarily due to increased revenues from EnergyNorth Gas System, Granite State Electric System, Midwest Gas System, U.S. Wind Facilities, and Columbus/Gainesville Gas System acquisitions, and increased demand and higher rates at the Liberty Utilities (West)’s electric distribution utility. A more detailed analysis of these factors is presented within the reconciliation of Adjusted EBITDA to net earnings (see Non-GAAP Performance Measures).

For the six months ended June 30, 2013, net earnings attributable to Shareholders from continuing operations totalled $36.2 million as compared to $7.3 million during the same period in 2012, an increase of $28.9 million. Net income per share from continuing operations was $0.18 for the six months ended June 30, 2013, as compared to net income per share of $0.05 during the same period in 2012.

The increase in net earnings from continuing operations attributable to Shareholders for the six months ended June 30, 2013 was due to $65.0 million increased earnings from operating facilities, $0.9 million due to a stronger U.S. dollar, $0.8 million in increased interest, dividend and other income, $3.4 million in decreased acquisition costs, $2.5 million in increased gains from derivative instruments, and $6.4 million in decreased allocations of earnings to non-controlling interests as compared to the same period in 2012. These items were partially offset by $27.1 million increased depreciation and amortization expense, $2.3 million related to increased administration charges, $10.2 million in higher interest expense and $10.5 million in higher tax expense.

For the six months ended June 30, 2013, net earnings (including discontinued operations) attributable to Shareholders totalled $1.1 million as compared to $8.3 million during the same period in 2012, a decrease of $7.2 million and primarily due to the write down in the carrying value of the EFW and BCI Facilities of $35.7 million. Net income per share totalled $0.01 for the six months ended June 30, 2013, as compared to net income per share of $0.06 during the same period in 2012.

During the six months ended June 30, 2013, cash generated by operating activities totalled $52.7 million or $0.26 per share as compared to cash provided by operating activities of $28.4 million, or $0.19 per share during the same period in 2012. During the six months ended June 30, 2013, adjusted funds from operations totalled $84.8 million or $0.42 per share as compared to adjusted funds from operations of $29.6 million, or $0.20 per share during the same period in 2012. A more detailed analysis of these factors is presented within the reconciliation of Adjusted Funds from operations to cash flow from operations set out below (see Non-GAAP Performance Measures).

Cash per share provided by operating activities and per share adjusted funds from operations are non-GAAP measures. Per share cash provided by operating activities and per share adjusted funds from operations are not substitute measures of performance for earnings per share. Amounts represented by per share cash provided by operating activities and per share adjusted funds from operations do not represent amounts available for distribution to shareholders and should be considered in light of various charges and claims against APUC.

2013 Three month results from operations

Key Selected Second Quarter Financial Information

		Three months ended June 30
(millions of dollars except per share information)		2013				2012
Revenue		$	148.8			$	58.7
Adjusted EBITDA 1, 3			56.5				22.2
Cash provided by operating activities			57.4				17.3
Adjusted funds from operations 1, 3			37.1				18.5
Net earnings attributable to Shareholders from continuing operations			15.8				5.3
Net earnings attributable to Shareholders			(18.1	)			6.1
Adjusted net earnings 1, 3			15.4				6.5
Dividends declared to Common Shareholders			17.4				11.3
Weighted Average number of common shares outstanding			204,908,701				153,414,269
Per share
Basic net earnings from continuing operations		$	0.08			$	0.03
Basic net earnings		$	(0.09	)		$	0.04
Adjusted net earnings 1, 2, 3		$	0.08			$	0.04
Diluted net earnings		$	(0.09	)		$	0.04
Cash provided by operating activities 1, 2, 3		$	0.28			$	0.11
Adjusted funds from operations 1, 2, 3		$	0.18			$	0.11
Dividends declared to Common Shareholders		$	0.09			$	0.07

¹  APUC uses adjusted EBITDA, adjusted net earnings and adjusted funds from operations to enhance assessment and understanding of the operating performance of APUC without the effects of certain accounting adjustments which are derived from a number of non-operating factors, accounting methods and assumptions.

² APUC uses per share adjusted net earnings, cash provided by operating activities and adjusted funds from operations to enhance assessment and understanding of the performance of APUC.

³ Non-GAAP measure—see applicable section later in this MD&A and the caution regarding non-GAAP measures on page 1.

For the three months ended June 30, 2013, APUC experienced an average U.S. exchange rate of approximately $1.0235 as compared to $1.0101 in the same period in 2012. As such, any quarter over quarter variance in revenue or expenses, in local currency, at any of APUC’s U.S. entities are affected by a change in the average exchange rate, upon conversion to APUC’s reporting currency.

For the three months ended June 30, 2013, APUC reported total revenue of $148.8 million as compared to $58.7 million during the same period in 2012, an increase of $90.1 million. The major factors resulting in the increase in APUC revenue in the three months ended June 30, 2013 as compared to the corresponding period in 2012 are set out as follows:

		Three months ended June 30, 2013
		(Millions)
Comparative Prior Period Revenue		$	58.7
Significant Changes:
Liberty Utilities:
West – Implementation of decoupling mechanism and increased customer demand			1.6
Central – Revenue increase due to Midwest Gas Systems, and Pine Bluff Water System acquisitions			16.0
East – Additional revenue due to EnergyNorth Gas System, Granite State Electric System, and Columbus/Gainesville Gas System acquisitions			52.2
APCo:
Renewable:
Hydro – Increased hydrology resources			0.6
Acquisition of US Wind Facilities			14.5
Sale of Renewable Energy Credits generated from the U.S. Wind Facilities			1.5
St Leon II Wind Facility – Revenue increase from expansion			0.9
Tinker/AES – Increased rates at AES and increased production at the Tinker Hydro facility			(1.4	)
Thermal:
Sanger Facility – Increase due to planned shutdown in 2012			1.3
Impact of the stronger U.S. dollar			2.6
Other			0.3
Current Period Revenue		$	148.8

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

Adjusted EBITDA in the three months ended June 30, 2013 totalled $56.5 million as compared to $22.2 million during the same period in 2012, an increase of $34.3 million.

The increase in Adjusted EBITDA was primarily due to increased revenues from EnergyNorth Gas System, Granite State Electric System, Midwest Gas System, U.S. Wind Facilities, and Columbus/Gainesville Gas System acquisitions, and increased demand and higher rates at the Liberty Utilities (West)’s electric distribution utility. A more detailed analysis of these factors is presented within the reconciliation of Adjusted EBITDA to net earnings (see Non-GAAP Performance Measures). A more detailed analysis of these factors is presented within the reconciliation of Adjusted EBITDA to net earnings (see Non-GAAP Performance Measures).

For the three months ended June 30, 2013, net earnings attributable to Shareholders from continuing operations totalled $15.8 million as compared to $5.3 million during the same period in 2012, an increase of $10.5 million. Net income per share from continuing operations was $0.08 for the three months ended June 30, 2013, as compared to net income per share of $0.03 during the same period in 2012.

The increase in net earnings from continuing operations attributable to Shareholders for the three months ended June 30, 2013 was due to $27.9 million increased earnings from operating facilities, $0.7 million in increased interest, dividend and other income, $1.5 million in decreased acquisition costs, $1.2 million in increased gains from derivative instruments, $3.9 million in decreased allocations of earnings to non-controlling interests as compared to the same period in 2012. These items were partially offset by $14.2 million increased depreciation and amortization expense, $1.9 million related to increased administration charges, $6.7 million in higher interest expense and $1.9 million in higher tax expense.

For the three months ended June 30, 2013, net loss (including discontinued operations) attributable to Shareholders totalled $18.1 million as compared to net income attributable to Shareholders of $6.1 million during the same period in 2012, a decrease of $24.2 million, and predominantly due to the discontinuance of the EFW Facility. Net loss per share totalled $0.09 for the three months ended June 30, 2013, as compared to net income per share of $0.04 during the same period in 2012.

During the three months ended June 30, 2013, cash generated by operating activities totalled $57.4 million or $0.28 per share as compared to cash provided by operating activities of $17.3 million, or $0.11 per share during the same period in 2012. During the three months ended June 30, 2013, adjusted funds

from operations totalled $37.1 million or $0.18 per share as compared to adjusted funds from operations of $18.5 million, or $0.11 per share during the same period in 2012. A more detailed analysis of these factors is presented within the reconciliation of Adjusted Funds from operations to cash flow from operations set out below (see Non-GAAP Performance Measures).

Cash per share provided by operating activities and per share adjusted funds from operations are non-GAAP measures. Per share cash provided by operating activities and per share adjusted funds from operations are not substitute measures of performance for earnings per share. Amounts represented by per share cash provided by operating activities and per share adjusted funds from operations do not represent amounts available for distribution to shareholders and should be considered in light of various charges and claims against APUC.

Outlook

APUC expects operational results for power generation in the third quarter of 2013 to reflect long-term average resource conditions for hydroelectric and wind power generation. Third quarter results will also continue to reflect growth from the acquisition of its newly acquired U.S. wind farms.

APUC expects continuing modest customer growth throughout its regulated utilities service territories in 2013 and that utility operations will meet APUC’s expectations for the third quarter of 2013. Third quarter results will also continue to reflect the acquisition of the Columbus/Gainesville Gas System on April 1, 2013, the Pine Bluff Water System on February 1, 2013.

APCo: Renewable Energy Division

		Long Term Average Resource				Three months ended June 30								Long Term Average Resource				Six months ended June 30
						2013				2012								2013				2012
Performance (GW-hrs sold)
Hydro Facilities:
Ontario7			35.8				16.5				31.2				72.9				24.4				67.8
Quebec			83.4				88.9				83.8				141.0				151.5				147.4
Maritime			72.3				68.6				58.6				108.0				109.9				93.9
Western			19.0				19.7				20.5				28.6				29.3				30.3
			210.5				193.7				194.1				350.5				315.1				339.4
Wind Facilities:
Manitoba			99.5				105.7				101.8				220.9				209.9				214.9
Saskatchewan1			20.8				20.4				21.2				43.9				41.3				45.1
Pennsylvania2			37.7				35.3				—				84.8				80.1				—
Illinois3			271.7				242.2				—				582.1				526.0				—
Texas4			137.4				155.0				—				288.6				300.3				—
			567.1				558.6				123.0				1,220.3				1,157.6				260.0
Total			777.6				752.3				317.1				1,570.8				1,472.7				599.4
Revenue5							(millions	)			(millions	)							(millions	)			(millions	)
Energy sales						$	37.0			$	22.3							$	76.7			$	43.8
Less:
Cost of Sales – Energy6							(1.1	)			(2.5	)							(3.5	)			(4.1	)
Net Energy Sales						$	35.9			$	19.8							$	73.2			$	39.7
Other Revenue							1.9				0.5								2.7				0.8
Total Net Revenue						$	37.8			$	20.3							$	75.9			$	40.5
Operating expenses							(9.5	)			(5.0	)							(18.4	)			(10.4	)
Interest and Other income							0.6				0.6								0.9				1.0
HLBV Income							7.5				—								12.6				—
Division operating profit						$	36.4			$	15.9							$	71.0			$	31.1

¹  APUC does not consolidate the operating results from this facility in its financial statements. Production from the facility is included as APUC manages the facility under contract and has an option to acquire a 75% equity interest in the facility in 2016.

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

³  Represents the operations of Minonk and Shady Oaks Wind Facilities acquired on December 10, 2012, and January 1, 2013, respectively. Production at the Shady Oaks Facility has been subject to congestion related curtailment by the independent system operator but where compensation is expected to be received for lost energy sales.

⁴  Represents the operations of Senate Wind Facility acquired on December 10, 2012.

⁵  While most of APCo’s PPAs include annual rate increases, a change to the weighted average production levels resulting in higher average production from facilities that earn lower energy rates can result in a lower weighted average energy rate earned by the division, as compared to the same period in the prior year.

⁶  Cost of Sales – Energy consists of energy purchases by Algonquin Energy Services (“AES”) which is resold to its retail and industrial customers. Under GAAP, in APUC’s interim consolidated Financial Statements, these amounts are included in operating expenses.

⁷  APCo’s Long Sault hydro facility was offline during most of the first half of 2013. See below for additional commentary.

2013 Six Month Operating Results

Production data, revenue and expenses have been adjusted to remove the results of the New York and New England regional assets which are now disclosed as discontinued operations. See Financial Statement note 15 for details.

For the six months ended June 30, 2013, the Renewable Energy Division produced 1,472.7GW-hrs of electricity, as compared to 599.4 GW-hrs produced in the same period in 2012, an increase of 146%. The increased generation is primarily due to the acquisition of Sandy Ridge, Minonk, Senate, and Shady Oaks Wind Facilities. This level of production represents sufficient renewable energy to supply the equivalent of 162,700 homes on an annualized basis with renewable power. Using new standards of thermal generation, as a result of renewable energy production, the equivalent of 805,327 tons of CO2 gas was prevented from entering the atmosphere in the first six months of 2013.

Adjusting for the effect of the unplanned outage at APCo’s Long Sault generating station, during the six months ended June 30, 2013, the division generated electricity equal to 97% of long-term projected average resources (wind and hydrology) as compared to 101% during the same period in 2012. In the first six months of 2013, the Ontario region’s operating facilities produced 10% above long-term average resources, while Quebec, Maritimes, Western and Texas regions produced 2% to 8% higher than long-term average resources. The Manitoba, Saskatchewan, Pennsylvania and Illinois regions experienced resources slightly lower than long-term average resources, producing 5% to 10% below long-term average resources.

For the six months ended June 30, 2013, revenue from energy sales in the Renewable Energy Division totalled $76.7 million, as compared to $43.8 million during the same period in 2012. As the purchase of energy by the Energy Services Business is a significant revenue driver and component of variable operating expenses, the division compares ‘net energy sales’ (energy sales revenue less energy purchases) as a more appropriate measure of the division’s sales results. For the six months ended June 30, 2013, net revenue from energy sales in the Renewable Energy Division totalled $73.2 million, as compared to $39.7 million during the same period in 2012.

Revenue from generation at APCo’s hydro facilities located in the Ontario, Quebec and Western regions decreased by $3.1 million primarily as a result of the Long Sault facility’s unplanned shutdown in the Ontario region offset by a 1% increase in weighted average energy rates as compared to the same period in 2012. Lost production from the unplanned shutdown at the Long Sault generating facility in Ontario was largely covered by business interruption insurance claim proceeds in the amount of $3.4 million. Further recognition of revenue under APCo’s business interruption insurance policy will not occur until final settlement of the claim expected in the fourth quarter. Revenue from APCo’s hydro facility located in the Maritime region decreased by $0.2 million primarily due to a $0.8 million decrease in weighted average energy rates offset by a $0.5 million increase in production, as compared to the same period in 2012.

Revenue from APCo’s wind facilities located in the Manitoba region increased $1.5 million due primarily to $1.8 million from the expansion of St. Leon wind facility, offset partially by $0.3 million in lower wind resources at St. Leon wind facility. APCo’s wind facilities located in the Pennsylvania, Texas, and Illinois regions consists of Sandy Ridge, Minonk, Senate and Shady Oaks Wind Facilities, acquired in 2012 and 2013, and produced revenue of $31.1 million.

Revenue at AES increased $0.3 million or 3% primarily due to a $0.5 million increase in weighted average energy rates partially offset by $0.2 million of decreased customer load served. Revenue at AES primarily consists of wholesale deliveries to local electric utilities, retail sales to commercial and industrial customers in Northern Maine, merchant sales of production in excess of committed customer deliveries from the Tinker Facility and other revenue.

For the six months ended June 30, 2013, energy purchase costs by AES totalled $3.5 million as compared to $4.1 million during the same period in 2012, a decrease of $0.6 million. AES’ decreased energy purchase costs for the six months ended June 30, 2013 was primarily due to a lower volume of energy purchases from external suppliers, partially offset by higher average prices. During this period, AES purchased approximately 33.9 GW-hrs of energy at market and fixed rates averaging U.S. $103 per MW-hr. During the six months, the Maritime region generated approximately 74% of the energy required to service its customers as well as AES’ customers, as compared to 53% in the same period in 2012.

For the six months ended June 30, 2013, other revenue totalled $2.7 million, as compared to $0.8 million in the same period in 2012, representing an increase of $1.9 million. The increase is primarily attributed to Renewable Energy Credit (REC) revenue earned at the Minonk and Sandy Ridge wind facilities.

The Red Lily I wind farm located in Saskatchewan produced 41.3 GW-hrs of electricity for the six months ended June 30, 2013. APCo’s economic return from its investment in Red Lily currently comes in the form of interest payments, fees and other charges and is not reflected in revenue from energy sales. Under the terms of the agreements, APCo has the right to exchange these contractual and debt interests in Red Lily I for a direct 75% equity interest in 2016. For the six months ended June 30, 2013, APCo earned fees and interest payments from Red Lily in the total amount of $1.2 million.

For the six months ended June 30, 2013, operating expenses excluding energy purchases totalled $18.4 million, as compared to $10.4 million during the same period in 2012, an increase of $8.0 million. The higher expenses were primarily due to the newly acquired Sandy Ridge, Senate, Minonk, and Shady Oaks Wind Facilities partially offset by lower lease and water usage costs at the Long Sault and Cote St. Catherine hydro facilities.

For the six months ended June 30, 2013, interest and other income totalled $0.9 million, consistent with the same period in 2012. Interest and other income primarily consist of interest related to the senior and subordinated debt interest in Red Lily I. This amount is included as part of APCo’s earnings from its investment in Red Lily I, as discussed above.

Hypothetical Liquidation at Book Value (“HLBV”) income represents the value of the net tax attributes generated by APCo in the period from certain of its U.S. wind power generation facilities. The value of net tax attributes generated in the first six months amounted to approximately U.S. $12.6 million.

For the six months ended June 30, 2013, the Renewable Energy Division’s operating profit totalled $71.0 million, as compared to $31.1 million during the same period in 2012, representing an increase of $39.9 million. Operating profit increased $0.4 million as a result of the stronger U.S. dollar’s impact on the division’s U.S. operations.

2013 Second Quarter Operating Results

For the quarter ended June 30, 2013, the Renewable Energy Division produced 752.3 GW-hrs of electricity, as compared to 317.1 GW-hrs produced in the same period in 2012, an increase of 137%. The increased generation is primarily due to the acquisition of Sandy Ridge, Minonk, Senate, and Shady Oaks Wind Facilities. This level of production represents sufficient renewable energy to supply the equivalent of 165,300 homes on an annualized basis with renewable power. Using new standards of thermal generation, as a result of renewable energy production, the equivalent of 409,100 tons of CO2 gas was prevented from entering the atmosphere in the second quarter of 2013.

Adjusting for the effect of the unplanned outage at APCo’s Long Sault generating station, during the quarter ended June 30, 2013, the division enjoyed the benefit of geographic and modality diversification with generated electricity equal to 99% of long-term projected average resources (wind and hydrology) as compared to 99% during the same period in 2012. In the second quarter of 2013, the Ontario region’s operating facilities produced 18% above long-term average resources. Quebec, Manitoba, Western and Texas regions produced 4% to13% higher than long-term average resources. The Maritimes, Saskatchewan, and Pennsylvania regions experienced resources slightly lower than long-term average resources, producing 2% to 6% below long-term average resources. The Illinois region produced 11% below long-term average resources with Minonk producing 162.1 GWhrs in the second quarter.

For the quarter ended June 30, 2013, revenue from energy sales in the Renewable Energy Division totalled $37.0 million, as compared to $22.3 million during the same period in 2012. As the purchase of energy by the Energy Services Business is a significant revenue driver and component of variable operating expenses, the division compares ‘net energy sales’ (energy sales revenue less energy purchases) as a more appropriate measure of the division’s sales results. For the quarter ended June 30, 2013, net revenue from energy sales in the Renewable Energy Division totalled $35.9 million, as compared $19.8 million during the same period in 2012.

Revenue from generation at APCo’s hydro facilities located in the Ontario, Quebec and Western regions decreased by $0.1 million due to an 8% decrease in production primarily a result of the Long Sault facility’s unplanned shutdown in the Ontario region offset by an 8% increase in weighted average energy rates as compared to the same period in 2012. Revenue associated with lost production from the unplanned shutdown at the Long Sault generating facility in Ontario was partially reimbursed through business interruption insurance claim proceeds in the amount of $0.6 million. Further recognition of revenue reimbursement under APCo’s business interruption insurance policy will not occur until final settlement of the claim expected in the fourth quarter. Revenue from APCo’s hydro facility located in the Maritime region decreased $0.2 million primarily due to a $0.4 million decrease in weighted average energy rates, partially offset by $0.2 million increase in production.

Revenue from APCo’s wind facilities located in the Manitoba region increased $0.7 million due primarily to $0.9 million from the expansion of St. Leon II wind facility, offset partially by $0.2 million in lower wind resources at St. Leon wind facility. Revenue from APCo’s wind facilities located in the Pennsylvania, Texas, and Illinois regions which are comprised of the US Wind Facilities acquired in 2012 and 2013, produced revenue of $14.8 million.

Revenue at AES decreased $1.1 million primarily due to a $0.8 million reclassification of intercompany energy/steam sales to the Thermal Division relating to the first quarter 2013 and $0.3 million due to decreased average energy rates. Revenue at AES primarily consists of wholesale deliveries to local electric utilities, retail sales to commercial and industrial customers in Northern Maine, merchant sales of production in excess of committed customer deliveries from the Tinker Facility and other revenue.

For the quarter ended June 30, 2013, energy purchase costs by AES totalled $1.1 million as compared to $2.5 million during the same period in 2012, a decrease of $1.4 million. AES’ decreased energy purchase costs for the quarter ended June 30, 2013 was primarily due to a lower volume of energy purchases from external suppliers, partially offset by higher average prices. During this period, AES purchased approximately 12.2 GW-hrs of energy at market and fixed rates averaging U.S. $92 per MW-hr. During the quarter, the Maritime region generated approximately 84% of the load required to service its customers as well as AES’ customers, as compared to 59% in the same period in 2012.

For the quarter ended June 30, 2013, other revenue totalled $1.9 million, as compared to $0.5 million in the same period in 2012, representing an increase of $1.4 million. The increase is primarily attributed to Renewable Energy Credit (REC) revenue earned at the Minonk and Sandy Ridge wind facilities.

The Red Lily I wind farm located in Saskatchewan produced 20.4 GW-hrs of electricity for the quarter ended June 30, 2013. APCo’s economic return from its investment in Red Lily currently comes in the form of interest payments, fees and other charges and is not reflected in revenue from energy sales. Under the terms of the agreements, APCo has the right to exchange these contractual and debt interests in Red Lily I for a direct 75% equity interest in 2016. For the quarter ended June 30, 2013, APCo earned fees and interest payments from Red Lily in the total amount of $0.8 million.

For the quarter ended June 30, 2013, operating expenses excluding energy purchases totalled $9.5 million, as compared to $5.0 million during the same period in 2012, an increase of $4.5 million. The increase was primarily driven by the increase in costs as a result of the newly acquired Sandy Ridge, Senate, Minonk, and Shady Oaks Wind Facilities.

For the quarter ended June 30, 2013, interest and other income totalled $0.6 million, consistent with the same period in 2012. Interest and other income primarily consist of interest related to the senior and subordinated debt interest in Red Lily I. This amount is included as part of APCo’s earnings from its investment in Red Lily I, as discussed above.

Hypothetical Liquidation at Book Value (“HLBV”) income represents the value of net tax attributes generated by APCo in the period from certain of its U.S. wind power generation facilities. The value of net tax attributes recognized in the second quarter amounted to approximately U.S. $7.5 million.

For the quarter ended June 30, 2013, the Renewable Energy Division’s operating profit totalled $36.4 million, as compared to $15.9 million during the same period in 2012, representing an increase of $20.5 million. Operating profit increased $0.3 million as a result of the stronger U.S. dollar’s impact on the division’s U.S. operations.

APCo: Thermal Energy Division

		Six months ended June 30, 2013												Six months ended June 30, 2012
		Windsor Locks				Sanger				Total				Windsor Locks				Sanger				Total
Performance			57.9				66.9				124.8				119.0				29.6				148.6
(GW-hrs sold)
Performance			345.4								345.4				300.6								300.6
(steam sales – billion lbs)
(all amounts in millions)
Revenue
Energy/steam sales		$	9.5			$	7.3			$	16.8			$	9.4			$	4.4			$	13.8
Less:
Cost of Sales – Fuel			(6.1	)			(2.9	)			(9.0	)			(6.3	)			(0.7	)			(7.0	)
Net Energy/Steam Sales		$	3.4			$	4.4			$	7.8			$	3.1			$	3.7			$	6.8
Other revenue			0.3				0.8				1.1				—				0.5				0.5
Total net revenue		$	3.7			$	5.2			$	8.9			$	3.1			$	4.2			$	7.3
Expenses
Operating expenses			(2.5	)			(2.7	)			(5.2	)			(2.7	)			(1.7	)			(4.4	)
Facility operating profit			1.2			$	2.5			$	3.7			$	0.4			$	2.5			$	2.9
Interest and other income											(0.2	)											0.5
Divisional operating profit										$	3.5											$	3.4

APCo’s Sanger and Windsor Locks generation facilities purchase natural gas from different suppliers and at prices based on different regional hubs. As a result, the average landed cost per unit of natural gas will differ between facility and regional changes in the average landed cost for natural gas may result in one facility showing increasing costs per unit while the other shows decreasing costs, as compared to the same period in the prior year. Total natural gas expense will vary based on the volume of natural gas consumed and the average landed cost of natural gas for each MMBTU.

2013 Six Month Operating Results

Production data, revenue and expenses have been adjusted to remove the results of the EFW Facility which are now disclosed as discontinued operations. See Financial Statement note 15 for details.

For the six months ended June 30, 2013, the Thermal Energy Division produced 124.8 GW-hrs of energy as compared to 148.6 GW-hrs of energy in the comparable period of 2012. The decrease in energy production was due primarily to the installation of the new Titan turbine which is a smaller, more efficient turbine, sized to optimize the energy and steam requirements of the steam host, and to minimize exposure of the facility to the ISO NE electricity market, compared to the larger Frame 6 turbine that was operating in previous years. This is partially offset by an increased production at Sanger as a result of a planned outage during the six month ended June 30, 2012.

For the six months ended June 30, 2013, the Thermal Division’s operating profit was $3.5 million, which was consistent with the same period in 2012. The Windsor Locks facility contributed $1.2 million, while the Sanger facility contributed $2.5 million of operating profit during the six months ended June 30, 2012 as compared to $0.4 million and $2.5 million, respectively, during the same period in the prior year. Operating profit increased $0.2 million as a result of the stronger U.S. dollar’s impact on the division’s U.S. operations. Detailed results of each facility are described below.

Windsor Locks

For the six months ended June 30, 2013, the Windsor Locks facility sold 345.4 billion lbs of steam as compared to 300.6 billion lbs of steam in the comparable period of 2012.

Energy/Steam revenues at the Windsor Locks facility were $9.5 million as compared to $9.4 million in the same period in 2012. The increase in electricity/steam sales is attributed to a higher average price for gas and higher steam production driven by increased customer demand, partially offset by the lower

electrical energy production as a result of the newly installed, smaller, more efficient Titan turbine. Natural gas costs for the period were $6.1 million as compared to $6.3 in the same period in 2012. The decrease in natural gas costs is due to a $2.1 million decrease in the volume of gas consumed as a result of the newly installed, smaller Titan turbine offset by a $1.9 million increase in the average landed cost of natural gas. As natural gas expense is a significant revenue driver and component of operating expenses, the division compares ‘net energy sales revenue’ (energy sales revenue less natural gas expense) as an appropriate measure of the division’s results. For the six months ended June 30, 2013, net energy / steam sales revenue at the Windsor Locks facility totalled $3.4 million, as compared to $3.1 million during the same period in 2012, an increase of $0.3 million. Operating expenses, excluding natural gas costs were $2.5 million as compared to $2.7 million in the same period in 2012. The decrease in operating expenses was primarily due to the reduced electricity purchases. In 2012, during the planned shutdown, the Windsor Locks facility was required to purchase all the electricity requirements for its customers; this additional expense was not required in the current year. The Windsor Locks facility’s resulting net operating income for the six months ended June 30, 2013 was $1.2 million as compared to $0.4 million in the same period in 2012, an increase of $0.8 million.

Sanger

The Sanger facility’s operating profit was driven by electrical/thermal energy sales of $7.3 million as compared to $4.4 million in the same period in 2012, an increase of $2.9 million. The increase in electrical/thermal energy is primarily a result of the Sanger facility being offline due to a planned outage for three months during the same period in the prior year. The return to operation resulted in an increase of $1.3 million due to increased electrical energy production, and $1.6 million in increased billing rates, as compared to the same period in 2012. Capacity revenues remained unchanged at $3.3 million. Gas costs for the period were $2.9 million as compared to $0.7 million in the same period in 2012. The increase in gas costs is due to an increase in the volume of natural gas consumed, and a 78% increase in the average cost of natural gas per MMBTU. As natural gas expense is a significant revenue driver and component of operating expenses, the division compares ‘net energy sales revenue’ (electricity/thermal energy sales revenue less natural gas expense) as an appropriate measure of the division’s results. For the six months ended June 30, 2013, net electricity/thermal energy sales revenue at the Sanger facility totalled $4.4 million, as compared to $3.7 million during the same period in 2012, an increase of $0.7 million. Operating expenses, excluding natural gas costs were $2.7 million as compared to $ 1.7 million in the same period in 2012. The increase in operating expenses was due to the Sanger Facility operating for the six months ended June 30, 2013, as opposed to being offline for three months during the same period in 2012. The Sanger facility’s resulting net operating income for the six months ended June 30, 2013 was $2.5 million, as compared to $2.5 million during the same period in 2012.

2013 Second Quarter Operating Results

		Three months ended June 30, 2013												Three months ended June 30, 2012
		Windsor Locks				Sanger				Total				Windsor Locks				Sanger				Total
Performance			27.9				32.7				60.6				38.6				24.6				63.2
(GW-hrs sold)
Performance			145.2								145.2				132.4								132.4
(steam sales – billion lbs)
(all amounts in millions)
Revenue
Energy/steam sales		$	5.0			$	4.7			$	9.7			$	4.2			$	3.3			$	7.5
Less:
Cost of Sales – Fuel			(2.5	)			(1.5	)			(4.0	)			(2.4	)			(0.6	)			(3.0	)
Net Energy/Steam Sales		$	2.5			$	3.2			$	5.7			$	1.8			$	2.7			$	4.5
Revenue
Other revenue			0.1				0.4				0.5								0.4				0.4
Total net revenue		$	2.6			$	3.6			$	6.2			$	1.8			$	3.1			$	4.9
Expenses
Operating expenses			(1.2	)			(1.5	)			(2.7	)			(1.7	)			(0.9	)			(2.6	)
Facility operating profit		$	1.4			$	2.1			$	3.5			$	0.1			$	2.2			$	2.3
Interest and other income											(0.5	)											0.2
Division operating profit										$	3.0											$	2.5

Production data, revenue and expenses have been adjusted to remove the results of the EFW facility which is now disclosed as discontinued operations. See Financial Statement note 15 for details

For the three months ended June 30, 2013, the Thermal Energy Division produced 60.6 GW-hrs of electrical energy as compared to 63.2 GW-hrs of electrical energy in the comparable period of 2012. The decrease in electrical energy production at the Windsor Locks facility was primarily due to the installation of the new Titan turbine which is a smaller, more efficient turbine, sized to optimize the electricity and steam requirements of the steam host, and to minimize exposure of the facility to the ISO NE electricity market, compared to the larger Frame 6 turbine that was operating in previous years. During the same period, Sanger experienced increased production as a result of a planned outage being offline for 22 days during the same period of 2012.

For the three months ended June 30, 2013, the Thermal Division’s operating profit was $3.0 million as compared to $2.5 million in the same period in 2012, an increase of $0.5 million. The Windsor Locks facility contributed $1.4 million, while the Sanger facility contributed $2.1 million of operating profit during the three months ended June 30, 2013 as compared to $0.1 million and $2.2 million, respectively during the same period in the prior year. Operating profit increased $0.1 million as a result of the stronger U.S. dollar’s impact on the division’s U.S. operations. Detailed results of each facility are described below.

Windsor Locks

For the three months ended June 30, 2013, the Windsor Locks facility sold 145.2 billion lbs of steam as compared to 132.4 billion lbs of steam in the comparable period of 2012.

The Windsor Locks facility’s operating profit was driven by electricity/steam sales of $5.0 million as compared to $4.2 million in the same period in 2012. The increase in electricity/steam sales is primarily a result of a $0.8 million reclassification of intercompany electricity/steam sales from the Renewable Energy Division relating to the first quarter of 2013. Gas costs for the period were $2.5 million as compared to $2.4 million in the same period in 2012. The increase in gas costs is a result of a 3% increase on the average landed cost of natural gas per MMBTU offset by a 2% decrease in the volume of natural gas consumed, as compared to the same period in 2012. As natural gas expense is a significant revenue driver and component of operating expenses, the division compares ‘net energy sales revenue’ (energy sales revenue less natural gas expense) as an appropriate measure of the division’s results. For the

three months ended June 30, 2013, net electrical energy / steam sales revenue at the Windsor Locks facility totalled $2.5 million, as compared to $1.8 million during the same period in 2012, an increase of $0.7 million. Operating expenses, excluding natural gas costs were $1.2 million as compared to $1.7 million in the same period in 2012. The decrease in operating expenses was primarily due to the reduced electricity purchases. In 2012 during the planned shutdown Windsor Locks was required to purchase all the electricity requirements for its customers; this additional expense was not required in the current year. The Windsor Locks facility’s resulting net operating income for the three months ended June 30, 2013 was $1.4 million as compared to $0.1 million in the same period in 2012, an increase of $1.3 million.

Sanger

The Sanger facility’s operating profit was driven by electricity/thermal energy sales of $4.7 million as compared to $3.3 million in the same period in 2012. The $1.4 million increase in electricity/thermal energy sales is attributed to increased production primarily as a result of a planned outage for 22 days during the three months ended June 30, 2012. The return to operation resulted in $1.2 million in increased energy production, in addition to $0.2 million in increased billing rates as compared to the same period in 2012. Capacity revenues remained unchanged at $2.4 million. Gas costs for the period were $1.5 million as compared to $0.6 million in the same period in 2012. The increase in gas costs is due to an increase in the volume of natural gas consumed, and a 103% increase in the average cost of natural gas per MMBTU as compared to the same period in 2012. As natural gas expense is a significant revenue driver and component of operating expenses, the division compares ‘net energy sales revenue’ (electricity/thermal energy sales revenue less natural gas expense) as an appropriate measure of the division’s results. For the three months ended June 30, 2013, net electricity/ thermal energy sales revenue at the Sanger facility totalled $3.2 million, as compared to $2.7 million during the same period in 2012, an increase of $0.5 million. Operating expenses, excluding natural gas costs were $1.5 million as compared to $0.9 million in the same period in 2012. The increase in operating expenses was due to the facility operating for the full quarter in 2013. The Sanger facility’s resulting net operating income for the three months ended June 30, 2013 was $2.1 million as compared to $2.2 million in the same period in 2012, a decrease of $0.1 million.

APCo: Development Division

The Development Division works to identify, develop and construct new power generating facilities, as well as to identify, and acquire, operating projects that would be complementary and accretive to APCo’s existing portfolio.

Projects Currently in Development

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

Project Name		Location		Size (MW)				Estimated Capital Cost				Commercial Operation				PPA Term				Production GW-hrs
Chaplin Wind 1		Saskatchewan			177			$	355.0				2016				25				720.0
Amherst Island 2		Ontario			75			$	230.0				2015				20				247.0
Val Eo 1		Quebec			24			$	70.0				2015				20				66.0
Morse Wind 3, 4		Saskatchewan			23			$	70.0				2015				20				93.0
St. Damase 1		Quebec			24			$	66.0				2014				20				78.7
Cornwall Solar 1, 2		Ontario			10			$	45.0				2013				20				13.4
Total					333			$	836.0												1,218.1

Notes:

1. PPA signed

2. FIT contract awarded

3. Two 10 MW PPAs; one 5 MW PPA

4. Comprised of three projects that are connected geographically and will be built simultaneously. All three projects were awarded PPAs under the province’s Green Options Partner Program (“GOPP”).

Project development updates for the quarter

A full description of APCo’s contracted development projects is contained in APUC’s annual MD&A. The following discussion provides updates on significant matters related to those projects.

Cornwall Solar

The Cornwall Project is a 10 MWac solar project located near Cornwall, Ontario. The project has been granted an Ontario FIT contract by the OPA, with a 20 year term and a rate of $443/MW-hr, resulting in expected initial annual revenues of approximately $6.2 million. Total capital cost of the project is targeted at approximately $45 million, including the consideration to be paid for the acquisition of the project. The project received its Renewable Energy Approval on January 15^th, 2013, and its Notice to Proceed on April 29, 2013.

Construction of the project began during the quarter with completion of construction expected late in fourth quarter of 2013 with expected annual generation of approximately 13,912 MW-hrs.

Chaplin Wind

Chaplin Wind Project is a 177MW facility located west of Moose Jaw Saskatchewan. The project has a signed 25 year PPA with SaskPower. The capital cost of the project is targeted at $355 million.

APCo expects to submit the initial Environmental Impact Assessment to Environmental Assessment Branch, Saskatchewan Environment in Q3 2013. The Environmental Assessment Branch will determine if a full Environmental Impact Assessment is required. The initial Environmental Impact Assessment contains the majority of the information and studies required in a full Environmental Impact Assessment.

Amherst Island Wind

Amherst Island Wind Project is a 75MW facility located in Prince Edward County Ontario. The project has a signed 20 year PPA with the Ontario Power Authority. The capital cost of the project is targeted at $230 million.

The Renewable Energy Approval (“REA”) application was submitted in April 2013, with an anticipated approval date to be received late in the fourth quarter of 2013. Subject to receipt of the REA, construction would commence shortly thereafter, with an expected construction completion timeframe of 12 to 18 months.

Morse Wind Project

Morse Wind Project is a 23MW facility located near Morse, Saskatchewan, approximately 180 km west of Regina. The project has a signed 20 year PPA with SaskPower. The capital cost of the project is targeted at $70 million, inclusive of acquisition costs.

The provincial permitting of the site was completed in the first quarter of 2013 and submitted to the provincial Environmental Assessment agency. In April 2013 the project was deemed a “non-development” by the Provincial Environmental Assessment Branch thereby not requiring further environmental assessment review.

Saint-Damase Wind Project

Saint-Damase Wind Project is a 24MW facility located near St. Damase, Quebec in a partnership the Municipality of Saint-Damase. The Saint-Damase Wind Project has signed a 20 year PPA with Hydro Quebec and has projected capital costs of $66 million. On June 25, 2013, the partnership executed an interconnection agreement with Hydro Quebec. The permitting and the environmental impact assessment are ongoing and the construction of the first project phase is to begin in the fall of 2013, with commercial operation for the project expected to commence in late 2014.

The project’s social acceptance is strong and there will be no requirement for a public hearing under the auspices of the Bureau d’audiences publiques sur l’environnement (“BAPE”). The environmental impact assessment for the project has also been submitted and is under review with provincial ministerial approval anticipated for the third quarter of 2013.

Val-Éo Wind Project

The Val-Éo Wind Project is a 24MW facility located in the local municipality of Saint-Gideon de Grandmont in a partnership with the Val-Éo wind cooperative formed by community based landowners. The Val-Éo Wind Project has signed a 20 year PPA with Hydro Quebec and has projected capital costs of $70 million. Preliminary permitting began in early 2011 and studies of flora and fauna are ongoing. The project received constructive comments during the open-house held on June 4, 2013 and anticipates the submission of the environmental impact study to the Minister of Sustainable Development, Environment, Wildlife and Parks in Q3 of 2013

APCo Outlook

The APCo Renewable Energy Division is expected to perform based on long-term average resource conditions for both wind and hydrology in the third quarter of 2013. In October 2012, APCo’s hydroelectric generating facility at Long Sault experienced an unplanned shut down. Three of four units at the facility were returned to service in the second quarter of 2013, with the final unit expected to return to full service during the third quarter of 2013. APCo expects its business interruption insurance to continue coverage for the lost revenue until the facility returns to full service. However, further recognition of revenue under APCo’s business interruption insurance policy will not occur until final settlement of the insurance claim expected in the fourth quarter. The acquisition of an interest in the Minonk and Senate Wind Facilities (on December 10, 2012), and the Shady Oaks Wind Facility (on January 1, 2013) are expected to contribute additional revenue in 2013.

Windsor Locks will operate in line with quarterly performance from the latter half of 2012. Sanger is expected to operate in line with historic performance.

During the quarter, the Company conducted a strategic review of the Company’s business plan and opportunities available for its Energy From Waste (“EFW”) and Brampton Cogeneration Inc. (“BCI”) facilities. The review concluded that EFW and BCI are no longer considered strategic to the ongoing operations of the Company and that management should look to divest the facilities. Accordingly, the assets of EFW are presented as assets held for sale on the unaudited interim Balance Sheet. In the second quarter of 2013, the nets assets of EFW were written down to their estimated fair value less cost of sale which resulted in a one-time write down of the net assets of $35.7 million, net of tax of $11.9 million. On June 28, 2013, APCo divested of nine small U.S. hydroelectric generating facilities that were no longer considered strategic to the ongoing operations of the Company for gross proceeds of U.S. $27 million. A tenth U.S. hydroelectric generating facility is expected to be sold in Q4, 2013. The operating results from these facilities are therefore disclosed as discontinued operations on the consolidated statements of operations and prior periods have been reclassified to conform to this presentation.

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

Utility System Type		June 30, 2013								June 30, 2012
		Regulatory Assets				Connections				Regulatory Assets				Connections
		U.S. $								U.S. $
		(millions)								(millions)
Electricity		$	261.9				90,630			$	159.0				46,955
Natural Gas			554.9				223,050				—				—
Water and Wastewater			235.5				96,650				202.9				76,800
		$	1,052.3				410,330			$	361.9				123,755

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

The Liberty Utilities (West) region is currently comprised of regulated electrical and water distribution and wastewater collection utility systems and serves approximately 115,000 active connections in the states of Arizona and California.

The Liberty Utilities (Central) region is comprised of regulated natural gas and water distribution and wastewater collection utility systems and serves approximately 110,000 active connections in the states of Arkansas, Texas, Missouri, Illinois, and Iowa.

Liberty Utilities (East) region is comprised of regulated natural gas and electric distribution utility systems and serves approximately 186,000 active connections located in the states of New Hampshire and Georgia.

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

Liberty Utilities: West Region

		Six months ended June 30
		2013				2012
Average Number of Active Electric Connections
Residential			40,800				41,350
Commercial – Small			5,440				5,510
Commercial – Large			54				54
Total Average Active Electric Connections			46,294				46,914
Average Number of Water Connections
Wastewater connections			32,000				31,050
Water distribution connections			34,970				34,120
Total Average Water Connections			66,970				65,170
Customer Usage (GW-hrs)
Residential			146.2				141.7
Commercial – Small			77.8				73.8
Commercial – Large			56.8				59.4
Total Customer Usage (GW-hrs)			280.8				274.9
Gallons Provided
Wastewater treated (millions of gallons)			860				830
Water sold (millions of gallons)			2,210				2,270
Total Gallons Provided			3,070				3,100

Liberty Utilities (West)’s increase in average water and wastewater connections during the period is primarily due to development within the service territory. During the six months ended June 30, 2013, Liberty Utilities (West) provided approximately 2,210 million gallons of water to its customers and treated approximately 860 million gallons of wastewater as compared to 2,270 million gallons of water and 830 million gallons of wastewater during the same period in 2012.

For the six months ended June 30, 2013, electricity usage at Liberty Utilities (West)’s electric utility (Calpeco Electric System) totalled 280.8 GW-hrs, as compared to 274.9 GW-hrs for the same period in 2012, an increase of 5.9 GW-hrs or 2%. This increase in usage was primarily due to colder weather in the first quarter of 2013 as compared to the warmer weather experienced in the same period a year ago. Under the base rate revenue decoupling mechanism approved by the California Public Utilities Commission (“CPUC”), which became effective on January 1, 2013, Calpeco Electric System’s base rate revenues will not be impacted by fluctuations in customer demand due to the variations in the weather conditions and changes in the number of customers. Instead, Calpeco Electric System is required to record 1/12 of its annual base rate revenue requirement each month. The electricity commodity continues to be passed through to Calpeco Electric System’s customers according to their consumption.

		Six months ended								Six months ended
		June 30								June 30
		2013				2012				2013				2012
		U.S. $ (millions)				U.S. $ (millions)				Can $ (millions)				Can $ (millions)
Water Assets for regulatory purposes			182.9				179.9
Electricity Assets for regulatory purposes			168.2				159.0
Revenue
Utility electricity sales and distribution		$	38.0			$	35.1			$	38.6			$	35.3
Wastewater treatment			9.0				8.7				9.2				8.8
Water distribution			9.3				9.3				9.4				9.3
Total Revenue		$	56.3			$	53.1			$	57.2			$	53.4
Less:
Cost of Sales – Electricity			(19.5	)			(21.4	)			(19.8	)			(21.4	)
		$	36.8			$	31.7			$	37.4			$	32.0
Expenses
Operating expenses			(17.8	)			(17.6	)			(18.3	)			(17.7	)
Other income			0.9				0.8				0.9				0.8
Divisional operating profit		$	19.9			$	14.9			$	20.0			$	15.1

2013 Six Months Operating Results

Liberty Utilities (West) has investments in water and wastewater distribution assets for regulatory purposes of U.S. $182.9 million and electricity assets for regulatory purposes of U.S. $168.2 million as at June 30, 2013, as compared to U.S. $179.9 million and U.S. $159.0 million, respectively as at June 30, 2012.

For the six months ended June 30, 2013, Liberty Utilities (West)’s revenue totalled U.S. $56.3 million as compared to U.S. $53.1 million during the same period in 2012, an increase of U.S. $3.2 million or 6%.

For the six months ended June 30, 2013, Liberty Utilities (West)’s revenue from utility electricity sales totalled U.S. $38.0 million as compared to U.S. $35.1 million during the same period in 2012, an increase of U.S. $2.9 million or 8%. This increase in revenues was primarily due to an increase in base revenue requirement approved in the most recent rate case that became effective January 1, 2013 and milder winter and spring weather that occurred in the first part of 2012. The purchase of electricity by Liberty Utilities (West) is a significant revenue driver and component of operating expenses but these costs are effectively passed through to its customers. As a result, Liberty Utilities (West) compares ‘net utility electricity sales’ (utility electricity sales less fuel and purchased power costs) as a more appropriate measure of the division’s results. For the six months ended June 30, 2013, net utility electricity sales revenues for Liberty Utilities (West) were U.S. $18.5 million, as compared to U.S. $13.7 million during the same period in 2012. Under the base rate revenue decoupling mechanism approved by the CPUC, which became effective on January 1, 2013, Calpeco Electric System’s base rate revenues will not be impacted by fluctuations in customer demand due to the variations in weather conditions and changes in the number of customers.

For the six months ended June 30, 2013, revenue from wastewater treatment and water distribution totalled U.S. $9.0 million and U.S. $9.3 million, respectively, as compared to U.S. $8.7 million and U.S. $9.3 million, respectively, during the same period in 2012. The increase in wastewater treatment revenue as compared to the previous period was due to increased connection counts, which increased fixed and usage revenue.

For the six months ended June 30, 2013, fuel and purchased power costs for Liberty Utilities (West)’s electric utility totalled U.S $19.5 million, as compared with U.S. $21.4 million for the same period in 2012. The overall electricity purchase expense decrease of U.S. $1.9 million was primarily the result of a U.S. $3.3 million decrease in weighted average electricity rates offset by U.S. $1.4 million increase in the volume of electricity purchased to meet customer demand, as compared to the same period in 2012.

For the six months ended June 30, 2013, operating expenses totalled U.S. $17.8 million, as compared to U.S. $17.6 million during the same period in 2012.

For the six months ended June 30, 2013, Liberty Utilities (West)’s operating profit was U.S. $19.9 million as compared to U.S. $14.9 million in the same period in 2012, an increase of U.S. $5.0 million.

Measured in Canadian dollars, Liberty Utilities (West)’s operating profit was $20.0 million as compared to $15.1 million in the same period in 2012.

2013 Second Quarter Operating Results

		Three months ended June 30
		2013				2012
Average Number of Active Electric Connections
Residential			41,390				41,350
Commercial – Small			5,430				5,510
Commercial – Large			54				54
Total Average Active Electric Connections			46,874				46,914
Average Number of Water Connections
Wastewater connections			32,100				31,120
Water distribution connections			35,070				34,230
Total Average Water Connections			67,170				65,350
Customer Usage (GW-hrs)
Residential			56.9				58.5
Commercial – Small			36.0				36.0
Commercial – Large			23.2				23.2
			116.1				117.7
Total Customer Usage (GW-hrs)
Gallons Provided			410				400
Wastewater treated (millions of gallons)			1,340				1,340
Water sold (millions of gallons)			1,750				1,740
Total Gallons Provided

For the three months ended June 30, 2013, Liberty Utilities (West)’s electricity usage totalled 116.1 GW-hrs, as compared to 117.7 GW-hrs for the same period in 2012, a decrease of 1.6 GW-hrs or 1%. Under the base rate revenue decoupling mechanism approved by the California Public Utilities Commission (“CPUC”), which became effective on January 1, 2013, Calpeco Electric System’s base rate revenues will not be impacted by fluctuations in customer demand due to the variations in the weather conditions and changes in the number of customers. Instead, Calpeco Electric System is required to record 1/12 of its annual base rate revenue requirement each month. The electricity commodity continues to be passed through to Calpeco Electric System’s customers according to their consumption.

During the three months ended June 30, 2013, Liberty Utilities (West) provided approximately 1,340 million gallons of water to its customers and treated approximately 410 million gallons of wastewater, as compared to 1,340 million gallons of water and 400 million gallons of wastewater during the same period in 2012.

		Three months ended								Three months ended
		June 30								June 30
		2013				2012				2013				2012
		U.S. $ (millions)				U.S. $ (millions)				Can $ (millions)				Can $ (millions)
Revenue
Utility electricity sales and distribution		$	17.1			$	15.7			$	17.5			$	15.9
Wastewater treatment			4.5				4.2				4.6				4.2
Water distribution			5.5				5.5				5.5				5.5
Total Revenue		$	27.1			$	25.4			$	27.6			$	25.6
Less:
Cost of Sales – Electricity			(8.0	)			(9.6	)			(8.2	)			(9.7	)
		$	19.1			$	15.8			$	19.4			$	15.9
Expenses
Operating expenses			(8.7	)			(8.0	)			(9.1	)			(8.3	)
Other income			0.3				0.1				0.2				0.1
Divisional operating profit		$	10.7			$	7.9			$	10.5			$	7.7

For the three months ended June 30, 2013, Liberty Utilities (West)’s revenue totalled U.S. $27.1 million as compared to U.S. $25.4 million during the same period in 2012, an increase of U.S. $1.7 million or 7%.

For the three months ended June 30, 2013, Liberty Utilities (West)’s revenue from utility electricity sales totalled U.S. $17.1 million as compared to U.S. $15.7 million during the same period in 2012, an increase of U.S. $1.4 million or 9%. This increase in revenues was primarily due to an increase in base revenue requirements approved in the most recent rate case that became effective January 1, 2013. The purchase of electricity by Liberty Utilities (West) is a significant revenue driver and component of operating expenses but these costs are effectively passed through to its customers. As a result, Liberty Utilities (West) compares ‘net utility electricity sales’ (utility electricity sales less fuel and purchased power costs) as a more appropriate measure of the division’s results. For the three months ended June 30, 2013, net utility electricity sales revenues for Liberty Utilities (West) were U.S. $9.1 million, as compared to U.S. $6.1 million during the same period in 2012. Under the base rate revenue decoupling mechanism approved by the CPUC, which became effective on January 1, 2013, Calpeco Electric System’s base rate revenues will not be impacted by fluctuations in customer demand due to the variations in weather conditions and changes in the number of customers.

For the three months ended June 30, 2013, revenue from wastewater treatment and water distribution totalled U.S. $4.5 million and U.S. $5.5 million, respectively, as compared to U.S. $4.2 million and U.S. $5.5 million, respectively, during the same period in 2012. The increase in wastewater revenue was primarily due to an increase in average connection counts, as compared to the same period in 2012.

For the three months ended June 30, 2013, fuel and purchased power costs for Liberty Utilities (West)’s electric utility totalled U.S $8.0 million, as compared with U.S. $9.6 million for the same period in 2012. The overall electricity purchase expense decrease of U.S. $1.6 million was primarily the result of a U.S. $1.3 million decrease in weighted average electricity rates and a U.S. $0.3 million decrease in the volume of electricity purchased to meet customer demand, as compared to the same period in 2012.

For the three months ended June 30, 2013, operating expenses totalled U.S. $8.7 million, as compared to U.S. $8.0 million during the same period in 2012. The increase in operating expenses was primarily due to increased general and administrative expenses as compared to the same period in 2012.

For the three months ended June 30, 2013, Liberty Utilities (West)’s operating profit was U.S. $10.7 million as compared to U.S. $7.9 million in the same period in 2012, an increase of U.S. $2.8 million or 35%.

Measured in Canadian dollars, Liberty Utilities (West)’s operating profit was $10.5 million as compared to $7.7 million in the same period in 2012.

Liberty Utilities: Central Region

		Six months ended
		June 30
		2013				2012
Average Number of Active Natural Gas Connections
Residential			72,370				—
Commercial			9,280				—
Industrial			60				—
Total Average Active Natural Gas Connections			81,710				—
Average Number of Water Connections
Wastewater connections			6,020				5,930
Water distribution connections			23,320				5,390
Total Average Water Connections			29,340				11,320
Customer Usage (MMBTU)
Residential			3,653,380				—
Commercial			1,925,100				—
Industrial			165,300				—
Total Customer Usage (MMBTU)1			5,743,780				—
Gallons Provided
Wastewater treated (millions of gallons)			190				170
Water sold (millions of gallons)			1,320				140
Total Gallons Provided			1,510				310

¹  Natural gas assets were acquired on August 1, 2012.

²  Water distribution utility was acquired on February 1, 2013

Liberty Utilities (Central) acquired its natural gas distribution and a water distribution utility system on August 1, 2012 and February 1, 2013, respectively, and accordingly, there are no results for these utilities for the corresponding period in 2012.

For the six months ended June 30, 2013, Liberty Utilities (Central) natural gas distribution sales totalled 5,743,780 MMBTU.

During the six months ended June 30, 2013, Liberty Utilities (Central) provided approximately 1,320 million gallons of water to its customers, and treated approximately 190 million gallons of wastewater, as compared to 140 million gallons of water and 170 million gallons of wastewater during the same period in 2012.

As a result of the acquisition of the Pine Bluff Water System on February 1, 2013 the number of water connections in the region increased by 17,800. The amount of water sold also correspondingly increased by 1,130 million gallons.

		Six months ended June 30								Six months ended June 30
		2013				2012				2013				2012
		U.S. $ (millions)				U.S. $ (millions)				Can $ (millions)				Can $ (millions)
Natural Gas Assets for regulatory purposes			139.9				—
Water Assets for regulatory purposes			52.5				22.9
Revenue
Utility natural gas sales and distribution 1		$	44.6			$	—			$	45.2			$	—
Wastewater treatment			2.7				2.8				2.8				2.8
Water distribution			5.4				1.7				5.5				1.7
			52.7				4.5				53.5				4.5
Less:
Cost of Sales – Natural Gas1			(27.7	)			—				(27.9	)			—
		$	25.0			$	4.5			$	25.6			$	4.5
Expenses
Operating expenses			(12.5	)			(2.5	)			(12.7	)			(2.6	)
Other income			0.2				—				0.2				—
Divisional operating profit		$	12.7				2.0				13.1				1.9

¹ Natural gas assets were acquired on August 1, 2012.

2013 Six Months Operating Results

Liberty Utilities (Central) has investments in natural gas distribution assets for regulatory purposes of U.S. $139.9 million and water distribution assets for regulatory purposes of U.S. $52.5 million as at June 30, 2013, as compared to U.S. $nil and U.S. $22.9 million, respectively as at June 30, 2012. The increase in water assets for regulatory purposes is primarily a result of the Pine Bluff Water System acquisition.

For the six months ended June 30, 2013, Liberty Utilities (Central)’s revenue totalled U.S. $52.7 million as compared to U.S. $4.5 million during the same period in 2012, an increase of U.S. $48.2 million. The increase in revenue is primarily attributed to the addition of the natural gas distribution assets acquired on August 1, 2012 and the Pine Bluff Water System acquired on February 1, 2013.

For the six months ended June 30, 2013, Liberty Utilities (Central)’s revenue from natural gas sales and distribution totalled U.S. $44.6 million. The purchase of natural gas by Liberty Utilities (Central) is a significant revenue driver and component of operating expenses but these costs are effectively passed through to its customers. As a result, the division compares ‘net utility natural gas sales and distribution revenue’ (utility natural gas sales and distribution revenue less natural gas purchases) as a more appropriate measure of the division’s results. For the six months ended June 30, 2013, net utility natural gas sales and distribution revenue for Liberty Utilities (Central) totalled U.S. $16.9 million.

For the six months ended June 30, 2013, revenue from wastewater treatment and water distribution totalled U.S. $8.1 million, as compared to U.S. $4.5 million during the same period in 2012. The increase in wastewater treatment and water distribution revenue is primarily attributed to the addition of the Pine Bluff Water System.

For the six months ended June 30, 2013, operating expenses, excluding natural gas purchases, totalled U.S. $12.5 million, as compared to U.S. $2.5 million during the same period in 2012. The increase in operating expenses can be primarily attributed to the addition of the natural gas distribution assets on August 1, 2012 and the Pine Bluff Water System acquired on February 1, 2013.

For the six months ended June 30, 2013, Liberty Utilities (Central)’s operating profit was U.S. $12.7 million as compared to U.S. $2.0 million in the same period in 2012, an increase of U.S. $10.7 million primarily attributed to the aforementioned acquisitions.

Measured in Canadian dollars, Liberty Utilities (Central)’s operating profit was $13.1 million as compared to $1.9 million in the same period in 2012.

2013 Second Quarter Operating Results

		Three months ended June 30
		2013				2012
Average Number of Active Natural Gas Connections
Residential			71,860				—
Commercial			9,220				—
Industrial			60				—
Total Average Active Natural Gas Connections			81,140				—
Average Number of Water Connections
Wastewater connections			6,040				5,940
Water distribution connections			23,320				5,400
Total Average Water Connections			29,360				11,340
Customer Usage (MMBTU)
Residential			968,980				—
Commercial			521,200				—
Industrial			59,200				—
Total Customer Usage (MMBTU)1			1,549,380				—
Gallons Provided
Wastewater treated (millions of gallons)			100				90
Water sold (millions of gallons)			800				90
Total Gallons Provided			900				180

¹ Natural gas assets were acquired on August 1, 2012.

Liberty Utilities (Central) is comprised of Liberty Utilities’ operations in Texas, Missouri, Illinois, Iowa, and Arkansas. Liberty Utilities (Central) acquired its natural gas distribution utilities and water distribution utility on August 1, 2012 and February 1, 2013, respectively, and accordingly, there are no results for these utilities for the corresponding period in 2012.

For the three months ended June 30, 2013, Liberty Utilities (Central) natural gas distribution sales totalled 1,549,380 MMBTU.

During the three months ended June 30, 2013, Liberty Utilities (Central) provided approximately 800 million gallons of water to its customers, and treated approximately 100 million gallons of wastewater, as compared to 90 million gallons of water and 90 million gallons of wastewater during the same period in 2012.

As a result of the acquisition of the Pine Bluff Water System on February 1, 2013 the number of water connections in the region increased by 17,800. The amount of water sold also correspondingly increased by 685 million gallons in the quarter.

		Three months ended June 30								Three months ended June 30
		2013				2012				2013				2012
		U.S. $ (millions)				U.S. $ (millions)				Can $ (millions)				Can $ (millions)
Revenue
Utility natural gas sales and distribution 1		$	13.7			$	—			$	14.0			$	—
Wastewater treatment			1.3				1.4				1.4				1.4
Water distribution			3.2				1.0				3.3				0.9
			18.2				2.4				18.7				2.3
Less:
Cost of Sales – Natural Gas1			(6.9	)			—				(7.0	)			—
		$	11.3			$	2.4			$	11.6			$	2.3
Expenses
Operating expenses			(6.0	)			(1.4	)			(6.1	)			(1.4	)
Other income			0.1				—				0.1				—
Divisional operating profit		$	5.4			$	1.0			$	5.6			$	0.9

¹  Natural gas assets were acquired on August 1, 2012.

²  Pine Bluff Water System acquired on February 1, 2013.

For the three months ended June 30, 2013, Liberty Utilities (Central)’s revenue totalled U.S. $18.2 million as compared to U.S. $2.4 million during the same period in 2012, an increase of U.S. $15.8 million. The increase in revenue can be primarily attributed to the addition of the natural gas distribution assets acquired on August 1, 2012 and the Pine Bluff Water System acquired on February 1, 2013.

For the three months ended June 30, 2013, Liberty Utilities (Central)’s revenue from natural gas sales and distribution totalled U.S. $13.7 million. The purchase of natural gas by Liberty Utilities (Central) is a significant revenue driver and component of operating expenses but these costs are effectively passed through to its customers. As a result, the division compares ‘net utility natural gas sales and distribution revenue’ (utility natural gas sales and distribution revenue less natural gas purchases) as a more appropriate measure of the division’s results. For the three months ended June 30, 2013, net utility natural gas sales and distribution revenue for Liberty Utilities (Central) totalled U.S. $6.8 million.

For the three months ended June 30, 2013, revenue from wastewater treatment and water distribution totalled U.S. $4.5 million, as compared to U.S. $2.4 million during the same period in 2012. The increase in wastewater treatment and water distribution revenue can be primarily attributed to the addition of the Pine Bluff Water System.

For the three months ended June 30, 2013, operating expenses, excluding natural gas purchases, totalled U.S. $6.0 million, as compared to U.S. $1.4 million during the same period in 2012. The increase in operating expenses is primarily attributed to the addition of the natural gas distribution assets on August 1, 2012 and the Pine Bluff Water System acquired on February 1, 2013.

For the three months ended June 30, 2013, Liberty Utilities (Central)’s operating profit was U.S. $5.4 million as compared to U.S. $1.0 million in the same period in 2012, an increase of U.S. $4.4 million primarily attributed to the aforementioned acquisitions.

Measured in Canadian dollars, Liberty Utilities (Central)’s operating profit was $5.6 million as compared to $0.9 million in the same period in 2012.

In the second quarter of 2012 Interim MD&A, guidance was provided on the Liberty Utilities (Central)’s expected operating results for each quarter to the end of June 30, 2013. For the three months ended June 30, 2013, Midwest Gas System’ EBITDA of U.S. $2.9 million exceeded guidance EBITDA of U.S. $2.3 million. The increased EBITDA was primarily due to operating expense savings as compared to guidance.

Liberty Utilities: East Region

		Six months ended June 301
		2013				2012
Average Number of Active Natural Gas Connections
Residential			129,260				—
Commercial and Industrial			13,680				—
Total Average Active Natural Gas Connections			142,940				—
Average Number of Active Electric Connections
Residential			35,730				—
Commercial and Industrial			7,710				—
Total Average Active Electric Connections			43,440				—
Customer Usage (GW-hrs)
Residential			141.2				—
Commercial and Industrial			309.6				—
Total Customer Usage (GW-hrs)			450.8				—
Customer Usage (MMBTU)
Residential			4,575,160				—
Commercial and Industrial			2,705,470				—
Total Customer Usage (MMBTU)			7,280,630				—

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

²  Columbus/Gainesville Gas System was acquired on April 1, 2013.

Liberty Utilities (East) is comprised of Liberty Utilities’ operations in New Hampshire and Georgia. Liberty Utilities (East) acquired its natural gas and electric distribution systems in New Hampshire on July 3, 2012 and natural gas distribution system in Georgia on April 1, 2013; accordingly, there are no results for the corresponding period in 2012.

For the six months ended June 30, 2013, Liberty Utilities (East)’s electricity usage totalled 450.8 GW-hrs and natural gas usage totalled 7,280,630 MMBTU. The newly acquired Columbus/Gainesville Gas System usage totalled 1,184,892 MMBTU.

		Six months ended								Six months ended
		June 30								June 30
		2013				2012				2013				2012
		U.S. $ (millions)				U.S. $ (millions)				Can $ (millions)				Can $ (millions)
Electricity Assets for regulatory purposes			93.7				—
Natural Gas for regulatory purposes			415.0				—
Revenue
Utility electricity sales and distribution1		$	40.0			$	—			$	40.6			$	—
Utility natural gas sales and distribution1,3			92.3				—				93.5				—
			132.3				—				134.1				—
Less:
Cost of Sales – Electricity			(26.8	)			—				(27.2	)			—
Cost of Sales – Natural Gas2			(55.3	)			—				(56.1	)			—
		$	50.2			$	—			$	50.8			$	—
Expenses
Operating expenses			(29.3	)			—				(29.7	)			—
Other Income			1.3								1.3
Division operating profit1		$	22.2			$	—			$	22.4			$	—

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

²  Natural Gas costs includes U.S. $11.4 million regulatory authorized deferral related to an under recovery of actual gas costs.

³  Columbus/Gainesville Gas System was acquired on April 1, 2013.

2013 Six Months Operating Results

Liberty Utilities (East) has investments in electricity assets for regulatory purposes of U.S. $93.7 million, and natural gas assets for regulatory purposes of U.S. $415.0 million as at June 30, 2013. The increase in gas assets for regulatory purposes from March 31, 2013 is primarily a result of the Columbus/Gainesville Gas System acquisition.

For the six months ended June 30, 2013, Liberty Utilities (East)’s revenue totalled U.S. $132.3 million.

For the six months ended June 30, 2013, Liberty Utilities (East)’s revenue from utility electricity sales totalled U.S. $40.0 million. The cost of electricity is passed through to Liberty Utilities (East)’s customers. As a result, the division compares ‘net utility electricity sales’ (revenue from electricity sales less fuel and purchased power costs) as a more appropriate measure of the division’s results. For the six months ended June 30, 2013, net electricity utility sales for Liberty Utilities (East) totalled U.S. $13.2 million.

For the six months ended June 30, 2013, Liberty Utilities (East)’s revenue from natural gas sales and distribution totalled U.S. $92.3 million, of which EnergyNorth contributed $79.8 million, while the newly acquired Columbus/Gainesville Gas System contributed $12.5 million. The cost of natural gas by Liberty Utilities (East) is passed through to Liberty Utilities (East)’s customers. As a result, the division compares ‘net utility natural gas sales and distribution revenue’ (utility natural gas sales and distribution revenue less natural gas purchases) as a more appropriate measure of the division’s results. For the six months ended June 30, 2013, net utility natural gas sales and distribution revenue for Liberty Utilities (East) totalled U.S. $37.0 million.

For the six months ended June 30, 2013, electricity purchases for Liberty Utilities (East) totalled U.S. $26.8 million, and natural gas purchases totalled U.S. $55.3 million.

For the six months ended June 30, 2013, operating expenses, excluding electricity and natural gas purchases, totalled U.S. $29.3 million.

For the six months ended June 30, 2013, other income for Liberty Utilities (East) totaled U.S. $1.3 million, and primarily consists of an equity allowance for funds utilized during construction and rental income.

For the six months ended June 30, 2013, Liberty Utilities (East)’s operating profit totalled U.S. $22.2 million.

Measured in Canadian dollars, Liberty Utilities (East)’s operating profit was $22.4 million.

2013 Second Quarter Operating Results

		Three months ended June 301
		2013				2012
Average Number of Active Natural Gas Connections
Residential			129,510				—
Commercial and Industrial			13,620				—
Total Average Active Natural Gas Connections			143,130				—
Average Number of Active Electric Connections
Residential			35,780				—
Commercial and Industrial			7,840				—
Total Average Active Electric Connections			43,620				—
Customer Usage (GW-hrs)
Residential			63.1				—
Commercial and Industrial			153.8				—
Total Customer Usage (GW-hrs)			216.9				—
Customer Usage (MMBTU)
Residential			1,713,220				—
Commercial and Industrial			1,457,750				—
Total Customer Usage (MMBTU)			3,170,970				—

¹  Granite State Electric System and EnergyNorth Gas System were acquired on July 3, 2012; Columbus/Gainesville Gas System was acquired on April 1, 2013.

For the three months ended June 30, 2013, Liberty Utilities (East)’s electricity usage totalled 216.9 GW-hrs and natural gas usage totalled 3,170,970 MMBTU. The newly acquired Columbus/Gainesville Gas System usage totalled 1,184,892 MMBTU.

		Three months ended								Three months ended
		June 30								June 30
		2013				2012				2013				2012
		U.S. $ (millions)				U.S. $ (millions)				Can $ (millions)				Can $ (millions)
Revenue
Utility electricity sales and distribution1		$	18.4			$	—			$	18.8			$	—
Utility natural gas sales and distribution1,2			33.7				—				34.5				—
			52.1				—				53.3				—
Less:
Cost of Sales – Electricity			(12.4	)			—				(12.7	)			—
Cost of Sales – Natural Gas3			(17.5	)			—				(17.9	)			—
		$	22.2			$	—			$	22.7			$	—
Expenses
Operating expenses			(16.0	)			—				(16.3	)			—
Other Income			1.0								1.0
Division operating profit1		$	7.2			$	—			$	7.4			$	—

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

²  Columbus/Gainesville Gas System was acquired on April 1, 2013.

³  Natural Gas costs includes U.S. $1.0 million regulatory authorized deferral related to an under recovery of actual gas costs.

For the three months ended June 30, 2013, Liberty Utilities (East)’s revenue totalled U.S. $52.1 million.

For the three months ended June 30, 2013, Liberty Utilities (East)’s revenue from utility electricity sales totalled U.S. $18.4 million. The cost of electricity is passed through to Liberty Utilities (East)’s customers. As a result, the division compares ‘net utility electricity sales’ (revenue from electricity sales less fuel and purchased power costs) as a more appropriate measure of the division’s results. For the three months ended June 30, 2013, net electricity utility sales for Liberty Utilities (East) totalled U.S. $6.0 million.

For the three months ended June 30, 2013, Liberty Utilities (East)’s revenue from natural gas sales and distribution totalled U.S. $33.7 million, of which EnergyNorth contributed $21.3 million, while the newly acquired Columbus/Gainesville Gas System contributed $12.4 million. The cost of natural gas by Liberty Utilities (East) is passed through to Liberty Utilities (East)’s customers. As a result, the division compares ‘net utility natural gas sales and distribution revenue’ (utility natural gas sales and distribution revenue less natural gas purchases) as a more appropriate measure of the division’s results. For the quarter ended June 30, 2013, net utility natural gas sales and distribution revenue for Liberty Utilities (East) totalled U.S. $16.2 million.

For the three months ended June 30, 2013, electricity purchases for Liberty Utilities (East) totalled U.S. $12.4 million, and natural gas purchases totalled U.S. $17.5 million.

For the three months ended June 30, 2013, operating expenses, excluding electricity and natural gas purchases, totalled U.S. $16.0 million.

For the three months ended June 30, 2013, other income for Liberty Utilities (East) totaled U.S. $1.0 million, and primarily consists of an equity allowance for funds utilized during construction and rental income.

For the three months ended June 30, 2013, Liberty Utilities (East)’s operating profit totalled U.S. $7.2 million.

Measured in Canadian dollars, Liberty Utilities (East)’s operating profit was $7.4 million.

In the second quarter 2012 Interim MD&A, guidance was provided on Granite State Electric System and EnergyNorth Gas System’s expected operating results for each quarter ending June 30, 2013. For the three months ended June 30, 2013, Granite State Electric System’s EBITDA of U.S. $1.3 million exceeded guidance EBITDA of U.S. $1.0 million, primarily due to lower than anticipated transition costs as compared to guidance. For the three months ended June 30, 2013, EnergyNorth Gas System’s EBITDA of U.S. $2.2 million was lower than guidance EBITDA of U.S. $3.9 million. The decreased EBITDA for EnergyNorth Gas System can be primarily attributed to lower than expected volumes as compared to guidance, partially offset by lower than anticipated transition costs as compared to guidance.

Regulatory Proceedings

Utility		State		Regulatory Proceeding Type		Rate Request ($000’s)				Current Status
Rio Rico Utilities Inc. (“Rio Rico Water System”)		Arizona		Rate Case		$	750			Order issued authorizing $420k annual increase
Litchfield Park Service Company (“LPSCo Water System”)		Arizona		Rate Case		$	3,000			Order expected first half of 2014
Granite State Electric Co.		New		Rate Case		$	13,169 +			Temporary Rates in effect;
(“Granite State Electric System”)		Hampshire				$	1,200 step adjustment in 2014			Hearing set for January 2014
Liberty Energy (Midstates) Corp. (“Missouri Gas System”)		Missouri		Accelerated Infrastructure Recovery		$	540k			Order expected Q4 2013

On May 31, 2012, Liberty Utilities (West) filed a general rate case with the Arizona Corporation Commission (“ACC”) related to the Rio Rico Water System. The filing sought, among other things, an increase in EBITDA by U.S. $0.8 million over 2011 results if approved as filed. On July 17, 2013, an order was received from the ACC which corresponds to an increase in EBITDA of approximately $0.4 million per year. Through the course of this rate application, Liberty Utilities also participated in a separate proceeding with other industry participants to develop a regulatory mechanism to track incremental capital expenditures in between rate cases; thus reducing regulatory lag. Liberty Utilities will be able to seek the inclusion of this mechanism in its tariffs in future rate cases, including the LPSCO Water System rate case currently before the ACC.

On February 28, 2013, Liberty Utilities (West) filed a general rate case with the Arizona Corporation Commission related to the LPSCo Water System seeking, among other things, an increase in EBITDA by U.S. $3.0 million over the 2012 results if approved as filed. The application seeks recognition of increased capital investment and increased operating expenses over current rates. In addition to a revenue increase, the application seeks an accelerated infrastructure recovery surcharge, a purchased power pass-through mechanism to recover power price increases between test years, a property tax accounting deferral to defer increases in property taxes between test years and a policy statement on rate design to begin the gradual shift of moving more revenue recovery to fixed charges versus commodity charges. New rates are expected to be implemented in the first half of 2014.

On March 29, 2013, Liberty Utilities (East)’s electric utility filed a rate case for the Granite State Electric System with the NHPUC seeking an increase in EBITDA of U.S. $13.2 million, and an additional U.S. $1.2 million increase in 2014 subject to the completion of certain capital projects. The filing is based on a 2012 test year, with revenues and expenses adjusted to reflect known and measurable changes. Among other things, Granite State Electric System requested and received approval to continue the current cost-recovery tracking mechanism related to the Reliability Enhancement and Vegetation Management Plan and was granted an annual rate increase of $0.4 million starting July 1, 2013. Granite State Electric System also requested a modification to allow for recovery of pre-staging personnel and equipment for qualifying storms. On June 27, 2013, the NHPUC approved a settlement agreement authorizing a temporary annual rate increase of $6.5 million effective July 1, 2013, and provides recognition for Liberty to request an increase to its storm recovery adjustment factor (“SRAF”). A separate petition was filed on July 12, 2013, proposing a factor which if approved corresponds to an annual increase in storm fund recovery of approximately $1.6 million for effect with rates on November 1, 2013. The case is expected to be concluded in mid-2014.

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

On July 2, 2013, Liberty Utilities (Central) filed an application on behalf of the Missouri Gas System with the Missouri Public Service Commission (“MPSC”) seeking accelerated recovery for infrastructure deployed under the utility’s infrastructure system replacement surcharge (“ISRS”). The filing seeks an increase in EBITDA of $0.5 million if approved as filed and is expected to be approved in Q4 2013.

Outlook – Liberty Utilities

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

Primarily as a result of the rate case at the Calpeco Electric System approved in late 2012, additional EBITDA of U.S. $7.1 million is expected in 2013 compared to the results achieved in the previous year.

APUC: Corporate and Other Expenses

		Three months ended June 30								Six months ended June 30
		2013				2012				2013				2012
		(millions)				(millions)				(millions)				(millions)
Corporate and other expenses:
Administrative expenses		$	7.3			$	5.5			$	12.2			$	9.9
(Gain)/Loss on foreign exchange			(0.8	)			(0.9	)			(1.3	)			(0.4	)
Interest expense			12.9				6.2				25.1				14.9
Interest, dividend and other Income			(0.8	)			(0.6	)			(1.3	)			(1.3	)
Acquisition-related costs			0.5				2.1				1.0				4.4
(Gain)/Loss on derivative financial instruments			(0.5	)			0.7				(1.9	)			0.6
Income tax expense/(recovery)			0.9				(1.0	)			7.2				(3.3	)

2013 Six Months Corporate and Other Expenses

During the six months ended June 30, 2013, administrative expenses totalled $12.2 million, as compared to $9.9 million in the same period in 2012. The expense increase in the period primarily results from additional personnel, increased wages, additional costs required to administer APUC’s operations, and other costs as compared to the same period in 2012 as a result of the continued growth in the company.

During the six months ended June 30, 2013, interest expense totalled $25.1 million as compared to $14.9 million in the same period in 2012. The increased interest expense is a result of new indebtedness incurred during the second half of 2012 used to partially finance the new acquisitions. These amounts were partially offset by reduced interest expense related to convertible debentures due to the conversion of the Series 3 Debentures in the fourth quarter of 2012, and $1.7 million in 2012 related to the Quebec water lease litigation.

During the six months ended June 30, 2013, interest, dividend and other income totalled $1.3 million, which is consistent with the same period in 2012. Interest, dividend and other income primarily consists of dividends from APUC’s share investment in the Kirkland and Cochrane facilities.

During the six months ended June 30, 2013, acquisition related costs totalled $1.0 million as compared to $4.4 million in the same period in 2012. Acquisition related costs will vary from quarter to quarter depending on the level of activity and complexity associated with various acquisitions.

An income tax expense of $7.2 million was recorded in the six months ended June 30, 2013, as compared to a recovery of $3.3 million during the same period in 2012. The income tax expenses for the six months ended June 30, 2013 is primarily due to higher earnings in the U.S. resulting from the various U.S. acquisitions completed in 2012, deferred taxes on HLBV income, the recognition of deferred credits from the utilization of deferred income tax assets recognized at the time of the Unit Exchange Offer, non-taxable inter-corporate dividends, and other items permanently excluded from Canadian taxable income.

2013 Second Quarter Corporate and Other Expenses

During the three months ended June 30, 2013, administrative expenses totalled $7.3 million, as compared to $5.5 million in the same period in 2012. The expense increase in the quarter primarily results from additional personnel, increased wages, additional costs required to administer APUC’s operations, and other costs as compared to the same period in 2012 as a result of the continued growth in the company.

During the three months ended June 30, 2013, interest expense totalled $12.9 million as compared to $6.2 million in the same period in 2012. The increased interest expense is a result of new indebtedness incurred or inherited during the second half of 2012, and the first two months of 2013 used to partially finance the new acquisitions. These amounts were partially offset by reduced interest expense related to convertible debentures due to the conversion of the Series 3 Debentures in the fourth quarter of 2012.

During the three months ended June 30, 2013, interest, dividend and other income totalled $0.8 million as compared to $0.6 million in the same period in 2012. Interest, dividend and other income primarily consists of dividends from APUC’s share investment in the Kirkland and Cochrane facilities.

During the three months ended June 30, 2013, acquisition related costs totalled $0.5 million as compared to $2.1 million in the same period in 2012. Acquisition related costs will vary from quarter to quarter depending on the level of activity and complexity associated with various acquisitions.

An income tax expense of $0.9 million was recorded in the three months ended June 30, 2013, as compared to a recovery of $1.0 million during the same period in 2012. The income tax expenses for the three months ended June 30, 2013 is primarily due to higher earnings in the U.S. resulting from the various U.S. acquisitions completed in 2012, deferred taxes on HLBV income, the recognition of deferred credits from the utilization of deferred income tax assets recognized at the time of the Unit Exchange Offer, non-taxable inter-corporate dividends, and other items permanently excluded from Canadian taxable income.

NON-GAAP PERFORMANCE MEASURES

Reconciliation of Adjusted EBITDA to net earnings

EBITDA is a non-GAAP metric used by many investors to compare companies on the basis of ability to generate cash from operations. APUC uses these calculations to monitor the amount of cash generated by APUC as compared to the amount of dividends paid by APUC. APUC uses Adjusted EBITDA to assess the operating performance of APUC without the effects of depreciation and amortization expense, income tax expense or recoveries, acquisition costs, interest expense, gain or loss on derivative financial instruments, write down of intangibles and property, plant and equipment, earnings attributable to non-controlling interests and gain or loss on foreign exchange. APUC adjusts for these factors as they may be non-cash, unusual in nature and are not factors used by management for evaluating the operating performance of the company. APUC believes that presentation of this measure will enhance an investor’s understanding of APUC’s operating performance. Adjusted EBITDA is not intended to be representative of cash provided by operating activities or results of operations determined in accordance with GAAP.

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

		Three months ended								Six months ended
		June 30								June 30
		2013				2012				2013				2012
		(millions)				(millions)				(millions)				(millions)
Net earnings/(loss) attributable to Shareholders		$	(18.1	)		$	6.1			$	1.1			$	8.3
Add (deduct):
Net earnings/(loss) attributable to the non-controlling interest, exclusive of HLBV income			4.1				0.4				7.1				1.0
(Earnings)/loss from discontinued operations			33.9				(0.8	)			35.0				(1.1	)
Income tax expense/(recovery)			0.9				(1.0	)			7.2				(3.3	)
Interest expense			12.9				6.2				25.1				14.9
Acquisition costs			0.5				2.1				1.0				4.4
Quebec water lease litigation			—				—				—				0.5
(Gain)/Loss on derivative financial instruments			(0.5	)			0.7				(1.9	)			0.6
(Gain)/Loss on foreign exchange			(0.8	)			(0.9	)			(1.3	)			(0.4	)
Depreciation and amortization			23.6				9.4				45.6				18.5
Adjusted EBITDA		$	56.5			$	22.2			$	118.9			$	43.4

Hypothetical Liquidation at Book Value (“HLBV”) income represents the value of net tax attributes earned by APCo in the period from electricity generated by certain of its U.S. wind power generation facilities. The value of net tax attributes earned in the three and six months ended June 30, 2013 amounted to approximately U.S. $7.5 million and U.S. $12.6 million, respectively.

For the six months ended June 30, 2013, Adjusted EBITDA totalled $118.9 million as compared to $43.4 million during the same period in 2012, an increase of $75.5 million. For the three months ended June 30, 2013, Adjusted EBITDA totalled $56.5 million as compared to $22.2 million during the same period in 2012, an increase of $34.3 million.

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				Six months
		ended				ended
		June 30				June 30
		(millions)				(millions)
Comparative Prior Period Adjusted EBITDA		$	22.2			$	43.4
Significant Changes:
Liberty Utilities
Increased demand and rate decoupling at the Calpeco Electric System			3.2				5.6
Acquisition of U.S. utilities			10.2				31.1
APCo:
Renewable
Increased hydrologic resource			1.3				1.8
Acquisition of U.S. Wind Facilities			17.0				33.9
Renewable Energy Credits sales			1.5				2.5
St Leon II – facility expansion			0.8				1.4
Increase due to prior year planned shutdown at Tinker facility Thermal			—				0.6
Windsor Locks – Reduced energy sales			1.4				0.7
Administrative expense			(1.8	)			(2.3	)
Increased results from the stronger U.S. dollar			0.7				1.1
Other			—				(0.9	)
Current Period Adjusted EBITDA		$	56.5			$	118.9

Reconciliation of adjusted net earnings to net earnings

Adjusted net earnings is a non-GAAP metric used by many investors to compare net earnings from operations without the effects of certain volatile primarily non-cash items that generally have no current economic impact or items such as acquisition expenses or litigation expenses and are viewed as not directly related to a company’s operating performance. Net earnings of APUC can be impacted positively or negatively by gains and losses on derivative financial instruments, including foreign exchange forward contracts, interest rate swaps and energy forward purchase contracts as well as to movements in foreign exchange rates on foreign currency denominated debt and working capital balances. Adjusted weighted average shares outstanding represents weighted average shares outstanding adjusted to remove the dilution effect related to shares issued in advance of funding requirements. APUC uses adjusted net earnings to assess its performance without the effects of gains or losses on foreign exchange, foreign exchange forward contracts, interest rate swaps, acquisition costs, litigation expenses and write down of intangibles and property, plant and equipment as these are not reflective of the performance of the underlying business of APUC. APUC believes that analysis and presentation of net earnings or loss on this basis will enhance an investor’s understanding of the operating performance of its businesses. It is not intended to be representative of net earnings or loss determined in accordance with GAAP.

The following table is derived from and should be read in conjunction with the 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								Six months ended
		June 30								June 30
		2013				2012				2013				2012
		(millions)				(millions)				(millions)				(millions)
Net earnings/(loss) attributable to Shareholders		$	(18.1	)		$	6.1			$	1.1			$	8.3
Add (deduct):
(Earnings)/loss from discontinued operations, net of tax			33.9				(0.8	)			35.0				(1.1	)
(Gain)/Loss on derivative financial instruments, net of tax			(0.4	)			0.4				(1.5	)			0.5
Quebec water lease litigation and interest, net of tax			—				—				—				1.6
Cross currency swap interest rate differential			0.2				—				0.3				—
(Gain)/Loss on foreign exchange, net of tax			(0.5	)			(0.5	)			(0.8	)			(0.2	)
Acquisition costs, net of tax			0.3				1.3				0.6				2.7
Adjusted net earnings		$	15.4			$	6.5			$	34.7			$	11.8
Adjusted net earnings per share		$	0.08			$	0.04			$	0.17			$	0.08

For the six months ended June 30, 2013, adjusted net earnings totalled $34.7 million as compared to adjusted net earnings of $11.8 million, an increase of $22.9 million as compared to the same period in 2012. The increase in adjusted net earnings for the six months ended June 30, 2013 is primarily due to higher income from operations, and interest and dividends partially offset by higher depreciation and amortization expense, higher interest expense, higher administration costs and income tax expense amounts as compared to the same period in 2012.

For the three months ended June 30, 2013, adjusted net earnings totalled $15.4 million as compared to adjusted net earnings of $6.5 million, an increase of $8.9 million as compared to the same period in 2012. The increase in adjusted net earnings for the three months ended June 30, 2013 is primarily due to higher income from operations, and interest and dividends partially offset by higher depreciation and amortization expense, higher interest expense, higher administration costs and income tax expense amounts as compared to the same period in 2012.

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

Adjusted funds from operations is a non-GAAP metric used by investors to compare cash flows from operating activities without the effects of certain volatile items that generally have no current economic impact or items such as acquisition expenses and are viewed as not directly related to a company’s operating performance. Cash flows from operating activities of APUC can be impacted positively or negatively by changes in working capital balances, acquisition and litigation expense. Adjusted weighted average shares outstanding represents weighted average shares outstanding adjusted to remove the dilution effect related to shares issued in advance of funding requirements. APUC uses adjusted funds from operations to assess its performance without the effects of changes in working capital balances, acquisition and litigation expense as these are not reflective of the long-term performance of the underlying businesses of APUC. APUC believes that analysis and presentation of funds from operations on this basis will enhance an investor’s understanding of the operating performance of its businesses. It is not intended to be representative of cash flows from operating activities as determined in accordance with GAAP.

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

The following table shows the reconciliation of funds from operations to adjusted funds from operations exclusive of these items:

		Three months ended								Six months ended
		June 30								June 30
		2013				2012				2013				2012
		(millions)				(millions)				(millions)				(millions)
Cash flows from operating activities		$	57.4			$	17.3			$	52.7			$	28.4
Add (deduct):
Changes in non-cash operating items			(23.8	)			1.7				28.1				1.4
Cash provided/(used) in discontinued operation			3.0				(2.6	)			2.9				(4.6	)
Cross currency swap interest rate differential			—				—				0.1				—
Acquisition costs			0.5				2.1				1.0				4.4
Adjusted funds from operations		$	37.1			$	18.5			$	84.8			$	29.6
Adjusted funds from operations per share		$	0.18			$	0.11			$	0.42			$	0.20

For the six months ended June 30, 2013, adjusted funds from operations totalled $84.8 million as compared to adjusted funds from operations of $29.6 million, an increase of $55.2 million as compared to the same period in 2012.

For the three months ended June 30, 2013, adjusted funds from operations totalled $37.1 million as compared to adjusted funds from operations of $18.5 million, an increase of $18.6 million as compared to the same period in 2012.

Summary of Property, Plant and Equipment Expenditures

		Three months ended								Six months ended
		June 30								June 30
		2013				2012				2013				2012
		(millions)				(millions)				(millions)				(millions)
APCo:
Renewables		$	7.9			$	6.7			$	12.0			$	9.6
Thermal			0.1				8.0				0.3				14.2
Total APCo:		$	8.0			$	14.7			$	12.3			$	23.8
Liberty Utilities:
West			2.2				3.2				3.7				4.6
Central			6.4				1.1				13.5				2.3
East			22.1				—				25.7				—
Total Liberty Utilities:			30.7				4.3				42.9				6.9
Corporate			0.7				—				0.7				—
Total		$	39.4			$	19.0			$	55.9			$	30.7

APUC has a total capital expenditure plan for all of 2013 of approximately $160 million of which $55.9 million has been invested in the half of the year leaving approximately $104.1 million expected to be invested in the second half of 2013. In 2013 APCo expects to invest approximately $60 million primarily relating to the development of the Cornwall solar project and Liberty Utilities expects to invest approximately $100 million to improve the reliability and efficiency of its gas and electric utility distribution systems.

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

2013 Six Month Property Plant and Equipment Expenditures

During the six months ended June 30, 2013, APCo incurred capital expenditures of $12.3 million, as compared to $23.8 million during the comparable period in 2012,

During the six months ended June 30, 2013, APCo’s Renewable Energy Division spent $12.0 million in capital expenditures as compared to $9.6 million in the comparable period in 2012. The capital expenditures primarily relate to major repairs and upgrades at the Long Sault and Tinker hydro facilities, as well as project costs related to the Cornwall Solar, Chaplin and St Damase developments. APCo’s Thermal Energy Division net capital expenditures were $0.3 million, as compared to $14.2 million in the comparable period in 2012. The capital expenditures in the prior year were primarily related to the Windsor Locks repowering and the major maintenance at the Sanger facility.

During the six months ended June 30, 2013, Liberty Utilities invested $42.9 million in capital expenditures as compared to $6.9 million during the comparable period in 2012. Liberty Utilities (West)’s spend was primarily related to growth and upgrades at the Calpeco Electric System and the expansion of the LPSCo Water System. Liberty Utility (Central)’s $13.5 million investment in capital expenditures was primarily related to pipe expansion and replacement activities and IT system implementations, as a result of the Midwest Gas Systems acquisition. Liberty Utility (East)’s $25.7 million investment in capital expenditures was primarily related to the installation of the Michael Ave. Substation and Enfield second supply line on the Granite State Electric system and the installation of new mains and services supporting growth and system reinforcements on the EnergyNorth Gas system.

2013 Second Quarter Property Plant and Equipment Expenditures

During the three months ended June 30, 2013, APCo incurred capital expenditures of $8.0 million, as compared to $14.7 million during the comparable period in 2012.

During the three months ended June 30, 2013, APCo’s Renewable Energy Division spent $7.9 million in capital expenditures as compared to $6.7 million in the comparable period in 2012. The capital expenditures primarily relate to major repairs and upgrades at the Long Sault and Tinker facilities, as well as project costs related to the Cornwall Solar, Chaplin Wind Project and St Damase Wind Project developments. APCo’s Thermal Energy Division net capital expenditures were $0.1 million, as compared to $8.0 million in the comparable period in 2012. The capital expenditures in the prior year were primarily related to the Windsor Locks Facility repowering and the major maintenance at the Sanger.

During the three months ended June 30, 2013, Liberty Utilities invested $30.7 million in capital expenditures as compared to $4.3 million during the comparable period in 2012. Liberty Utilities (West)’s spend was primarily related to growth and upgrades at the Calpeco Electric System and the expansion of the LPSCo Water System. Liberty Utility (Central)’s $6.4 million investment in capital expenditures was primarily related to pipe expansion and replacement activities and IT system implementations, as a result of the Missouri Gas System, and Illinois Gas System acquisitions. Liberty Utility (East)’s $22.1 million investment in capital expenditures was primarily related to the installation of the Michael Ave. Substation and Enfield second supply line on the Granite State Electric System and the installation of new mains and services supporting growth and system reinforcements on the EnergyNorth Gas System.

Quebec Dam Safety Act

As a result of the dam safety legislation passed in Quebec (Bill C93), APCo’s Renewable Energy Division completed technical assessments on its hydroelectric facility dams owned or leased within the Province of Quebec. Out of these, nine remedial plans have been submitted to and accepted by the Quebec government. The assessments have identified possible remedial work at seven facilities. Of these seven, remediation work has now been completed at two facilities, remediation work is underway at one facility, monitoring activities and options analysis are being performed for two facilities, and remedial work is being planned at two facilities.

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

		Total				2013				2014				2015				2016
Future Estimated Bill C-93 Capital Expenditures			16,900				500				5,400				5,700				5,300

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

• APCo completed the majority of the on-site remediation work for the Mont Laurier Facility in 2012 at a capital cost of approximately $0.3 million. Phase two of the on-site remediation work is scheduled for third and fourth quarters of 2013 at an estimated cost of $0.1 million.

• APCo completed the dam safety evaluation for the Donnacona Facility and has obtained the Certificate of Authorization from the Quebec government. The remedial on-site work is anticipated to start in 2014 and be completed in 2015.

• The dam safety study and a detailed condition assessment for the St. Alban Facility have been completed. APCo anticipates engineering and regulatory review to be performed in 2014, with remedial work in 2015 to 2016.

• APCo is presently reviewing options with respect to the Belleterre Facility including the removal of several small dams that are not required for power generation. APCo anticipates completion of any required work on these dams by 2016.

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

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

In addition to the C-93 related dam remediation work, APCo has implemented a dam condition monitoring program at some of the above facilities following recommendations specified in the dam safety reviews.

Liquidity and Capital Reserves

APUC has revolving operating facilities available at APUC, APCo and Liberty Utilities to manage the liquidity and working capital requirements of each division (collectively the “Facilities”).

Bank Credit Facilities

The following table sets out the amounts drawn, letters of credit issued and outstanding amounts available to APUC and its subsidiaries as at June 30, 2013 under the Facilities:

		As at June 30, 2013																As at Dec 31, 2012 Total
		APUC				APCo				Liberty Utilities				Total
		(millions)				(millions)				(millions)				(millions)				(millions)
Committed Facilities		$	30.0			$	200.0			$	105.2			$	335.2			$	329.5
Funds drawn on Facilities			—				(69.5	)			(31.6	)			(101.1	)			(54.5	)
Letters of Credit issued			(6.0	)			(42.4	)			(5.5	)			(53.9	)			(50.7	)
Funds available for draws on the Facilities		$	24.0			$	88.1			$	68.1			$	180.2			$	224.3
Cash on Hand															37.4				53.1
Total liquidity and capital reserves		$	24.0			$	88.1			$	68.1			$	217.6			$	277.4

As at June 30, 2013, the APUC $30.0 million senior unsecured revolving credit facility (“APUC Facility”) was undrawn and had $6.0 million of outstanding letters of credit.

As at June 30, 2013, the APCo $200.0 million senior unsecured revolving credit facility (the “APCo Facility”) had drawn $69.5 million and had $42.4 million in outstanding letters of credit under the APCo Facility.

As at June 30, 2013, the Liberty Utilities U.S. $100.0 million senior unsecured revolving credit facility (the “Liberty Facility”) had drawn $31.6 million and had $5.5 million of outstanding letters of credit under the Liberty Facility.

Long Term Debt

On January 1, 2013, in conjunction with the acquisition of the Shady Oaks Wind Facility, APCo assumed a U.S. $150 million dollar variable rate long term credit facility. The facility is secured by the assets of the Shady Oaks Wind Facility. APCo made a principal payment of U.S. $25 million in the second quarter of 2013 and will be required to make semi-annual principal payments ranging between U.S. $3 million and U.S. $6 million thereafter. The facility matures in 2026. Funds advanced against the facility are repayable at any time without penalty.

On March 14, 2013 Liberty Utilities entered into a U.S. $100 million non-revolving term credit facility with a U.S. Bank. On April 1, 2013 Liberty used the full amount available under the facility in connection with closing of the Columbus/Gainesville Gas System. On July 31, 2013, concurrent with the closing of the U.S. $125 million private placement the facility was repaid in full.

On March 14, 2013 Liberty Utilities completed a U.S. $15 million private placement debt financing. The notes are senior unsecured notes with a 10 year bullet maturity and carry a coupon of 4.14%.

On July 31, 2013, Liberty Utilities issued U.S. $125 million of debt through a private placement. The notes are senior unsecured with an average life maturity of ten years and a weighted average coupon of 3.81%. The proceeds of the private placement financing were used to repay the U.S. $100 million term facility and reduce the drawn amount on Liberty’s revolving credit facility.

Contractual Obligations

Information concerning contractual obligations as of June 30, 2013 is shown below:

		Total				Due less than 1 year				Due 1 to 3 years				Due 4 to 5 years				Due after 5 years
		(millions)				(millions)				(millions)				(millions)				(millions)
Long-term debt obligations 1		$	1,091.6				8.2				223.2				82.5				777.7
Advances in aid of construction		$	79.6				0.6				—				—				79.0
Interest on long-term debt obligations		$	367.8				48.7				91.4				81.5				146.2
Purchase obligations		$	115.4				115.4				—				—				—
Environmental Obligations		$	62.8				1.0				33.5				17.7				10.6
Derivative financial instruments:
Cross Currency Swap		$	6.7				—				—				—				6.7
Interest rate swap		$	3.7				1.9				1.8				—				—
Energy derivative contracts		$	10.4				1.1				0.2				—				9.1
Capital lease obligations		$	0.2				0.1				0.1				—				—
Capital projects		$	20.7				20.2				0.5
Long term service agreements		$	636.5				25.8				49.3				57.2				504.2
Purchased power		$	122.6				58.1				64.5				—				—
Gas delivery, service and supply agreements		$	119.3				26.6				28.6				11.2				52.9
Operating leases		$	110.0				5.3				9.1				6.9				88.7
Other obligations		$	20.8				4.3				—				—				16.5
Total obligations		$	2,768.1			$	317.3			$	502.2			$	257.0			$	1,691.6

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

Equity

The shares of APUC are publicly traded on the Toronto Stock Exchange (“TSX”). As at June 30, 2013, APUC had 204,997,926 issued and outstanding common shares.

APUC may issue an unlimited number of common shares. The holders of common shares are entitled to dividends, if and when declared; to one vote for each share at meetings of the holders of common shares; and to receive a pro rata share of any remaining property and assets of APUC upon liquidation, dissolution or winding up of APUC. All shares are of the same class and with equal rights and privileges and are not subject to future calls or assessments.

APUC is also authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board. As at June 30, 2013, APUC had 4,800,000 cumulative rate reset preferred shares, Series A (the “Series A Shares”) issued and outstanding, yielding 4.5% per cent annually for the initial six-year period ending on December 31, 2018. The preferred shares have been assigned a rating of P-3 and Pfd-3(low) by S&P and DBRS respectively.

As at June 30, 2013, APUC had issued 100 redeemable Series C preferred shares (the “Series C Shares”) that were issued in exchange for 100 Class B limited partnership units issued by the St. Leon Wind Energy LP. The Series C Shares are mandatorily redeemable in 2031.

APUC has a shareholder dividend reinvestment plan (the “Reinvestment Plan”) for registered holders of shares (“Shareholders”) of APUC. APUC has a shareholder dividend reinvestment plan (the “Reinvestment Plan”) for registered holders of shares (“Shareholders”) of APUC. As at June 30, 2013, 48.6 million common shares representing approximately 24% of total shares outstanding had been registered with the Reinvestment Plan, and during the second quarter 499,185 common shares were issued under the Reinvestment Plan. Subsequent to the end of the quarter, on July 15, 2013, an additional 614,136 common shares were issued under the Reinvestment Plan.

Emera subscription receipts

In 2013, a total of 15.2 million common shares have been issued to Emera for proceeds of $90.4 million pursuant to subscription agreements in contemplation of certain previously announced transactions, as outlined below:

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

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

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

As at August 12, 2013, in total, Emera owns 50.1 million APUC common shares representing approximately 24.5% of the total outstanding common shares of the Company. APUC believes issuance of shares to Emera is an efficient way to raise equity as it avoids underwriting fees, legal expenses and other costs associated with raising equity in the capital markets.

SHARE-BASED COMPENSATION PLANS

For the three and six months ended June 30, 2013, APUC recorded $563 and $987 (2012—$617 and $846) in total share-based compensation expense. No tax deduction was realized in the current year. The compensation expense is recorded as part of administrative expenses in the Consolidated Statement of Operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.

As at June 30, 2013, total unrecognized compensation costs related to non-vested options and share unit awards were $3,012 and $153 respectively, which are expected to be recognized over a period of 1.82 years and 1.35 years respectively.

STOCK OPTION PLAN

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

For the quarter ended June 30, 2013, no additional options were granted to senior executives or certain senior management of APUC. As at June 30, 2013, APUC had 4,567,129 options issued and outstanding. APUC determines the fair value of options granted using the Black-Scholes option-pricing model. The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on a straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date.

PERFORMANCE SHARE UNITS

APUC has a Performance Share Unit as part of its long-term incentive program. Performance share units (“PSUs”) are granted to certain employees annually for three-year overlapping performance cycles. The PSUs provide for settlement in cash or shares at the election of APUC. As APUC does not expect to settle these instruments in cash, these PSUs are accounted for as equity awards. For the quarter ended June 30, 2013, no additional PSUs were granted. As at June 30, 2013, 85,230 PSUs had been granted.

DIRECTORS DEFERRED SHARE UNITS

APUC has a Deferred Share Unit Plan. Under the plan, non-employee directors of APUC may elect annually to receive all or any portion of their compensation in deferred share units (“DSUs”) in lieu of cash compensation. The DSUs provide for settlement in cash or shares at the election of APUC. As APUC does not expect to settle the DSU’s in cash, these DSUs are accounted for as equity awards.

As at June 30, 2013, 61,842 DSUs had been granted.

EMPLOYEE SHARE PURCHASE PLAN

APUC has an employee share purchase plan (the “ESPP”) which allows eligible employees to use a portion of their earnings to purchase common shares of APUC. The aggregate number of shares reserved for issuance from treasury by APUC under this plan shall not exceed 2,000,000 shares. As at June 30, 2013, a total of 98,775 shares had been issued under the ESPP.

MANAGEMENT OF CAPITAL STRUCTURE

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

APUC’s objectives when managing capital are:

• To maintain its capital structure consistent with investment grade credit metrics appropriate to the sectors in which APUC operates;

• To maintain appropriate debt and equity levels in conjunction with standard industry practices and to limit financial constraints on the use of capital;

• To ensure capital is available to finance capital expenditures sufficient to maintain existing assets;

• To ensure generation of cash is sufficient to fund sustainable dividends to shareholders as well as meet current tax and internal capital requirements;

• To maintain sufficient cash reserves on hand to ensure sustainable dividends made to shareholders; and

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

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

RELATED PARTY TRANSACTIONS

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

Transactions with APMI and Senior Executives

• APUC has leased its head office facilities since 2001 from an entity owned by the shareholders of APMI on a triple net basis. Base lease costs for the three and six months ended June 30, 2013 were $84 and $168 (2012—$82 and $164).

• APUC utilizes chartered aircraft, including the use of an aircraft owned by an affiliate of APMI, Algonquin Airlink Inc. In 2004, APUC remitted $1,300 to the affiliate as an advance against expense reimbursements (including engine utilization reserves) for APUC’s business use of the aircraft. During the three and six months ended June 30, 2013, APUC incurred costs in connection with the use of the aircraft of $78 and $146 (2012—$104 and $164) and amortization expense related to the advance against expense reimbursements of $nil (2012—$88 and $155). At June 30, 2013, the remaining amount of the advance was $nil (December 31, 2012—$nil).

• Affiliates of APMI hold 60% of the outstanding Class B limited partnership units issued by the St. Leon LP, a subsidiary of APUC and the legal owner of the St. Leon facility. The related holders of the Class B units received cash distributions of $nil for the three and six months ended June 30, 2013 (2012—$80 and $155). On January 1, 2013, the Company issued 100 redeemable Series C preferred shares and exchanged such shares for the Class B units (note 10).

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

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

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

• As part of the project to re-power the Sanger facility, APUC entered into an agreement with APMI to undertake certain construction management services on the project for a performance based contingency fee. An amount of U.S. $550 has been accrued as an estimate of the final fee owed to APMI.

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

• As at June 30, 2013, due from related parties include $814 (December 31, 2012—$816) owed to APUC from APMI and due to related parties include $1,839 (December 31, 2012—$1,811) owed to APMI. These amounts arise from the transactions described above.

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

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

• Under the term sheet, it is proposed that APUC will exchange its 45% interest in the 4MW Rattle Brook hydroelectric facility (including a $0.5 million positive working capital adjustment) in return for the Parties’ residual partnership interest in the Long Sault Rapids hydroelectric facility and the equity interest in the Brampton cogeneration plant. The agreement is based on an assumed transaction date of January 1, 2012 and also settles outstanding fees owing to APMI.

Transactions with Emera

• In 2011, a subsidiary of Emera provided lead market participant services for fuel capacity and forward reserve markets to ISO NE for the Windsor Locks facility. During the three and six months ended June 30, 2013 APUC paid U.S. $nil (2012 – U.S. $69 and $160) in relation to this contract. In 2011, APUC provided a corporate guarantee to a subsidiary of Emera in an amount of U.S. $1,000 in conjunction with this contract.

• For the three and six months ended June 30, 2013, the Energy Services Business sold electricity to Maine Public Service Company (“MPS”), a subsidiary of Emera, amounting to U.S. $1,527 and $3,162 (2012 – U.S. $1,477 and $2,990). In 2011, APUC provided a corporate guarantee to MPS in an amount of U.S. $3,000 and a letter of credit in an amount of U.S. $100, primarily in conjunction with a three year contract to provide standard offer service to commercial and industrial customers in Northern Maine.

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

Business Associations with APMI and Senior Executives

There have been historic business relationships between Ian Robertson and Chris Jarratt (“Senior Executives”), APMI and related affiliates (collectively the “Parties”) and APUC. In 2011, the Board initiated a process to review all of the remaining business associations with the Parties in order to reduce, streamline and simplify these relationships. The Board formed a special committee and engaged independent consultants to assist with this process.

The co-owned assets and remaining business associations as at June 30, 2013 are listed below. During the quarter ended March 31, 2012, APUC and the Parties reached an agreement to resolve a number of the business associations and relationships (the “Agreement”). A more detailed description of the Agreement has been set out below in Settlement of Other Business Associations.

• Rattle Brook hydroelectric generating facility

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

• Brampton Cogeneration Inc.

BCI is an energy supply facility which sells steam produced from APCo’s EFW facility. APMI has a partnership 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 $0.1 in relation to the development of this project. See Settlement of Other Business Associations below for more details.

• 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. See Settlement of Other Business Associations below for more details.

• Office lease

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

• Operations services

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

• 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 fee. An amount of U.S. $0.6 million has been accrued as an estimate of the fee owed to APMI. See Settlement of Other Business Associations below for more details.

• Clean Power Income Fund

During 2007, Algonquin allowed its offer to acquire Clean Power Income Fund (“Clean Power”) to expire and earned a termination fee of $1.8 million. As part of its role in the process, APUC has agreed to pay APMI a fee of $0.1 million. Since December 31, 2011 this amount is accrued and included in due to related parties on the consolidated balance sheet. See Settlement of Other Business Associations below for more details.

• 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. See Settlement of Other Business Associations below for more details.

• Trafalgar

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

Settlement of Other Business Associations

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

Under the Agreement, APUC will exchange its 45% interest in the 4MW Rattle Brook hydroelectric facility (including a $0.5 million positive working capital adjustment) in return for the Parties’ residual equity interest in the Long Sault Rapids hydroelectric facility and the partnership interest in the Brampton cogeneration plant. The agreement also terminates all outstanding fees potentially owing to APMI in respect of historic transactions.

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

TREASURY RISK MANAGEMENT

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

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

Market price risk

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

On May 15, 2012, APCo entered into a financial hedge, which expires December 31, 2016 with respect to its Dickson Dam hydroelectric facility located in the Western region. The financial hedge is structured to hedge 75% of APCo’s production volume against exposure to the Alberta Power Pool’s current spot market rates. For the unhedged portion of production, each $10.00 per MW-hr change in the market prices in the Western region would result in a change in revenue of $0.2 million on an annualized basis.

The July 1, 2012 acquisition of Sandy Ridge Wind Facility included a financial hedge which commenced on January 1, 2013 for a 10 year period. The financial hedge is structured to hedge 72% of the Sandy Ridge Wind Facility’s production volume against exposure to PJM Western Hub current spot market rates. For the unhedged portion of production, each $10 per MW-hr change in the market prices would result in a change in revenue of about $0.3 million for the year.

The December 10, 2012 acquisition of Senate Wind Facility included a physical hedge which commenced on January 1, 2013 for a 15 year period. The physical hedge is structured to hedge 64% of Senate Wind Facility’s production volume against exposure to ERCOT North Zone current spot market rates. For the unhedged portion of production, each $10 per MW-hr change in the market prices would result in a change in revenue of about $1.1 million for the year.

The December 10, 2012 acquisition of the Minonk Wind Facility included a financial hedge which commenced on January 1, 2013 for a 10 year period. The financial hedge is structured to hedge 73% of the Minonk Wind Facility’s production volume against exposure to PJM Northern Illinois Hub current spot market rates. For the unhedged portion of production, each $10 per MW-hr change in market prices would result in a change in revenue of about $1.1 million for the year.

The January 1, 2013 acquisition of the Shady Oaks Wind Facility included a power sales contract which commenced on January 1, 2013 for a 20 year period. The power sales contract is structured to hedge the preponderance of the Shady Oaks Wind Facility’s production volume against exposure to PJM ComEd Hub current spot market rates. For the unhedged portion of production, each $10 per MW-hr change in market prices would result in a change in revenue of about $1.1 million for the year.

Interest rate risk

APUC’s operating credit facility is subject to a variable interest rate. The APUC Facility has no amounts outstanding as at June 30, 2013. As a result, a 100 basis point change in the variable rate charged would not impact interest expense.

The APCo Facility had $69.5 million outstanding as at June 30, 2013. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $7.0 million annually.

The Liberty Facility had $31.6 million outstanding as at June 30, 2013. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $3.2 million annually.

The Shady Oaks Senior Debt Facility had $131.5 million outstanding as at June 30, 2013. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $1.3 million annually.

Liquidity risk

Liquidity risk is the risk that APUC and its subsidiaries will not be able to meet their financial obligations as they become due.

Both APCo and Liberty have established financing platforms to access new liquidity from the capital markets as requirements arise. APUC continually monitors the maturity profile of its debt and adjusts accordingly to ensure sufficient liquidity exists at each of APCo and Liberty Utilities to meet their liabilities when due.

As at June 30, 2013, APUC and its subsidiaries had a combined $180.2 million of committed and available credit facilities remaining and $37.4 million of cash resulting in $217.6 million of total liquidity and capital reserves.

APUC currently pays a dividend of $0.34 per common share per year. The Board determines the amount of dividends to be paid, consistent with APUC’s commitment to the stability and sustainability of future dividends, after providing for amounts required to administer and operate APUC and its subsidiaries, for capital expenditures in growth and development opportunities, to meet current tax requirements and to fund working capital that, in its judgment, ensures APUC’s long-term success.

The long term portion of debt totals approximately $1,091.5 million with maturities set out in the Contractual Obligation table. In the event that APUC was required to replace the Facilities and project debt with borrowings having less favorable terms or higher interest rates, the level of cash generated for dividends and reinvestment may be negatively impacted.

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

Commodity price risk

APCo’s exposure to commodity prices is primarily limited to exposure to natural gas price risk. Liberty Utilities is exposed to energy price risk in its Liberty Utilities (West) and Liberty Utilities (East) regions. Additionally, Liberty Utilities is exposed to natural gas price risk in its Liberty Utilities (Central) and Liberty Utilities (East) regions. See APUC’s audited consolidated financial statements for the years ended December 31, 2012 and 2011 for discussion of this risk.

OPERATIONAL RISK MANAGEMENT

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

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

Litigation risks and other contingencies

APUC and certain of its subsidiaries are involved in various litigations, claims and other legal proceedings that arise from time to time in the ordinary course of business. Any accruals for contingencies related to these items are recorded in the financial statements at the time it is concluded that a material financial loss is likely and the related liability is estimable. Anticipated recoveries under existing insurance policies are recorded when reasonably assured of recovery.

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

With respect to the civil proceedings, the United States Second Circuit Court of Appeals dismissed all the claims against Algonquin in the civil proceedings and remanded one issue to the District Court. On April 3, 2012, the District Court granted Algonquin summary judgment on its counter-claims against Trafalgar. The District Court found that Trafalgar was in default of the indenture and the loan agreements and that Algonquin was entitled to proceed to enforce its rights against its collateral. Trafalgar filed a notice of appeal of the Memorandum-Decision and Order. The appeal was argued on March 21, 2013. On March 25, 2013, the United States Second Circuit Court of Appeals affirmed the decision of the District Court giving Algonquin judgment on its claims. Trafalgar has asked the United States Second Circuit Court of Appeals for reconsideration of its decision or to certify a legal question to the Connecticut Supreme Court. On May 21, 2013, the United States Second Circuit Court of Appeals denied TPI’s petition and the matter was sent back to the District Court for further proceedings with respect to the enforcement of Algonquin’s remedies under the loan documents, including the calculation of the debt and the disposition of collateral.

With respect to the bankruptcy proceedings, on January 30, 2013, the United States Second Circuit Court of Appeals held that Algonquin did have a security interest in Trafalgar’s engineering malpractice claim and its proceeds. On February 20, 2013, Trafalgar filed a petition for a rehearing with the United States Second Circuit Court of Appeals which petition was denied on June 17, 2013. Algonquin filed and served a motion seeking an order terminating the automatic stay and directing the distribution of the funds held in the escrow account to Algonquin. Algonquin’s motion for relief from the automatic stay has been adjourned to August 15, 2013 for submission of written arguments regarding the effect of the various decisions on the defenses TPI raised to the motion for relief from stay and for future oral argument.

On October 21, 2011 the Québec Court of Appeal ordered a subsidiary of APUC to pay approximately $5.4 million (including interest) to the government of Québec relating to water lease payments that the APUC subsidiary has been paying to the St. Lawrence Seaway Management Corporation (“Seaway Management”) under its water lease with Seaway Management in prior years. The water lease with Seaway Management contains an indemnification clause which management believes mitigates this claim and management intends to vigorously defend its position. The potential unrecoverable loss, if any, for the related prior periods could be up to $5.8 million. The parties are attempting to resolve this matter through good faith negotiations.

Quarterly Financial Information

The following is a summary of unaudited quarterly financial information for the eight quarters ended June 30, 2013:

Millions of dollars		3rd Quarter				4th Quarter				1st Quarter				2nd Quarter
(except per share amounts)		2012				2012				2013				2013
Revenue		$	93.0			$	138.9			$	193.1			$	148.8
Adjusted EBITDA			22.1				32.3				61.8				56.5
Net earnings / (loss) attributable to shareholders from continuing operations			(0.9	)			6.8				20.4				15.8
Net earnings / (loss) attributable to shareholders			(0.2	)			6.4				19.2				(18.1	)
Net earnings / (loss) per share from continuing operations			(0.01	)			0.04				0.10				0.08
Net earnings / (loss) per share			0.00				0.04				0.10				(0.09	)
Adjusted net earnings			2.9				5.6				19.4				15.4
Adjust net earnings per share			0.02				0.03				0.10				0.08
Total Assets			1,967.1				2,778.2				2,990.7				3,201.8
Long term debt*			705.1				771.8				917.5				1,091.5
Dividend declared per common share			0.08				0.08				0.08				0.09
		3rd Quarter 2011				4th Quarter 2011				1st Quarter 2012				2nd Quarter 2012
Revenue		$	59.4			$	64.8			$	58.1			$	58.7
Adjusted EBITDA			23.3				22.1				21.4				22.2
Net earnings / (loss) attributable to shareholders from continuing operations			19.2				1.9				2.0				5.3
Net earnings/(loss) attributable to shareholders			19.6				(8.5	)			2.3				6.1
Net earnings / (loss) per share from continuing operations			0.16				(0.6	)			0.02				0.03
Net earnings/(loss) per share			0.16				(0.07	)			0.02				0.04
Adjusted net earnings			22.0				13.2				5.0				6.5
Adjust net earnings per share			0.18				0.10				0.04				0.04
Total Assets			1,263.1				1,282.6				1,265.6				1,416.0
Long term debt*			472.2				455.0				391.9				461.8
Dividend declared per common share			0.07				0.07				0.07				0.07

* Long term debt includes current and long term portion of debt and convertible debentures

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

Quarterly revenues have fluctuated between $58.1 million and $193.1 million over the prior two year period. A number of factors impact quarterly results including acquisitions, seasonal fluctuations, hydrology and winter and summer rates built into the PPAs. In addition, a factor impacting revenues year over year is the fluctuation in the strength of the Canadian dollar which can result in significant changes in reported revenue from U.S. operations.

Quarterly net earnings attributable to shareholders have fluctuated between net earnings attributable to shareholders of $19.6 million and a net loss of $8.5 million over the prior two year period. Earnings have been significantly impacted by non-cash factors such as deferred tax recovery and expense, impairment of intangibles, property, plant and equipment and mark-to-market gains and losses on financial instruments.

Disclosure Controls

As of June 30, 2013, APUC carried out an evaluation, under the supervision of and with the participation of APUC’s management, including the Chief Executive Officer (“CEO”) and the Chief Financial Officer (“CFO”), of the effectiveness of the design and operations of APUC’s disclosure controls and procedures (as defined in Rule 13a – 15(e) and Rule 15d – 15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on that evaluation, the CEO and the CFO have concluded that as of June 30, 2013, APUC’s disclosure controls and procedures are effective.

Internal controls over financial reporting

Management, including the CEO and the CFO, is responsible for establishing and maintaining internal control over financial reporting. 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 (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

During the six months ended June 30, 2013, APUC acquired the Shady Oaks Wind Facility, the Pine Bluff Water System, and the Columbus/Gainesville Gas System. The financial information for these business acquisitions is included in this MD&A and in Note 3 of the unaudited interim financial statements. National Instrument 52-109 and the U.S. Securities and Exchange Commission provide an exemption, whereby companies undergoing acquisitions, can exclude the acquired business in the year from the scope of testing and assessment of operational effectiveness of controls over financial reporting. Due to the complexity associated with assessing internal controls during integration efforts, the Company plans to utilize the scope exemption as it relates to these acquisitions in management’s report on internal controls over financial reporting for the year ending December 31, 2013. The Company also excluded the 2012 acquisitions of EnergyNorth Gas System, Granite State Electric System, Missouri Gas System, Illinois Gas System, Iowa Gas System, and the Sandy Ridge, Minonk and Senate Wind Facilities from its evaluation of the effectiveness of APUC’s internal controls over financial reporting as of December 31, 2012 due to the complexity associated with assessing internal controls during integration efforts and the proximity of some of the acquisitions to year-end.

During the quarter ended June 30, 2013, there has been no change in APUC’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, APUC’s internal control over financial reporting. APUC continues to implement its internal control structure over the operations of the acquired businesses discussed above.

Critical Accounting Estimates and Polices

APUC prepared its unaudited interim 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. Significant accounting policies requiring the use of management estimates relate to the useful lives and recoverability of depreciable assets, recoverability of deferred tax assets, rate-regulation, unbilled revenue, fair value of derivatives, pension and post-retirement benefits and environmental remediation obligation. Management believes there has been no material changes during the three months ended June 30, 2013 to the items discussed in APUC’s MD&A and Note 1 of its consolidated financial statements for the year ended December 31, 2012 available on SEDAR at www.sedar.com and on the APUC website at www.AlgonquinPowerandUtilities.com. Actual results may differ from these estimates.