EX-99.6

EX-99.6 7 d587781dex996.htm EX-99.6 EX-99.6

Exhibit 99.6

Interim Consolidated Financial Statements of

Algonquin Power & Utilities Corp.

For the three and six months ended June 30, 2013 and 2012

(Unaudited)

Algonquin Power & Utilities Corp.

Interim Consolidated Balance Sheets

(Unaudited)

(thousands of Canadian dollars)


	June 30,		December 31,
	2013		2012
ASSETS
Current assets:
Cash and cash equivalents	$	37,386	$	53,122
Accounts receivable, net of allowance for doubtful accounts of $ 6,389 and $ 4,360 (note 4)		101,608		87,876
Natural gas in storage		19,728		19,279
Supplies and consumables inventory		7,016		4,233
Regulatory assets (note 5)		2,934		10,644
Due from related parties (note 16)		814		816
Prepaid expenses		12,751		10,861
Notes receivable (note 6)		566		537
Deferred tax asset		12,883		10,567
Income tax receivable		588		556
Derivative instruments (note 21)		6,700		7,020
Assets held for sale (note 15)		33,007		102,887
Other current assets		833		833

		236,814		309,231
Property, plant and equipment		2,516,951		2,086,728
Intangible assets		56,216		56,781
Goodwill		79,364		61,459
Regulatory assets (note 5)		130,896		123,748
Derivative instruments (note 21)		19,094		6,230
Long-term investments and notes receivable (note 6)		36,734		37,646
Deferred non-current income tax asset		108,291		77,497
Other assets		17,428		18,917

	$	3,201,788	$	2,778,237

Algonquin Power & Utilities Corp.

Interim Consolidated Balance Sheets

(Unaudited)

(thousands of Canadian dollars)


	June 30,			December 31,
	2013			2012
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	26,638		$	34,271
Accrued liabilities		86,902			98,269
Due to related parties (note 16)		1,839			1,811
Dividends payable (note 13)		18,294			15,498
Regulatory liabilities (note 5)		14,119			6,065
Long-term liabilities (note 7)		8,159			1,768
Other long-term liabilities		6,286			4,352
Advances in aid of construction		625			591
Derivative instruments (note 21)		3,033			2,211
Environmental obligation (note 18)		3,277			—
Preferred series C (note 10)		896			—
Liabilities held for sale		1,282			1,211
Income tax liability		1,110			539
Deferred credits		6,260			5,754
Deferred income tax liability		897			1,133

		179,617			173,473
Long-term liabilities (note 7)		1,083,293			769,058
Convertible debentures (note 8)		—			960
Advances in aid of construction		78,931			71,626
Regulatory liabilities (note 5)		88,865			82,050
Deferred income tax liability		111,455			100,798
Derivative instruments (note 21)		17,833			15,605
Deferred credits		21,796			25,816
Pension and post employment benefits (note 9)		73,129			59,246
Environmental obligation (note 18)		55,482			56,587
Other long-term liabilities		20,951			20,889
Preferred Series C (note 10)		17,857			—

		1,569,592			1,202,635
Equity:
Preferred shares (note 11(b))		116,546			116,546
Common shares (note 11(a))		1,342,774			1,245,326
Subscription receipts (note 11(a)(ii))		—			61,160
Additional paid-in capital		6,203			5,224
Deficit		(459,513	)		(406,143	)
Accumulated other comprehensive loss (note 12)		(62,389	)		(104,867	)

Total Equity attributable to shareholders of Algonquin Power & Utilities Corp.		943,621			917,246
Non-controlling interests		508,958			484,883

Total Equity		1,452,579			1,402,129
Commitments and contingencies (note 18)
Subsequent events (notes 7 and 18)

	$	3,201,788		$	2,778,237

See accompanying notes to unaudited interim consolidated financial statements

Algonquin Power & Utilities Corp.

Interim Consolidated Statements of Operations

(Unaudited)

(thousands of Canadian dollars, except per share amounts)


	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
Revenue:
Regulated electricity sales and distribution	$	36,353		$	15,913		$	79,208		$	35,299
Regulated gas sales and distributions		48,582			—			138,671			—
Regulated water reclamation and distribution		14,808			12,061			26,874			22,654
Non-regulated energy sales		46,544			29,836			93,474			57,582
Other revenue		2,463			909			3,844			1,323

		148,750			58,719			342,071			116,858

Expenses
Operating		44,856			19,854			87,903			39,143
Regulated electricity purchased		20,958			9,661			46,961			21,444
Regulated gas purchased		24,890			—			83,940			—
Non-regulated fuel for generation		3,998			3,009			9,022			7,041
Depreciation of property, plant and equipment		22,514			8,383			43,468			16,409
Amortization of intangible assets		1,061			1,038			2,100			2,077
Administrative expenses		7,348			5,478			12,205			9,859
Gain on foreign exchange		(835	)		(863	)		(1,318	)		(409	)

		124,790			46,560			284,281			95,564

Operating income from continuing operations		23,960			12,159			57,790			21,294
Interest expense		12,889			6,202			25,088			14,872
Interest, dividend and other income		(2,166	)		(1,480	)		(4,385	)		(3,596	)
Acquisition-related costs		521			2,053			1,014			4,431
Gain on derivative financial instruments (note 21(b))		(518	)		694			(1,904	)		631

		10,726			7,469			19,813			16,338

Earnings from continuing operations before income taxes		13,234			4,690			37,977			4,956
Income tax expense (recovery) (note 14)
Current		1,066			73			1,256			144
Deferred		(177	)		(1,069	)		5,980			(3,445	)

		889			(996	)		7,236			(3,301	)

Earnings from continuing operations		12,345			5,686			30,741			8,257
(Loss)/earnings from discontinued operations net of tax (note 15)		(33,890	)		784			(35,040	)		1,078

Net (loss)/earnings		(21,545	)		6,470			(4,299	)		9,335
Net (loss)/earnings attributable to non-controlling interests (note 22)		(3,454	)		402			(5,418	)		993

Net (loss)/earnings attributable to shareholders of Algonquin Power & Utilities Corp.	$	(18,091	)	$	6,068		$	1,119		$	8,342

Basic net earnings per share from continuing operations (note 17)	$	0.08		$	0.03		$	0.18		$	0.05
Basic net loss per share from discontinued operations (note 17)		(0.17	)		0.01			(0.17	)		0.01
Basic net earnings per share (note 17)		(0.09	)		0.04			0.01			0.06
Diluted net earnings per share from continuing operations (note 17)		0.08			0.03			0.18			0.05
Diluted net loss per share from discontinued operations (note 17)		(0.16	)		0.01			(0.17	)		0.01
Diluted net earnings per share (note 17)	$	(0.09	)	$	0.04		$	0.01		$	0.06

See accompanying notes to unaudited interim consolidated financial statements

Algonquin Power & Utilities Corp.

Interim Consolidated Statements of Comprehensive Income (Loss)

(Unaudited)

(thousands of Canadian dollars)


	Three months ended June 30,					Six months ended June 30,
	2013			2012		2013			2012
Net earnings	$	(21,545	)	$	6,470	$	(4,299	)	$	9,335
Other comprehensive income (loss):
Foreign currency translation adjustment, net of tax of $2,776 and $3,351 (2012—$Nil), respectively (notes 21(b)(iii) and (c))		45,534			4,887		70,878			49
Change in fair value of cash flow hedge, net of tax recovery of $1,973 and $2,711 (2012—$Nil), respectively		2,951			144		4,152			144
Change in unrealized pension and other post-retirement expense, net of tax recovery of $5 and $10 (2012—$Nil), respectively (note 9)		10			—		23			(4	)

Other comprehensive income (loss), net of tax		48,495			5,031		75,053			189

Comprehensive income (loss)		26,950			11,501		70,754			9,524
Comprehensive income (loss) attributable to the non-controlling interest		17,538			1,188		27,157			1,043

Comprehensive income (loss) attributable to shareholders of Algonquin Power & Utilities Corp.	$	9,412		$	10,313	$	43,597		$	8,481

See accompanying notes to unaudited interim consolidated financial statements

Algonquin Power & Utilities Corp.

Interim Consolidated Statement of Equity

(Unaudited)

(thousands of Canadian dollars)

For the six months ended June 30, 2013


								Additional
	Common		Preferred		Subscription			paid-in		Accumulated			Accumulated			Non-controlling
	Shares		Shares		Receipts			capital		Deficit			OCI			interests			Total
Balance, December 31, 2012	$	1,245,326	$	116,546	$	61,160		$	5,224	$	(406,143	)	$	(104,867	)	$	484,883		$	1,402,129
Net (loss)/earnings											1,119						(5,418	)		(4,299	)
Other comprehensive income		—		—		—			—		—			42,478			32,575			75,053
Dividends declared and distributions to non-controlling interests		—		—		—			—		(30,172	)		—			(3,081	)		(33,253	)
Dividends and issuance of shares under dividend reinvestment plan		5,820		—		—			—		(5,820	)		—			—			—
Exercise and conversion of subscription receipts		90,468		—		(90,468	)		—		—			—			—			—
Issuance of subscription receipts		—		—		29,308			—		—			—			—			29,308
Conversion and redemption of convertible debentures		960		—		—			—		—			—			—			960
Issuance of common shares under employee share purchase plan		200		—		—			—		—			—			—			200
Stock compensation expense		—		—		—			979		—			—			—			979
Preferred Series C shares		—							—		(18,497	)		—			—			(18,497	)

Balance, June 30, 2013	$	1,342,774	$	116,546	$	—		$	6,203	$	(459,513	)	$	(62,389	)	$	508,958		$	1,452,580

See accompanying notes to unaudited interim consolidated financial statements

Algonquin Power & Utilities Corp.

Interim Consolidated Statements of Cash Flows

(Unaudited)

(thousands of Canadian dollars)


	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
Cash provided by (used in):
Operating Activities:
Net earnings from continuing operations	$	12,345		$	5,686		$	30,741		$	8,257
Adjustments and items not affecting cash:
Depreciation of property, plant and equipment		22,514			8,383			43,468			16,409
Amortization of intangible assets		1,061			1,038			2,100			2,077
Other amortization		287			573			863			1,121
Deferred taxes		(177	)		(1,068	)		5,980			(3,445	)
Unrealized (gain)/loss on derivative financial instruments		(1,058	)		291			(2,202	)		(830	)
Share-based compensation		559			618			979			846
Pension and post retirement expense		1,047			—			1,807			—
Unrealized foreign exchange loss		—			778			—			778
Changes in non-cash operating items (note 19)		23,332			185			(27,663	)		1,521
Changes in non-cash operating items from discontinued operations (note 19)		473			(1,865	)		(481	)		(2,939	)
Cash provided from discontinued operations		(3,006	)		2,636			(2,898	)		4,598

		57,377			17,255			52,694			28,393
Financing Activities:
Cash dividends on common shares		(12,263	)		(8,602	)		(24,676	)		(16,483	)
Cash dividends on preferred shares		(1,350	)		—			(2,700	)		—
Cash distributions to non-controlling interests		(2,903	)		(133	)		(3,081	)		(258	)
Issuance of common shares		82			60,167			29,508			60,167
Proceeds from subscription receipts		—			15,000			—			15,000
Deferred financing costs		(10	)		(1,253	)		(324	)		(1,828	)
Increase in long-term liabilities		364,042			66,029			392,654			66,029
Decrease in long-term liabilities		(213,336	)		(327	)		(258,063	)		(656	)
Increase in advances in aid of construction		2,327			1,064			2,477			1,103
Increase in other long-term liabilities		—			171			—			265
Decrease in other long-term liabilities		(301	)		(92	)		(1,057	)		(160	)

		136,288			132,024			134,738			123,179
Investing Activities:
Decrease/(increase) in restricted cash		(454	)		(94	)		(648	)		680
Increase in other assets		(86	)		(2,281	)		(1,783	)		(3,545	)
Distributions received in excess of equity income		504			(433	)		818			(168	)
Receipt of principal on notes receivable		133			119			203			235
Additions to property, plant and equipment		(39,377	)		(19,024	)		(55,785	)		(29,668	)
Additions to intangibles		—			(60	)		—			(1,060	)
Acquisitions of operating entities (note 3(a),(b), and (e))		(159,486	)		(30,287	)		(172,189	)		(30,287	)
Proceeds from sale of discontinued operations		24,968			204			24,968			204

		(173,798	)		(51,856	)		(204,416	)		(63,609	)
Effect of exchange rate differences on cash		670			52			1,248			8

Increase/(decrease) in cash and cash equivalents from continuing operations		(1,425	)		94,635			(37,806	)		83,169
Increase in cash and cash equivalents from discontinued operations (note 15)		21,962			2,840			22,070			4,802
Cash and cash equivalents, beginning of the period		16,849			63,382			53,122			72,887

Cash and cash equivalents, end of the period	$	37,386		$	160,858		$	37,386		$	160,858

Supplemental disclosure of cash flow information:
Cash paid during the period for interest expense	$	7,749		$	4,448		$	20,966		$	11,604
Cash paid during the period for income taxes	$	352		$	160		$	635		$	251
Non-cash transactions
Property, plant and equipment acquisitions in accruals	$	6,146		$	2,561		$	6,146		$	2,561

See accompanying notes to consolidated financial statements

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

Algonquin Power & Utilities Corp. (“APUC” or the “Company”) is an incorporated entity under the Canada Business Corporations Act. APUC’s principal activity is the ownership of power generation facilities and water, gas and electric utilities, through investments in securities of subsidiaries including corporations, limited partnerships and trusts which carry on these businesses.

APUC’s power generation business unit conducts business under the name Algonquin Power Co. (“APCo”). APCo owns or has interests in renewable energy facilities and thermal energy facilities. APUC’s Utility Services business unit conducts business under the name of Liberty Utilities Co. (“Liberty Utilities”). Liberty Utilities operates a portfolio of utilities in the United States of America providing electric, natural gas, water distribution or wastewater services.

1.	Significant accounting policies

(a)

Basis of preparation

The accompanying unaudited interim consolidated financial statements and accompanying notes have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and follow disclosures required under Regulation S-X Rule 10-01, Interim Financial Statements provided by the Securities and Exchange Commission (“SEC”).

The significant accounting policies applied to these unaudited interim consolidated financial statements of APUC are consistent with those disclosed in the audited consolidated financial statements of APUC for the year ended December 31, 2012 except for accounting policies adopted for disclosure about offsetting assets and liabilities, comprehensive income and revenue recognition for Liberty Energy (California) (“Calpeco Electric System”) (note 1(c), (d) and note 2 below).

APUC’s operating results are subject to seasonal fluctuations that could materially impact quarter-to-quarter operating results and, thus, one quarter’s operating results are not necessarily indicative of a subsequent quarter’s operating results. APUC’s hydroelectric energy assets are primarily “run-of-river” and as such fluctuate with the natural water flows. During the winter and summer periods, flows are generally slower, while during the spring and fall periods flows are heavier. APUC’s water and wastewater utility assets’ revenues fluctuate depending on the demand for water. During drier, hotter periods of the year, which occurs generally in the summer, demand for water is typically higher than during cooler, wetter periods of the year. During the winter period, natural gas distribution utilities experience higher demand than during the summer period. Different electrical distribution utilities can experience higher or lower demand in the summer or winter depending on the specific regional weather and industry characteristics within a utility serving territory. Calpeco Electric System has historically experienced higher demand for electricity during the winter rather than during the summer period since the utility serves a number of ski hills and resorts in its service territory. Starting in 2013, as a result of the decoupling mechanism approved by its regulator (note 5), Calpeco Electric System’s earnings are no longer affected by differences in delivery volumes from levels assumed when rates were approved.

(b)

Basis of consolidation

The accompanying unaudited interim consolidated financial statements of APUC include the accounts of APUC and its wholly owned subsidiaries and variable interest entities (“VIEs”) where the Company is the primary beneficiary. Intercompany transactions and balances have been eliminated.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

1.	Significant accounting policies (continued)

(c)

Recognition of revenue

Beginning in 2013, in accordance with the revenue decoupling mechanism approved by its regulator, Calpeco Electric System is required to record approved annual delivery revenues evenly over its fiscal year. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers.

(d)

Right of offset

The fair value gains or losses recognized on derivative instruments executed with the same counterparty under a master netting arrangement are presented on a gross basis on the Consolidated Balance Sheet.

2.	Changes in Accounting Policies and Estimates

(a)

Recent accounting pronouncements

The FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities and ASU 2013-01 Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. These newly issued accounting standards require an entity to disclose both gross and net information about financial instruments and transactions eligible for offset in the balance sheet including financial instruments and transactions executed under a master netting or similar arrangement. The standards were issued to enable users of the financial statements to understand the effects or potential effects of such arrangements on an entity’s financial position. The adoption of these standards as at January 1, 2013 did not have a material impact on the Company’s interim consolidated financial statements.

The FASB issued ASU 2013-02, Comprehensive Income (Topic 220). This newly issued accounting standard requires an entity to provide certain information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes to the financial statements, the effect of, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. Other than the additional disclosure (note 12), the adoption of this standard did not have a material impact on the Company’s interim consolidated financial statements.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

2.	Changes in Accounting Policies and Estimates (continued)

(b)

Recent accounting pronouncements not yet adopted

The FASB issued ASU 2013-11, Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. This newly issued accounting standard requires an entity to present an unrecognized tax benefit, or a portion of an unrecognized tax benefit as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except in some specific situations. This ASU is required to be applied prospectively for fiscal years, and interim periods beginning after December 15, 2013. The adoption of this standard is not expected to have an impact the Company’s financial position or results of operations.

The FASB issued ASU 2013-10, Derivatives and Hedging (Topic 815): Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes. This newly issued accounting standard permit the Fed Funds Effective Swap Rate (OIS) to be used as a U.S. benchmark interest rate for hedge accounting purposes under Topic 815, in addition to interest rates on direct Treasury obligations of the U.S. government and the London Interbank Offered Rate. The amendments also remove the restriction on using different benchmark rates for similar hedges. This ASU is required to be applied prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. The adoption of this standard is not expected to have an impact the Company’s financial position or results of operations.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

3.	Business acquisitions and developments projects

(a)

Acquisition of Shady Oaks wind power facility

Effective January 1, 2013, APCo acquired the 109.5 megawatt (“MW”) Shady Oaks wind powered generating facility (“Shady Oaks”) by assuming the existing long-term debt of approximately U.S. $150,000 for no additional cash. The purchase agreement provides for final purchase price adjustments based on working capital at the acquisition date, energy generated by the project and basis differences between the relevant node and hub prices. The energy and basis related price adjustment will be based on the project’s experience from January 1, 2013 to June 30, 2014.

The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date:


Cash	$	4,683
Working capital		2,653
Property, plant and equipment		121,143
Deferred tax asset		22,790
Long term debt		(149,235	)
Asset retirement obligation		(1,363	)

Total net assets acquired	$	671

The determination of the fair value of assets and liabilities acquired has been based upon management’s preliminary estimates and certain assumptions with respect to the fair values of the assets acquired and liabilities assumed. The Company has not completed the fair value measurements, particularly that of the contingent consideration. The Company will continue to review information and perform further analysis prior to finalizing the fair value of the consideration paid and the fair value of the assets acquired and liabilities assumed. The estimated purchase price was reduced by U.S. $3,291 as at June 30, 2013 to reflect the latest information available.

Property, plant and equipment are amortized on a straight line basis over the lives of the assets, which have a weighted average life of 38 years.

Shady Oaks earns revenue from the sale of electricity and renewable energy credits and from capacity payments. Shady Oaks recognizes revenue from the sale of electricity and renewable energy credits (“RECs”) based upon the output delivered at rates specified under a long-term power purchase agreement with Commonwealth Edison Company (“ComEd”). Shady Oaks has contracted to sell approximately 310,000 MW hours of electricity (and associated RECs) to ComEd each year, commencing June 1, 2012, under this long-term power purchase agreement. On March 29, 2013, ComEd issued curtailment notice reducing the annual contract quantity for the delivery year from June 1, 2013 to May 31, 2014 to 252,617 MW hours. Electricity and associated renewable energy credits not sold to ComEd will be sold into wholesale electric markets.

Shady Oaks contributed revenue of $4,282 and $9,434 and net earnings of $956 and $2,660 to APUC’s consolidated financial results for the three and six months ended June 30, 2013. The disclosure of pro forma revenue and earnings has been deemed impracticable as Shady Oaks being a newly constructed wind power generation facility only achieved commercial operations in the second half of 2012 and therefore had little operations prior to the acquisition by APCo.

All costs related to the acquisition have been expensed in the unaudited interim Consolidated Statement of Operations.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

3.	Business acquisitions and developments projects (continued)

(b)

Acquisition of Pine Bluff Water System

On February 1, 2013, Liberty Utilities acquired United Water Arkansas Inc. a regulated water distribution utility (the “Pine Bluff Water System”) located in Pine Bluff, Arkansas. Total purchase price for the Pine Bluff Water System is approximately $27,533 (U.S. $27,600), subject to certain working capital and other closing adjustments. The following table summarizes the preliminary determination of the fair value of the assets acquired and liabilities assumed including working capital adjustments at the acquisition date:


Cash	$	8
Working capital		813
Property, plant and equipment		28,371
Regulatory assets		957
Goodwill		4,656
Other liabilities		(304	)
Pension		(3,665	)
Deferred income tax liability, net		(2,931	)

Total net assets acquired	$	27,905

The determination of the fair value of assets and liabilities acquired has been based upon management’s preliminary estimates and certain assumptions with respect to the fair values of the assets acquired and liabilities assumed. The Company has not yet completed the fair value measurements as at June 30, 2013. In particular, fair value estimates of the OPEB obligation have not yet been recorded. In addition, the purchase agreement provides for a final purchase price adjustment based on agreed working capital and rate base balances at the acquisition date. The Company will continue to review information and perform further analysis prior to finalizing the fair value of the consideration paid and the fair value of the assets acquired and liabilities assumed. The actual fair values of the assets acquired and liabilities assumed may differ from the amounts above.

Goodwill represents the excess of the fair value of the consideration paid over the fair value of net assets acquired. The contributing factors to the amount recorded as goodwill include expected future cash flows, potential operational synergies, the utilization of technology, and cost savings opportunities in the delivery of certain shared administrative and other services. The goodwill related to the Pine Bluff Water System has been reported under the Liberty Utilities (Central) segment.

Property, plant and equipment are amortized in accordance with regulatory requirements over the estimated useful life of the assets using the straight line method. The weighted average life of the Pine Bluff Water System assets is 40 years.

All costs related to the acquisition have been expensed through the unaudited interim Consolidated Statement of Operations.

Pine Bluff Water System contributed revenue of $2,361 and $3,806 and net earnings of $353 and $586 to the Company’s consolidated financial results for the three and six months ended June 30, 2013.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

3.	Business acquisitions and developments projects (continued)

(c)

Acquisition of Columbus/Gainesville Gas System

On April 1, 2013, Liberty Utilities acquired certain regulated natural gas distribution utility assets (the “Columbus/Gainesville Gas System”) located in the State of Georgia from Atmos Energy Corporation. The total purchase price for the Columbus/Gainesville Gas System is approximately $155,578 (U.S. $153,000), subject to certain working capital and other closing adjustments.

The following table summarizes the preliminary determination of the fair value of the assets acquired and liabilities assumed at the acquisition date:


Working capital	$	7,775
Property, plant and equipment		147,157
Goodwill		8,560
Deferred income tax asset, net		2,119
Derivative asset		231
Regulatory liabilities		(3,612	)
Other liabilities		(1,853	)
Pension and OPEB		(4,615	)
Derivative liabilities		(184	)

Total net assets acquired	$	155,578

The determination of the fair value of assets and liabilities acquired has been based upon management’s preliminary estimates and certain assumptions with respect to the fair values of the assets acquired and liabilities assumed. The Company has not yet completed the fair value measurements as at June 30, 2013. In addition, the purchase agreement provides for a final purchase price adjustment based on agreed working capital and rate base balances at the acquisition date. The Company will continue to review information and perform further analysis prior to finalizing the fair value of the consideration paid and the fair value of the assets acquired and liabilities assumed. The actual fair values of the assets acquired and liabilities assumed may differ from the amounts above.

Goodwill represents the excess of the fair value of the consideration paid over the fair value of net assets acquired. The contributing factors to the amount recorded as goodwill include expected future cash flows, potential operational synergies, the utilization of technology, and cost savings opportunities in the delivery of certain shared administrative and other services. The goodwill related to the Columbus/Gainesville Gas System has been reported under the Liberty Utilities (East) segment.

All costs related to the acquisition have been expensed through the unaudited interim Consolidated Statement of Operations.

Columbus/Gainesville Gas System contributed revenue of $12,668 and $12,668 and net earnings of $1,996 and $1,996 to the Company’s consolidated financial results for the three and six months ended June 30, 2013.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

3.	Business acquisitions and developments projects (continued)

(c)

Acquisition of Columbus/Gainesville Gas System (continued)

The supplemental pro forma financial information below was prepared using the acquisition method of accounting and is based on the historical financial information of APUC and Columbus/Gainesville Gas System reflecting results of operations for the three and six months ended June 30, 2013 and 2012 on a comparative basis as though the aforementioned companies were combined as of January 1, 2012. The acquiree’s pre-acquisition results have been added to APUC’s historical results, and the totals have been adjusted for the pro forma effects of acquisition-related costs, interest expense related to the financing of the business combinations, and related income taxes.


Pro forma	Three months ended				Six months ended
	June 30,				June 30,
	2013		2012		2013		2012
Total revenue from continuing operations	$	148,750	$	68,231	$	363,936	$	144,370
Net earnings from continuing operations		11,994		6,263		32,927		11,014
Basic net earnings from continuing operations per share		0.08		0.04		0.19		0.07
Diluted net earnings from continuing operations per share		0.08		0.04		0.19		0.07

The above unaudited pro forma financial information is presented for informational purposes only and does not purport to represent what the results would have been had the acquisition closed on the date assumed, nor is it necessarily indicative of the results that may be expected in future period.

Acquisition of solar energy project

On January 4, 2012, APCo acquired rights to develop a 10 MWac solar project located near Cornwall, Ontario which has been granted a Feed-in-Tariff contract by the Ontario Power Authority (“OPA”) for a 20 year term at a rate of $443/MWh. The consideration for the development rights is $4,500 plus additional contingent consideration of $3,500 based on achieving certain construction milestones. As at June 30, 2013, the Company has paid a total of $3,000 based on achieved milestones. The transaction has been recorded as a purchase of intangible assets.

(e)

Agreement to acquire New England Gas Company

On February 11, 2013, Liberty Utilities entered into an agreement with The Laclede Group, Inc. to assume the rights to purchase the assets of New England Gas Company (“New England Gas”) located in the State of Massachusetts. Total purchase price for the New England Gas net assets is approximately U.S. $74,000, subject to certain working capital and other closing adjustments. Closing of the transaction is subject to certain conditions including state and federal regulatory approval, and is expected to occur in the second half of 2013.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

3.	Business acquisitions and developments projects (continued)

(f)

Acquisition of New Hampshire electric and gas utilities

After the December 31, 2012 consolidated financial statements were issued, the Company received additional information which was used to refine the estimates for fair value of assets acquired and liabilities assumed for the New Hampshire electric and gas utilities. The carrying value of those assets and liabilities were retrospectively adjusted to the amounts detailed in the table below. As a result, the total consideration was reduced by $9,277, working capital acquired was reduced by $9,697 and goodwill was increased by $957.


	Granite State			EnergyNorth			Total
Cash	$	395		$	—		$	395
Restricted cash		3,252			—			3,252
Working capital		1,916			15,420			17,336
Property, plant and equipment		86,935			256,305			343,240
Regulatory assets		31,683			87,126			118,809
Deferred financing		31			—			31
Other assets		—			83			83
Goodwill		—			28,537			28,537
Customer deposits		(661	)		(962	)		(1,623	)
Long-term debt		(15,188	)		—			(15,188	)
Other long-term liabilities		(1,468	)		(3,287	)		(4,755	)
Advances in aid of construction		—			(86	)		(86	)
Derivative liabilities		—			(2,598	)		(2,598	)
Regulatory liabilities		(5,533	)		(27,456	)		(32,989	)
Pension and OPEB		(19,108	)		(29,197	)		(48,305	)
Environmental obligation		—			(54,431	)		(54,431	)
Deferred income tax liabilities, net		—			(61,484	)		(61,484	)
		82,254			207,970			290,224

Less: Cash acquired		(395	)		—			(395	)

Total net assets acquired	$	81,859		$	207,970		$	289,829

4.	Accounts receivable

Accounts receivable as of June 30, 2013, includes unbilled revenue of $15,201 (December 31, 2012 - $22,658) in the regulated utilities. The unbilled revenue is an estimate of the amount of utility revenue earned since the date the meters were last read.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

5.	Regulatory matters

The Company’s regulated utility operating companies owned by Liberty Utilities are subject to regulation by the public utility commissions of the states in which they operate. The respective public utility commissions have jurisdiction with respect to rate, service, accounting policies, issuance of securities, acquisitions and other matters. These utilities operate under cost-of-service regulation as administered by these state authorities. The Company`s regulated utility operating companies are accounted for under the principles of U.S. Financial Accounting Standards Board ASC Topic 980 Regulated Operations (“ASC 980”). Under ASC 980, regulatory assets and liabilities that would not be recorded under U.S. GAAP for non-regulated entities are recorded to the extent that they represent probable future revenues or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate setting process.

On November 29, 2012, Calpeco Electric System’s regulator approved an All Parties General Rate Case Settlement. As an element of the decision, a revenue decoupling mechanism and a vegetation management memorandum account was agreed upon. The revenue decoupling mechanism will isolate base revenues from fluctuations caused by weather and economic factors. The vegetation management memorandum account allows for the tracking and pass through of vegetation management expenses to customers, one of the largest expenses of the utility.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

5.	Regulatory matters (continued)

Regulatory assets and liabilities consist of the following:


	June 30, 2013			December 31, 2012
Regulatory assets:
Environmental costs	$	62,310		$	59,789
Pension and other post employment benefits		50,030			47,838
Storm costs deferral		6,575			6,726
Energy costs adjustment		1,249			7,962
Derivative assets		1,303			1,731
Rate case costs		2,468			2,398
Vegetation management		1,946			2,082
Alternative revenue program		98			272
Rate adjustment mechanism		73			—
Asset retirement obligation		1,417			1,095
Other		6,361			4,499

Total regulatory assets		133,830			134,392
Less current regulatory assets		(2,934	)		(10,644	)

Non-current regulatory assets	$	130,896		$	123,748

Regulatory liabilities
Cost of removal	$	67,706		$	58,852
Rate-base offset		15,573			15,541
Energy costs adjustment		16,661			11,706
Pension and other post employment benefits		1,064			1,127
Derivative liabilities		14			616
Other		1,966			273

Total regulatory liabilities		102,984			88,115
Less current regulatory liabilities		(14,119	)		(6,065	)

Non-current regulatory liabilities	$	88,865		$	82,050

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

6.	Long-term investments and notes receivable

Long-term investments and notes receivable consist of the following:


	June 30, 2013			December 31, 2012
Long –term investments
32.4% of Class B non-voting shares of Kirkland Lake Power Corp.	$	4,851		$	4,926
25% of Class B non-voting shares of Cochrane Power Corporation		4,048			4,669
45% interest in the Algonquin Power (Rattle Brook) Partnership		4,032			3,884
50% interest in the Valley Power Partnership		1,371			1,767
Other		321			180

Total long-term investments	$	14,623		$	15,426

Notes receivable
Red Lily Senior loan, interest at 6.31%	$	11,588		$	11,588
Red Lily Subordinated loan, interest at 12.5%		6,565			6,565
Chapais Énergie, Société en Commandite interest at 10.789% and 4.91%, respectively		2,195			2,448
Silverleaf resorts loan, interest at 15.48% maturing July 2020		2,125			2,010
Other		204			146

		22,677			22,757
Less: current portion		(566	)		(537	)

Total long-term notes receivable	$	22,111		$	22,220

Total long-term investments and notes receivable	$	36,734		$	37,646

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

7.	Long-term liabilities

Long-term liabilities consist of the following:


	June 30, 2013			December 31, 2012
APCo
Revolving credit facility	$	69,516		$	27,074
Senior debt Shady Oaks		131,475			—
Senior Unsecured notes		149,915			149,910
Senior Unsecured notes		134,822			134,807
Senior debt Long Sault Rapids		37,652			38,136
Sanger bonds		20,194			19,102
Senior debt Chute Ford		3,595			3,763
Liberty Utilities
Revolving credit facility		31,554			27,360
Unsecured term facility		105,180			—
Liberty Utilities Co.
Senior unsecured notes		252,432			223,852
California Pacific Electric Company, LLC
Senior unsecured notes		73,626			69,643
Liberty Water Co.
Senior unsecured notes		52,590			49,745
Granite State Electric Company
Senior Unsecured notes		15,777			14,924
Litchfield Park Service Company
IDABonds		11,888			11,269
Bella Vista Water
Water Infrastructure Financing Authority of Arizona loans		1,236			1,241

		1,091,452			770,826
Less: current portion		(8,159	)		(1,768	)

	$	1,083,293		$	769,058

APCo

Effective January 1, 2013, concurrent with the acquisition of Shady Oaks (note 3(a)), APCo assumed existing long-term debt of approximately U.S. $150 million. A portion of the long-term debt of U.S. $25,000 was repaid on June 30, 2013 and another current portion of U.S. $3,000 is payable on November 15, 2013. The semi-annual principal repayment schedule for the following 11 years ranges from U.S., $3,000 to U.S. $6,000 with a final repayment of U.S. $20,000 in 2025. This debt may be repaid in whole or in part at anytime without penalty and bears interest at Libor plus 280 basis points.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

7.	Long-term liabilities (continued)

Liberty Utilities

On March 14, 2013, Liberty Utilities issued U.S. $15,000 of senior unsecured notes through a private placement in connection with the acquisition of the Pine Bluff Water System (note 3 (b)). The notes bear interest at 4.14% and mature in 10 years.

On March 14, 2013, Liberty Utilities entered into a variable rate unsecured U.S. $100,000 term facility with a U.S. Bank. On April 1, 2013, Liberty Utilities drew U.S. $100,000 from the facility to fund a portion of the acquisition of the Columbus/Gainesville Gas System (note 3(c)). Subsequent to quarter end on July 31, 2013, Liberty Utilities issued U.S. $125,000 of senior unsecured notes through a private placement in three tranches: U.S. $25,000, bearing an interest rate of 3.23%, maturing July 31, 2020; U.S. $75,000, bearing an interest rate of 3.86%, maturing July 31, 2023; and, U.S. $25,000, bearing an interest rate of 4.26%, maturing July 31, 2028. The proceeds of the private placement financing were used to repay the U.S. $100,000 term facility and reduce the drawn amount on Liberty’s revolving credit facility. As a result of its long term refinancing subsequent to quarter end, the term facility is classified as non-current as at June 30, 2013.

8.	Convertible debentures

On January 2, 2013, the remaining principal amount of $960 of Series 3 Debentures was redeemed for 150,816 shares of APUC (note 11(a)(i)).

9.	Pension and other post-retirement benefits

The following table lists the components of net benefit costs for the pension plans and Other Post Employment Benefits (“OPEB”) recorded as part of administrative expenses in the unaudited interim Consolidated Statements of Operations. The Consolidated Statements of Operations reflect the employee benefit costs for businesses acquired from the date of acquisition. The portion of employee benefit costs capitalized as cost of construction is insignificant.


	Pension benefits
	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
Service cost	$	729		$	81		$	1,380		$	162
Interest cost		1,064			6			2,049			11
Expected return on plan assets		(1,027	)		(4	)		(1,948	)		(9	)
Amortization of net actuarial loss		2			—			4			—
Amortization of regulatory assets/liabilities		122			1			242			1

Net benefit cost	$	890		$	84		$	1,727		$	165


	OPEB
	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
Service cost	$	388		$	—		$	675		$	—
Interest cost		348			—			653			—
Expected return on plan assets		(149	)		—			(297	)		—
Amortization of net actuarial loss		10			—			19			—
Amortization of regulatory assets/liabilities		52			—			103			—

Net benefit cost	$	649		$	—		$	1,153		$	—

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

10.

Mandatorily redeemable Series C preferred shares

Effective January 1, 2013, the Company issued 100 redeemable Series C preferred shares in exchange for 100 Class B limited partnership units issued by the St. Leon Wind Energy LP (“St. Leon LP”), a subsidiary of APCo and the legal owner of the St. Leon facility (note 11(b)). Thirty six of the Series C preferred shares are owned by related parties controlled by executives of the Company. The preferred shares are mandatorily redeemable in 2031 for $53,400 per share and have a contractual cumulative cash dividend paid quarterly until the date of redemption based on a prescribed payment schedule detailed below. These shares are accounted for as liabilities in the unaudited interim consolidated financial statements. The cumulative dividends are indexed in proportion to the increase in CPI over the term of the shares. The dividend is intended to approximate the distributions that otherwise would have accrued to holders of Class B limited partnership units.

Upon redemption in 2031, the shares will be redeemed for $53,400 per share. The Series C preferred shares are convertible into common shares at the option of the holder and the Company, at any time after May 20, 2031 and before June 19, 2031, at a conversion price of $53,400 per share.

The Series C preferred shares were initially measured at their estimated fair value of $18,497 based on the present value of the expected contractual cash flows including dividends and redemption amount, discounted at a rate of 5.0%. The recognition of the initial fair value of $18,497 resulted in an adjustment to equity of the shareholders of the Company as the Class B shares had a nominal carrying amount prior to the exchange. The Series C preferred shares are accounted for under the effective interest method, resulting in accretion of interest expense over the term of the shares. Dividend payments are recorded as a reduction of the Series C preferred share carrying value.


Estimated dividend and redemption payments due in the next five years and thereafter are:
2013	$	619
2014		1,109
2015		1,077
2016		946
2017		895
Thereafter to 2031		21,985
Redemption amount		5,340

		31,971
Less amounts representing interest		(13,218	)

		18,753
Less current portion		(896	)

	$	17,857

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

11.

Shareholders’ capital

(a)

Common shares

Number of common shares:


	June 30, 2013
Common shares, December 31, 2012		188,763,486
Conversion and redemption of convertible debentures (i)		150,816
Conversion of subscription receipts (ii)		15,223,016
Issuance of shares under the dividend reinvestment and employee share purchase plans		860,608

Common shares, June 30, 2013		204,997,926

(i)

Conversion and redemption of convertible debentures

On January 2, 2013, the remaining principal amount of $960 Series 3 Debentures was redeemed for 150,816 common shares of APUC.

(ii)

Subscription receipts

On December 10, 2012, in connection with the acquisition of Senate Wind Project and Minonk Wind Project, the Company received $45,000 from Emera Inc. (“Emera”) relating to the exercise of 7,842,016 subscription receipts at a price of $5.74 per subscription receipt pursuant to a subscription receipt agreement. The subscription receipts were converted to 7,842,016 common shares on February 14, 2013.

On December 21, 2012, in connection with the acquisition of Emera’s non-controlling interest in Calpeco Electric System, the Company received $38,756 from Emera relating to the exercise of 8,211,000 subscription receipts at a price of $4.72 per subscription receipt pursuant to a subscription receipt agreement. On December 27, 2012, Emera exercised 4,790,000 of these subscription receipts and the Company issued 4,790,000 common shares in exchange. On February 14, 2013, the balance of 3,421,000 subscription receipts were exercised by Emera and the Company issued 3,421,000 common shares.

On March 26, 2013, the Company issued 3,960,000 common shares at a price of $7.40 per share to Emera pursuant to a subscription receipt agreement. The $29,308 cash proceeds of the subscription receipts were used to fund a portion of the cost of the acquisition of the Columbus/Gainesville Gas System on April 1, 2013 (note 3 (c)).

Following the above noted subscription receipts transactions, as of June 30, 2013 all subscriptions receipts had been exercised for cash and converted to common shares.

(b)

Preferred shares

APUC is authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board of Directors of APUC. APUC has 4,800 Series A Preferred shares outstanding, at an average price of $25 per share.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

11.

Shareholders’ capital

(c)

Share-based compensation

On March 13, 2013, the Board approved the grant of 816,402 options to senior executives of the Company. The options allow for the purchase of common shares at a price of $7.72, the market price of the underlying common share at the date of grant.

One-third of the options vest on each of January 1, 2014, 2015 and 2016. Options may be exercised up to eight years following the date of grant.

During the six months ended June 30, 2013, 11,669 Deferred Share Units (“DSU”) were issued pursuant to the election of the Directors to defer a percentage of their 2013 Director’s fee in the form of DSUs.

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 unaudited interim 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, and are expected to be recognized over a period of 1.82 years and 1.35 years respectively.

12.

Accumulated other comprehensive loss

Changes in accumulated other comprehensive loss by component, net of tax:


	Foreign currency cumulative translation			Unrealized gain on cash flow hedges		Pension and post- retirement actuarial loss			Total
Balance, December 31, 2012	$	(105,959	)	$	3,593	$	(2,501	)	$	(104,867	)
Other comprehensive income (loss) before reclassifications		38,303			3,981		—			42,284
Amounts reclassified from accumulated other comprehensive loss		—			171		23			194

Net current period other comprehensive income		38,303			4,152		23			42,478

Balance, June 30, 2013	$	(67,656	)	$	7,745	$	(2,478	)	$	(62,389	)

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

13.

Cash dividends

On June 28, 2013, an initial dividend of $0.28125 per share totaling $1,350, Series A, was paid in cash to Preferred Share, Series A holders of record on June 14, 2013.

The dividends per common share declared per share for the three and six months ending June 30, 2013 was $0.085 and $0.1625 respectively (2012—$0.07 and $0.14).

14.

Income taxes

For the six months ended June 30, 2013, the Company’s overall effective tax rate was different than the statutory rate of 26.50% (2012—26.25%) due primarily to recognition of deferred credits, higher tax rates in U.S. subsidiaries, minority interest partner’s tax expenses, inter-corporate dividends, and non deductible expenses.

Included in deferred income tax recoveries for the three and six months ended June 30, 2013 is $1,198 and $3,514 (2012- $771 and $1,518) related to the recognition of deferred credits from the utilization of deferred income tax assets respectively.

15.

Sale of Facilities

On June 29, 2013, APCo sold 9 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. $23,400 for a gain on sale of U.S. $1,098, net of tax recovery of U.S. $1,661. The sale of the last small U.S. hydroelectric generating facilities is expected to close in the fourth quarter of 2013 for $3,600.

During the quarter, the Company initiated a strategic review of the Company’s business plan and opportunities available for its Energy From Waste (“EFW”) facility. As a result of the review, the Company decided during the quarter to sell the facility and expects the sales process to be concluded within the next 12 months. 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 net assets of EFW were written down to their estimated fair value less cost of sale which resulted in a write down of the net assets of $47,651 before tax, or $35,738 net of tax of $11,913. The determination of the fair value of the net assets of EFW has been based upon management’s preliminary estimates and assumptions considering present conditions and management’s planned course of action. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.

In August 2012, APCo sold a small U.S. Hydro facility for gross proceeds of $350 for a loss on sale, net of tax of $253.

The operating results from these facilities are disclosed as discontinued operations on the interim consolidated statements and prior periods have been reclassified to conform to this presentation.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

15.

Sale of Facilities (continued)

The summary of operating results and cash flows from discontinued operations for the three and six months ended June 30 is as follows:


	Three months ended
	2013			2012
Non-regulated energy sales	$	2,718		$	2,486
Waste disposal fees		2,037			4,179
Other and interest income		94			7
Operating and administrative expenses		(5,438	)		(3,990	)
Depreciation of property, plant and equipment		(928	)		(1,640	)
Interest expense		(43	)		(46	)
Gain on sale		1,155			—
Write-down of assets		(47,651	)		—

Income (loss) from discontinued operations, before income taxes		(48,056	)		996
Income tax recovery(expense)		14,166			(212	)

Income (loss) from discontinued operations, net of income taxes		(33,890	)		784
Add:
Depreciation of property, plant and equipment		928			1,640
Write-down of assets		47,651			—
Net proceeds from disposition		22,052			204
Contingent liability		(613	)		—
Income tax recovery (expense)		(14,166	)		212

Increase in cash and cash equivalents from discontinued operations	$	21,962		$	2,840


	Six months ended
	2013			2012
Non-regulated energy sales	$	6,056		$	5,357
Waste disposal fees		3,950			7,606
Other and interest income		253			13
Operating and administrative expenses		(10,696	)		(8,271	)
Depreciation of property, plant and equipment		(2,483	)		(3,259	)
Interest expense		(87	)		(107	)
Gain on sale		1,155			—
Write-down of assets		(47,651	)		—

Income (loss) from discontinued operations, before income taxes		(49,503	)		1,339
Income tax recovery(expense)		14,463			(261	)

Income (loss) from discontinued operations, net of income taxes		(35,040	)		1,078
Add:
Depreciation of property, plant and equipment		2,483			3,259
Write-down of assets		47,651			—
Net proceeds from disposition		22,052			204
Contingent liability		(613	)		—
Income tax recovery (expense)		(14,463	)		261

Increase in cash and cash equivalents from discontinued operations	$	22,070		$	4,802

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

15.

Sale of Facilities (continued)

Assets held-for-sale was as follows:


	June 30, 2013		December 31, 2012
Property, plant and equipment	$	29,945	$	100,377
Accounts receivable and prepaids		3,062		2,510

Total	$	33,007	$	102,887

Liabilities held-for-sale was as follows:


	June 30, 2013		December 31, 2012
Accounts payable and accrued liabilities	$	1,282	$	1,211

16.

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.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

16.

Related party transactions (continued)

Transactions with APMI and Senior Executives (continued)

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.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

17.

Basic and diluted net earnings per share

Basic and diluted earnings per share have been calculated on the basis of net earnings attributable to the common shareholders of the Company and the weighted average number of common shares outstanding during the year. Diluted net income per share is computed using the weighted-average number of common shares and, if dilutive, potential common shares outstanding during the period. Potential common shares consist of the incremental common shares issuable upon the exercise of stock options, performance share units (“PSUs”), deferred share units (“DSUs”), shareholders’ rights and convertible debentures. The dilutive effect of outstanding stock options, PSUs, DSUs and shareholders’ rights is reflected in diluted earnings per share by application of the Treasury Stock Method while the dilutive effect of convertible debentures is reflected in diluted earnings per share by application of the As If Converted Method.

The reconciliation of the net income and the weighted average shares used in the computation of basic and diluted earnings per share are as follows:


	Three months ended June 30,					Six months ended June 30,
	2013			2012		2013			2012
Net(loss)/earnings attributable to shareholders of APUC	$	(18,091	)	$	6,068	$	1,119		$	8,342
Series A preferred shares dividend		1,350			—		2,700			—

Net earnings attributable to common shareholders of APUC – Basic and Diluted	$	(19,441	)	$	6,068	$	(1,581	)	$	8,342

Weighted average number of shares
Basic		204,908,701			153,414,269		202,802,877			146,998,173
Dilutive effect of share-based awards		1,160,065			548,315		1,112,381			513,925

Diluted		206,068,766			153,962,584		203,915,258			147,512,098

For the three and six months ended June 30, 2013, the shares potentially issuable as a result of the convertible debentures as well as stock options of 816,402 and 816,407 (2012 – 1,696,486 and 1,704,785) are excluded from this calculation as they are anti-dilutive.

18.

Commitments and contingencies

Contingencies

APUC and its subsidiaries are involved in various claims and litigation arising out of the ordinary course and conduct of its business. Although such matters cannot be predicted with certainty, management does not consider APUC’s exposure to such litigation to be material to these unaudited interim consolidated financial statements, with the exception of those matters described below. Accruals for any contingencies related to these items are recorded in the unaudited interim consolidated financial statements at the time it is concluded that its occurrence is probable and the related liability is estimable.

On October 21, 2011 the Québec Court of Appeal ordered a subsidiary of APUC to pay approximately $5,400 (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.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

18.

Commitments and contingencies (continued)

Contingencies (continued)

The water lease with Seaway Management contains an indemnification clause which management believes mitigates this claim and management intends to vigorously defend its position. As a result, the probability of loss, if any, and its quantification cannot be estimated at this time but could range from $nil to $6,000.

ii)

The normal ongoing operations and historic activities of the Company are subject to various federal, state and local environmental laws and regulations and are regulated by agencies such as the United States Environmental Protection Agency and the New Hampshire Department of Environmental Services (“NHDES”). Like most other industrial companies, the gas and electric distribution utilities generate some hazardous wastes. Under federal and state Superfund laws, potential liability for historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred. In the case of regulated utilities these costs are often allowed in rate case proceedings to be recovered from rate payers over a specified period.

Prior to their acquisition by Liberty Utilities, EnergyNorth Gas System and Granite State Electric System were named as potentially responsible parties for remediation of several sites at which hazardous waste is alleged to have been disposed as a result of historic operations of Manufactured Gas Plants (“MGP”) and related facilities. The Company is currently investigating and remediating, as necessary, those MGP and related sites in accordance with plans submitted to the NHDES. The Company believes that obligations imposed on it because of those sites will not have a material impact on its results of operations or financial position.

As at June 30, 2013, the Company estimates the remaining undiscounted, unescalated cost of these MGP-related environmental cleanup activities will be $62,876 (U.S. $59,780). At a discount rate of 3.5%, it represents a recorded accrual of $58,759 (December 31, 2012 - $56,857), the current portion of which amounts to $3,227. Remediation costs estimates for each site may vary, depending upon changing technologies and regulatory standards, selected end use for each site, and actual environmental conditions encountered.

By rate orders, the regulator provided for the recovery of actual expenditures for site investigation and remediation over a period of 7 years and accordingly, at June 30, 2013 the Company has reflected a regulatory asset of $62,310 (December 31, 2012 - $59,789) for the MGP and related sites.

Estimated cash flows for site investigation and remediation costs in the next five years and thereafter are as follows:


2013	$	1,019
2014		8,478
2015		25,060
2016		16,623
2017		1,053
Thereafter to 2047		10,643

	$	62,876

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

18.

Commitments and contingencies (continued)

Commitments

In addition to the commitments relating to the proposed acquisitions disclosed in note 3 the following significant commitments exist as at June 30, 2013.

As a result of the dam safety legislation passed in Quebec (Bill C93), APUC has completed technical assessments on its hydroelectric facility dams owned or leased within the Province of Quebec. The assessments have identified a number of remedial measures required to meet the new safety standards. APUC currently estimates further capital expenditures of approximately $16,900 over a period of five years related to compliance with the legislation.

APUC has outstanding purchase commitments for power purchases, gas delivery, service and supply, service agreements, capital project commitments and operating leases. Detailed below are estimates of future commitments under these arrangements:


	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
Purchased power	$	58,115	$	44,106	$	20,443	$	—	$	—	$	—	$	122,664
Gas delivery, service and supply agreements		26,554		18,128		10,443		5,945		5,272		52,903		119,245
Service agreements		25,809		21,587		27,707		28,042		29,169		504,246		636,560
Capital projects		20,242		500		—		—		—		—		20,742
Operating leases		5,280		5,023		4,086		3,546		3,350		88,712		109,997

Total	$	136,000	$	89,344	$	62,679	$	37,533	$	37,791	$	645,861	$	1,009,208

Calpeco has entered into a five year all-purpose power purchase agreement (“PPA”) with NV Energy to provide its full electric requirements at NV Energy’s “system average cost” rates. The PPA has an effective starting date of January 1, 2011 with a five year renewal option. The commitment amounts included in the table above are based on market prices as of June 30, 2013. However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism. Granite State has several types of contracts for the purchase of electric power. Substantially all of these contracts require power to be delivered before the Company is obligated to make payment.

Subsequent to quarter end on August 6, 2013, Liberty Utilities (Canada) Corp entered into an agreement to purchase a property located in Oakville, Ontario to host the Company’s head office. The purchase, in an amount of $47,300 is expected to close on December 2, 2013. The company has already paid installments of $2,500.

19.

Non-cash operating items

The changes in non-cash operating items from discontinued operations is comprised of the following:


	Three months ended June 30,					Six months ended June 30,
	2013		2012			2013			2012
Accounts receivable	$	240	$	(1,657	)	$	(432	)	$	(2,502	)
Prepaid expenses		76		(217	)		(120	)		(227	)
Accrued liabilities		157		9			71			(210	)

	$	473	$	(1,865	)	$	(481	)	$	(2,939	)

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

19.

Non-cash operating items (continued)

The changes in non-cash operating items is comprised of the following:


	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
Accounts receivable	$	30,129		$	1,570		$	(5,114	)	$	7,168
Related party balances		17			20			30			(65	)
Natural gas inventory		(10,026	)		—			(449	)		—
Supplies and consumable inventory		(1,189	)		(451	)		(2,289	)		(639	)
Income tax receivable		(20	)		(4	)		(32	)		(29	)
Prepaid expenses		1,372			64			(1,742	)		1,671
Accounts payable		(4,272	)		(1,481	)		(10,337	)		427
Accrued liabilities		994			(1,098	)		(17,071	)		(9,368	)
Current income tax liability		662			(120	)		571			(137	)
Net regulatory assets and liabilities		5,665			1,685			8,770			2,493

	$	23,332		$	185		$	(27,663	)	$	1,521

20.

Segmented information

APUC has two operating segments: APCo which owns or has interests in renewable energy facilities and thermal energy facilities and Liberty Utilities which owns and operates utilities in the United States of America providing electric, natural gas, water distribution or wastewater services.

Within APCo there are three divisions: Renewable Energy, Thermal Energy and Development. The Renewable Energy division operates the Company’s hydro-electric and wind power facilities. The Thermal Energy division operates co-generation, energy from waste, steam production and other thermal facilities. The Development division develops the Company’s greenfield power generation projects as well as any expansion of the Company’s existing portfolio of renewable energy and thermal energy facilities.

Liberty Utilities’ operational segments are aggregated and reported by the following geographic territories: Liberty Utilities (West), Liberty Utilities (Central) and Liberty Utilities (East). Liberty Utilities (West) is comprised of Calpeco and the water distribution and wastewater utilities located in Arizona. Liberty Utilities (Central) is comprised of the Midwest Gas Utilities and the water distribution and wastewater utilities located in Texas, Missouri, Illinois and Arkansas. Liberty Utilities (East) is comprised of the New Hampshire and Georgia electric and gas utilities.

Operational segments

APUC’s reportable segments are APCo - Renewable Energy, APCo - Thermal Energy, Liberty Utilities (West), Liberty Utilities (Central) and Liberty Utilities (East). The development activities of APCo are reported under Renewable Energy or Thermal Energy as appropriate. For purposes of evaluating divisional performance, the Company allocates the realized portion of the loss on financial instruments to specific divisions. This allocation is determined when the initial foreign exchange forward contract is entered into. The unrealized portion of any gains or losses on derivatives instruments is not considered in management’s evaluation of divisional performance and is therefore allocated and reported in the corporate segment. The interest rate swaps relate to specific debt facilities and gains and losses are allocated in the same manner as interest expense. Amounts relating to the convertible debentures are reported in the corporate segment.

The results of operations and assets for these segments are as follows:

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

20.

Segmented information (continued)

Operational segments (continued)


	Three months ended June 30, 2013
	Algonquin Power												Liberty Utilities									Corporate		Total
	Renewable Energy			Thermal Energy			Total			Central			West			East			Total
Revenue
Regulated electricity sales and distribution	$	—		$	—		$	—		$	—		$	17,523		$	18,830		$	36,353		$	—	$	36,353
Regulated gas sales and distribution		—			—			—			14,033			—			34,549			48,582					48,582
Regulated water reclamation and distribution		—			—			—			4,693			10,115			—			14,808			—		14,808
Non-regulated energy sales		36,980			9,564			46,544			—			—			—			—			—		46,544
Other revenue		1,986			474			2,460			—			3			—			3			—		2,463

Total revenue		38,966			10,038			49,004			18,726			27,641			53,379			99,746			—		148,750
Operating expenses		10,597			2,687			13,284			6,137			9,140			16,295			31,572			—		44,856
Regulated electricity purchased		—			—			—			—			8,238			12,720			20,958			—		20,958
Regulated gas purchased		—			—			—			7,023			—			17,867			24,890			—		24,890
Non-regulated fuel for generation		—			3,998			3,998			—			—			—			—			—		3,998

		28,369			3,353			31,722			5,566			10,263			6,497			22,326			—		54,048
Depreciation of property, plant and equipment		(9,424	)		(2,750	)		(12,174	)		(2,072	)		(3,302	)		(4,966	)		(10,340	)		—		(22,514	)
Amortization of intangible assets		(663	)		(213	)		(876	)		(19	)		(166	)		—			(185	)		—		(1,061	)
Administration expenses		(3,461	)		(140	)		(3,601	)		(804	)		(2,289	)		(851	)		(3,944	)		197		(7,348	)
Foreign exchange gain		—			—			—			—			—			—			—			835		835
Interest expense		(6,607	)		(177	)		(6,784	)		(907	)		(4,833	)		(2,563	)		(8,303	)		2,198		(12,889	)
Interest, dividend and other income		553			(482	)		71			130			235			973			1,338			757		2,166
Acquisition related costs		(289	)		—			(289	)		(14	)		—			(218	)		(232	)		—		(521	)
Gain on derivative financial instruments		258			—			258			—									—			260		518

Earnings/(loss) from continuing operations before income taxes		8,736			(409	)		8,327			1,880			(92	)		(1,128	)		660			4,247		13,234
Gain/(loss) from discontinued operations before income taxes		1,427			(49,483	)		(48,056	)		—			—			—			—			—		(48,056	)

Earnings/(loss) before income taxes	$	10,163		$	(49,892	)	$	(39,729	)	$	1,880		$	(92	)	$	(1,128	)	$	660		$	4,247	$	(34,822	)

Capital expenditures		7,871			98			7,969			6,415			2,239			22,103			30,756			652		39,377
Acquisition of operating entities		2,311			—			2,311			584			—			156,591			157,175			—		159,486

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

20.

Segmented information (continued)

Operational segments (continued)


	Six months ended June 30, 2013
	Algonquin Power												Liberty Utilities									Corporate			Total
	Renewable Energy			Thermal Energy			Total			Central			West			East			Total
Revenue
Regulated electricity sales and distribution	$	—		$	—		$	—		$	—		$	38,579		$	40,629		$	79,208		$	—		$	79,208
Regulated gas sales and distribution		—			—			—			45,202			—			93,469			138,671						138,671
Regulated water reclamation and distribution		—			—			—			8,304			18,570			—			26,874			—			26,874
Non-regulated energy sales		76,710			16,764			93,474			—			—			—			—			—			93,474
Other revenue		2,703			1,124			3,827			—			17			—			17			—			3,844

Total revenue		79,413			17,888			97,301			53,506			57,166			134,098			244,770			—			342,071
Operating expenses		21,870			5,248			27,118			12,736			18,324			29,725			60,785			—			87,903
Regulated electricity purchased		—			—			—			—			19,809			27,152			46,961			—			46,961
Regulated gas purchased		—			—			—			27,865			—			56,075			83,940			—			83,940
Non-regulated fuel for generation		—			9,022			9,022			—			—			—			—			—			9,022

		57,543			3,618			61,161			12,905			19,033			21,146			53,084			—			114,245
Depreciation of property, plant and equipment		(20,446	)		(4,081	)		(24,527	)		(4,038	)		(6,285	)		(8,618	)		(18,941	)		—			(43,468	)
Amortization of intangible assets		(1,326	)		(422	)		(1,748	)		(40	)		(312	)		—			(352	)		—			(2,100	)
Administration expenses		(5,965	)		(391	)		(6,356	)		(548	)		(2,996	)		(1,320	)		(4,864	)		(985	)		(12,205	)
Foreign exchange gain		—			—			—			—			—			—			—			1,318			1,318
Interest expense		(13,092	)		(760	)		(13,852	)		(938	)		(6,981	)		(2,649	)		(10,568	)		(668	)		(25,088	)
Interest, dividend and other income		937			(238	)		699			168			874			1,345			2,387			1,299			4,385
Acquisition related costs		(366	)		—			(366	)		(61	)		—			(587	)		(648	)		—			(1,014	)
Gain on derivative financial instruments		695			—			695			—									—			1,209			1,904

Earnings/(loss) from continuing operations before income taxes		17,980			(2,274	)		15,706			7,448			3,333			9,317			20,098			2,173			37,977
Gain/(loss) from discontinued operations before income taxes		2,114			(51,617	)		(49,503	)		—			—			—			—			—			(49,503	)

Earnings/(loss) before income taxes	$	20,094		$	(53,891	)	$	(33,797	)	$	7,448		$	3,333		$	9,317		$	20,098		$	2,173		$	(11,526	)

Property, plant and equipment	$	1,311,362		$	87,102		$	1,398,464		$	204,757		$	370,061		$	543,669		$	1,118,487		$	—		$	2,516,951
Intangible assets		28,141			6,059			34,200			2,721			19,295			—			22,016			—			56,216
Assets held for sale		3,815			29,192			33,007			—			—			—			—			—			33,007
Total assets		1,431,599			112,059			1,543,658			263,911			492,183			705,268			1,461,362			196,768			3,201,788
Capital expenditures		11,957			278			12,235			13,510			3,669			25,665			42,843			707			55,785
Acquisition of operating entities		(1,698	)		—			(1,698	)		27,545			—			146,342			173,887			—			172,189

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

20.

Segmented information (continued)

Operational segments (continued)


	Three months ended June 30, 2012
	Algonquin Power												Liberty Utilities								Corporate			Total
	Renewable Energy			Thermal Energy			Total			Central			West			East		Total
Revenue
Regulated electricity sales and distribution	$	—		$	—		$	—		$	—		$	15,913		$	—	$	15,913		$	—		$	15,913
Regulated water reclamation and distribution		—			—			—			2,322			9,739			—		12,061			—			12,061
Non-regulated energy sales		22,288			7,548			29,836			—			—			—		—			—			29,836
Other revenue		458			366			824			—			85			—		85			—			909

Total revenue		22,746			7,914			30,660			2,322			25,737			—		28,059			—			58,719
Operating expenses		7,530			2,628			10,158			1,404			8,292			—		9,696			—			19,854
Regulated electricity purchased		—			—			—			—			9,661			—		9,661			—			9,661
Non-regulated fuel for generation		—			3,009			3,009			—			—			—		—			—			3,009

		15,216			2,277			17,493			918			7,784			—		8,702			—			26,195
Depreciation of property, plant and equipment		(4,070	)		(998	)		(5,068	)		(302	)		(3,013	)		—		(3,315	)		—			(8,383	)
Amortization of intangible assets		(663	)		(203	)		(866	)		(18	)		(154	)		—		(172	)		—			(1,038	)
Administration expenses		(1,832	)		(137	)		(1,969	)		183			(290	)		—		(107	)		(3,402	)		(5,478	)
Foreign exchange loss		—			—			—			—			—			—		—			863			863
Interest expense		(2,781	)		(357	)		(3,138	)		(17	)		(1,852	)		—		(1,869	)		(1,195	)		(6,202	)
Interest, dividend and other income		559			231			790			—			121			—		121			569			1,480
Acquisition related costs		(782	)		—			(782	)		—			(1,271	)		—		(1,271	)		—			(2,053	)
Loss on derivative financial instruments		(590	)		—			(590	)		—			—			—		—			(104	)		(694	)

Earnings from continuing operations before income taxes		5,057			813			5,870			764			1,325			—		2,089			(3,269	)		4,690
Loss from discontinued operations before income taxes		(391	)		1,387			996			—			—			—		—			—			996

Earnings/(loss) before income taxes	$	4,666		$	2,200		$	6,866		$	766		$	1,325		$	—	$	2,089		$	(3,269	)	$	5,686

Capital expenditures	$	6,711		$	8,021		$	14,732		$	1,099		$	3,238		$	—	$	4,337		$	15		$	19,084

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

20.

Segmented information (continued)

Operational segments (continued)


	Six months ended June 30, 2012
	Algonquin Power												Liberty Utilities								Corporate			Total
	Renewable Energy			Thermal Energy			Total			Central			West			East		Total
Revenue
Regulated electricity sales and distribution	$	—		$	—		$	—		$	—		$	35,299		$	—	$	35,299		$	—		$	35,299
Regulated water reclamation and distribution		—			—			—			4,507			18,147			—		22,654			—			22,654
Non-regulated energy sales		43,776			13,806			57,582			—			—			—		—			—			57,582
Other revenue		771			467			1,238			—			85			—		85			—			1,323

Total revenue		44,547			14,273			58,820			4,507			53,531			—		58,038			—			116,858
Operating expenses		14,493			4,368			18,861			2,559			17,723			—		20,282			—			39,143
Regulated electricity purchased		—			—			—			—			21,444			—		21,444			—			21,444
Non-regulated fuel for generation		—			7,041			7,041			—			—			—		—			—			7,041

		30,054			2,864			32,918			1,948			14,364			—		16,312			—			49,230
Depreciation of property, plant and equipment		(7,733	)		(2,373	)		(10,106	)		(611	)		(5,692	)		—		(6,303	)		—			(16,409	)
Amortization of intangible assets		(1,326	)		(405	)		(1,731	)		(38	)		(308	)		—		(346	)		—			(2,077	)
Administration expenses		(3,236	)		(621	)		(3,857	)		(282	)		(1,114	)		—		(1,396	)		(4,606	)		(9,859	)
Foreign exchange loss		—			—			—			—			—			—		—			409			409
Interest expense		(7,188	)		(960	)		(8,148	)		(33	)		(3,707	)		—		(3,740	)		(2,984	)		(14,872	)
Interest, dividend and other income		997			520			1,517			—			827			—		827			1,252			3,596
Acquisition related costs		(2,282	)		—			(2,282	)		—			(2,149	)		—		(2,149	)		—			(4,431	)
Loss on derivative financial instruments		(1,669	)		—			(1,669	)		—			—			—		—			1,038			(631	)

Earnings from continuing operations before income taxes		7,617			(975	)		6,642			984			2,221			—		3,205			(4,891	)		4,956
Loss from discontinued operations before income taxes		(711	)		2,050			1,339			—			—			—		—			—			1,339

Earnings/(loss) before income taxes	$	6,906		$	1,075		$	7,981		$	984		$	2,221		$	—	$	3,205		$	(4,891	)	$	6,295

Capital expenditures	$	9,570		$	14,230		$	23,800		$	2,301		$	4,589		$	—	$	6,890		$	38		$	30,728


	December 31, 2012
Property, plant and equipment	$	1,157,062		$	77,888		$	1,234,950		$	151,637		$	350,053		$	350,088	$	851,778		$	—		$	2,086,728
Intangible assets		29,480			6,132			35,612			2,613			18,556			—		21,169			—			56,781
Assets held for sale		24,390			78,497			102,887			—			—			—		—			—			102,887
Total assets		1,272,037			175,173			1,447,210			212,495			464,201			500,374		1,177,070			153,957			2,778,237

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

21.

Financial instruments

(a)

Fair value of financial instruments


	June 30, 2013
	Carrying amount		Fair Value		Level 1		Level 2		Level 3
Notes receivable	$	22,677	$	24,835	$	—	$	—	$	24,835
Derivative financial instruments:
Energy contracts designated as a cashflow hedge		25,593		25,593		—		25,593		—
Cross-currency swap designated as a foreign exchange hedge		187		187		—		187		—
Commodity contracts for regulatory operations		14		14		—		14		—

Total derivative financial instruments		25,794		25,794		—		25,794		—

Total financial assets	$	48,471	$	50,629	$	—	$	25,794	$	24,835

Long-term liabilities	$	1,091,452	$	1,110,469	$	295,143	$	815,326	$	—
Derivative financial instruments:
Energy contracts designated as a cashflow hedge		9,128		9,128		—		9,128		—
Cross-currency swap designated as a foreign exchange hedge		6,727		6,727		—		6,727		—
Interest rate swaps not designated as a hedge		3,735		3,735		—		3,735		—
Commodity contracts for regulated operations		1,147		1,147		—		1,147		—
Energy derivative contracts not designated as a hedge		129		129		—		129		—

Total derivative financial instruments		20,866		20,866		—		20,866		—

Total financial liabilities	$	1,112,318	$	1,131,335	$	295,143	$	836,192	$	—

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

21.

Financial instruments (continued)

(a)

Fair value of financial instruments (continued)


December 31, 2012
	Carrying amount		Fair Value		Level 1		Level 2		Level 3
Notes receivable	$	22,757	$	25,476	$	—	$	—	$	25,476
Derivative financial instruments:
Energy contracts designated as a cashflow hedge		12,695		12,695		—		12,695		—
Cross-currency swap designated as a foreign exchange hedge		408		408		—		408		—
Commodity contracts for regulatory operations		147		147		—		147		—

Total derivative financial instruments		13,250		13,250		—		13,250		—

Total financial assets	$	36,007	$	38,726	$	—	$	13,250	$	25,476

Long-term liabilities	$	770,826	$	785,473	$	293,348	$	492,125	$	—
Convertible debentures		960		1,319		1,319		—		—
Derivative financial instruments:
Energy contracts designated as a cashflow hedge		9,012		9,012		—		9,012		—
Cross-currency swap designated as a foreign exchange hedge		2,078		2,078		—		2,078		—
Interest rate swaps not designated as a hedge		4,778		4,778		—		4,778		—
Energy derivative contracts		287		287		—		287		—
Commodity contracts for regulated operations		1,661		1,661		—		1,661		—

Total derivative financial instruments		17,816		17,816		—		17,816		—

Total financial liabilities	$	789,602	$	804,608	$	294,667	$	509,941	$	—

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

21.

Financial instruments (continued)

(a)

Fair value of financial instruments (continued)

The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. The Company determines fair value based on assumptions that market participants would use in pricing an asset or liability in the principle or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels:

•

Level 1 Inputs: Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date.

•

Level 2 Inputs: Other than quoted prices included in Level 1 inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.

•

Level 3 Inputs: Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at measurement date.

The Company has determined that the carrying value of its short-term financial assets and liabilities approximates fair value (a level 2 measurement) at June 30, 2013 and December 31, 2012 due to the short-term maturity of these instruments.

The fair value of notes receivable have been determined using a discounted cash flow method, using estimated current market rates for similar instruments adjusted for estimated credit risk as determined by management. Such estimates are significantly influenced by unobservable data and therefore the fair value of notes receivable is subject to estimation risk.

APUC has long-term liabilities at both fixed interest rates and variable interest rates. The estimated fair value of such liabilities is calculated using current interest rates. The fair value of convertible debentures is determined using quoted market prices.

The Company’s Level 2 fair value derivative instruments primarily consist of swaps, options, and forward physical deals where market data for pricing inputs are observable. Level 2 pricing inputs are obtained from various market indices and utilize discounting based on quoted interest rate curves which are observable in the marketplace.

The Red Lily conversion option is measured at fair value on a recurring basis using unobservable inputs (Level 3). The fair value is determined by applying an income approach using an option pricing model that incorporates various inputs such as energy yield function from wind, estimated cash flows and a discount rate of 8.5%. The Company used a discount rate believed to be most relevant given the business strategy. There was no change in fair value of $nil during the three months ended June 30, 2013 or 2012.

Fair value estimates are made at a specific point in time, using available information about the financial instrument. These estimates are subjective in nature and often cannot be determined with precision.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

21.

Financial instruments (continued)

(a)

Fair value of financial instruments (continued)

The Company’s accounting policy is to recognize transfers between levels of the fair value hierarchy on the date of the event or change in circumstances that caused the transfer. There was no transfer into or out of level 1, level 2 or level 3 during the three or six months ended June 30, 2013 or 2012.

(b)

Derivative instruments

Derivative instruments are recognized on the balance sheet as either assets or liabilities and measured at fair value each reporting period.

(i)

Commodity derivatives – regulated accounting

The Company uses derivative financial instruments to reduce the cash flow variability associated with the purchase price for a portion of future natural gas transactions associated with its regulated gas service territories.

The following are commodity volumes, in MMBTU associated with the above derivative contracts:


	2013
Financial contracts: Gas swaps		2,963,000
Gas options		1,989,200

		4,952,200

The change in fair value of the Company’s derivative instruments is recorded as an offsetting adjustment to the regulatory assets and liabilities. As a result, the changes in fair value of these natural gas derivative contracts and their offsetting adjustment to regulatory assets and liabilities had no impact on net earnings.

(ii)

Cash flow hedges

APCo reduces the price risk on the expected future sales of power generation from Sandy Ridge, Senate and Minonk and at one of its hydro facilities no longer subject to a PPA by entering into the following long-term energy derivative contracts.

Notional quantity as

at June 30, 2013

(MW-hrs)

Expiry

Receive average
prices (per MW-hr)

Pay floating price
(per MW-hr)

174,830

December 2016

66.91

AESO

1,079,427

December 2022

U.S. $

42.81

PJM Western HUB

4,614,671

December 2022

U.S. $

30.25

NI HUB

4,801,636

December 2027

U.S. $

36.46

ERCORT North HUB

The Company expects $6,153 of unrealized gains currently in accumulated other comprehensive loss to be reclassified into net earnings within the next twelve months, as the underlying hedged transactions settle.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

21.

Financial instruments (continued)

(b)

Derivative instruments (continued)

(iii)

Foreign exchange hedge of net investment in foreign operation

The Company periodically uses a combination of foreign exchange forward contracts and spot purchases to manage its foreign exchange exposure on cash flows generated from the U.S. operations.

Concurrent with its $150,000 debentures offering in December 2012, APCo entered into a cross currency swap, coterminous with the debentures, to effectively convert the Canadian dollar denominated offering into United States dollar (“USD”). APCo designated the entire notional amount of the cross currency fixed for fixed interest rate swap and related short-term USD payables created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure of its net investment in APCo’s U.S. operations. The gain or loss related to the fair value changes of the swap and the related foreign currency gains and losses on the USD accruals that are designated as, and are effective as, an economic hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in other comprehensive income) related to the net investment. A foreign currency loss of $4,592 was recorded in other comprehensive income in the six months ended June 30, 2013.

(iv)

Other derivatives

APCo satisfies the energy demands of various customers under fixed rate contracts. While the production from the Tinker Assets are expected to provide a portion of the energy required to service these customers, APUC anticipates having to purchase a portion of its energy requirements at the ISO NE spot rates to supplement self-generated energy.

This risk is mitigated through the use of short-term financial forward energy purchase contracts which are classified as derivative instruments. The electricity derivative contracts are net settled fixed-for-floating swaps whereby APUC pays a fixed price and receives the floating or indexed price on a notional quantity of energy over the remainder of the contact term at an average rate, as per the following table. These contracts are not accounted for as hedges and changes in fair value are recorded in earnings as they occur.


Notional quantity as at June 30, 2013 (MW-hrs)	Expiry		Receive average prices (per MW-hr)		Net Asset
63,423		February 2014	U.S. $	53.01	$	(147	)
26,304		March 2015	U.S. $	47.88		(12	)
92,870		March 2015	U.S. $	47.88		30

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

21.

Financial instruments (continued)

(b)

Derivative instruments (continued)

(iv)

Other derivatives (continued)

For derivatives that are not designated as cash flow hedges and for the ineffective portion of gains and losses on derivatives that are accounted for as hedges, the changes in the fair value are immediately recognized in earnings. The effect on the unaudited interim consolidated statement of operations of derivative financial instruments not designated as hedges is as follows:


	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
Change in unrealized loss/(gain)on derivative financial instruments:
Interest rate swaps	$	(759	)	$	66		$	(1,043	)	$	(1,116	)
Energy derivative contracts		499			225			(166	)		286

Total change in unrealized loss/(gain) on derivative financial instruments	$	(260	)	$	291		$	(1,209	)	$	(830	)

Realized loss/(gain) on derivative financial instruments:
Foreign exchange contracts	$	—		$	(187	)	$	—		$	(207	)
Interest rate swaps		512			524			998			1,051
Energy derivative contracts		15			66			(723	)		617

Total realized loss on derivative financial instruments	$	527		$	403		$	275		$	1,461

Loss/(gain) on derivative financial instruments accounted for as hedges	$	267		$	694		$	(934	)	$	631
Ineffective portion of derivatives financial instruments accounted for as hedges		(785	)		—			(970	)		—

Loss/(gain) on derivative financial instruments	$	(518	)	$	694		$	(1,904	)	$	631

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Unaudited Interim Consolidated Financial Statements

Three and six months ended June 30, 2013 and 2012

(in thousands of Canadian dollars except as noted and amounts per share)

21.

Financial instruments (continued)

(c)

Risk management

Foreign currency risk

The Company is exposed to currency fluctuations from its U.S. based operations. APUC manages this risk primarily through natural hedges by using U.S. long term debt to finance its U.S. operations.

In August 2012, APCo designated the amounts drawn on its U.S. dollar denominated bank credit facility as a hedge of the foreign currency exposure from net investment in U.S. operations. The foreign currency transaction gain or loss on the outstanding U.S. dollar denominated balance of APCo’s facility that is designated as a hedge of the net investment in its foreign operations is reported in the same manner as a translation adjustment (in other comprehensive income) related to the net investment, to the extent it is effective as a hedge. A foreign currency loss of $1,809 was recorded in other comprehensive income in the six months ended June 30, 2013.

Interest rate risk

The Company is exposed to interest rate fluctuations related to certain of its floating rate debt obligations, including certain project specific debt and its revolving credit facility, its interest rate swaps as well as interest earned on its cash on hand. The Company does not currently hedge that risk.

APCo is party to an interest rate swap whereby, the Company pays a fixed interest rate of 4.47% on a notional amount of $63,236 and receives floating interest at 90 day CDOR, up to the expiry of the swap in September 2015. At June 30, 2013, the estimated fair value of the interest rate swap was a liability of $3,735 (2012 – liability of $5,859). This interest rate swap is not being accounted for as a hedge and consequently, changes in fair value are recorded in earnings as they occur.

22.

Non-controlling interests

Net earnings/(loss) attributable to non-controlling interests consists of the following:


	Three months ended June 30,					Six months ended June 30,
	2013			2012		2013			2012
Net earnings/(loss) attributable to non-controlling interest	$	4,039		$	—	$	7,107		$	—
Hypothetical liquidation at book value (income) / loss		(7,532	)		—		(12,564	)		—
Other		39			402		39			993

Total	($	3,454	)	$	402	($	5,418	)	$	993

23.

Comparative figures

Certain of the comparative figures have been reclassified to conform to the financial statement presentation adopted in the current period.