EX-99.2 3 a2016q4-exhibit992xfinanci.htm EXHIBIT 99.2 UNAUDITED FINANCIAL INFORMATION Exhibit
Unaudited Consolidated Financial Statements of
Algonquin Power & Utilities Corp.
For the years ended December 31, 2016 and 2015



Algonquin Power & Utilities Corp.
Unaudited Consolidated Balance Sheets

(thousands of Canadian dollars)
 
 
 
 
December 31,
2016
 
December 31,
2015
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
110,417

 
$
124,817

Accounts receivable, net (note 4)
189,658

 
186,681

Natural gas in storage (note 1(h))
21,625

 
28,502

Regulatory assets (note 7)
48,440

 
32,213

Prepaid expenses
26,562

 
18,409

Derivative instruments (note 25)
76,631

 
15,039

Other assets (note 12)
18,519

 
18,073

 
491,852

 
423,734

Property, plant and equipment, net (note 5)
4,889,946

 
3,877,170

Intangible assets, net (note 6)
64,989

 
74,477

Goodwill (note 6)
306,641

 
110,493

Regulatory assets (note 7)
243,524

 
213,102

Derivative instruments (note 25)
74,553

 
73,322

Long-term investments (note 8)
105,433

 
174,802

Deferred income taxes (note 20)
30,005

 
18,109

Restricted cash (note 1(f))
2,026,183

 
18,999

Other assets (note 12)
16,334

 
7,517

 
$
8,249,460

 
$
4,991,725




Algonquin Power & Utilities Corp.
Unaudited Consolidated Balance Sheets

(thousands of Canadian dollars)
 
 
 
 
December 31,
2016
 
December 31,
2015
LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
90,592

 
$
50,428

Accrued liabilities
308,318

 
193,320

Dividends payable (note 17)
38,973

 
41,802

Regulatory liabilities (note 7)
47,769

 
44,167

Long-term debt (note 9)
10,075

 
8,945

Other long-term liabilities and deferred credits (note 13)
43,157

 
36,621

Other liabilities
7,665

 
16,593

 
546,549

 
391,876

Long-term debt (note 9)
3,903,340

 
1,477,850

Convertible debentures (note 14)
358,619

 
—

Regulatory liabilities (note 7)
134,965

 
131,180

Deferred income taxes (note 20)
288,139

 
175,799

Derivative instruments (note 25)
104,647

 
106,628

Pension and other post-employment benefits obligation (note 10)
147,845

 
150,094

Other long-term liabilities (note 13)
232,449

 
223,135

Preferred shares, Series C (note 11)
17,552

 
17,548

 
5,187,556

 
2,282,234

Redeemable non-controlling interest (note 19)
29,434

 
25,751

Equity:
 
 
 
Preferred shares (note 15(b))
213,805

 
213,805

Common shares (note 15(a))
1,972,203

 
1,808,894

Subscription receipts (note 15(a)(ii))
—

 
110,503

Additional paid-in capital
38,652

 
38,241

Deficit
(556,024
)
 
(523,116
)
Accumulated other comprehensive income (note 16)
254,927

 
286,737

Total equity attributable to shareholders of Algonquin Power & Utilities Corp.
1,923,563

 
1,935,064

Non-controlling interests (note 19)
562,358

 
356,800

Total equity
2,485,921

 
2,291,864

Commitments and contingencies (note 23)

 

Subsequent events (notes 3, 8, 9, 14, 15 and 21)

 

 
$
8,249,460

 
$
4,991,725

See accompanying notes to consolidated financial statements




Algonquin Power & Utilities Corp.
Unaudited Consolidated Statements of Operations
 
(thousands of Canadian dollars, except per share amounts)
Year ended December 31
 
2016
 
2015
Revenue
 
 
 
Regulated electricity distribution
$
228,097

 
$
224,110

Regulated gas distribution
405,735

 
463,651

Regulated water reclamation and distribution
181,655

 
78,467

Non-regulated energy sales
243,149

 
222,581

Other revenue
37,382

 
39,046

 
1,096,018

 
1,027,855

Expenses
 
 
 
Operating expenses
333,001

 
279,406

Regulated electricity purchased
119,825

 
131,647

Regulated gas purchased
142,003

 
217,236

Regulated water purchased
12,227

 
—

Non-regulated energy purchased
21,260

 
27,990

Administrative expenses
46,349

 
39,830

Depreciation and amortization
186,899

 
149,806

Gain on foreign exchange
(436
)
 
(2,631
)
 
861,128

 
843,284

Operating income from continuing operations
234,890

 
184,571

Interest expense on convertible debentures and acquisition financing (notes 9(b) and 14)
57,630

 
—

Interest expense on long-term debt and others
73,962

 
65,993

Interest, dividend, equity and other income
(10,573
)
 
(9,095
)
Other gains
(8,555
)
 
(5,110
)
Acquisition-related costs
12,028

 
1,832

Loss (gain) on long-lived assets, net (note 8(e) and 18)
(3,263
)
 
2,890

Gain on derivative financial instruments (note 25(b)(iv))
(15,849
)
 
(2,188
)
 
105,380

 
54,322

Earnings from continuing operations before income taxes
129,510

 
130,249

Income tax expense (note 20)
 
 
 
Current
8,461

 
7,310

Deferred
28,675

 
36,403

 
37,136

 
43,713

Earnings from continuing operations
92,374

 
86,536

Loss from discontinued operations, net of tax
—

 
(1,032
)
Net earnings
92,374

 
85,504

Net effect of non-controlling interests (note 19)
(38,550
)
 
(31,976
)
Net earnings attributable to shareholders of Algonquin Power & Utilities Corp.
$
130,924

 
$
117,480

Series A and D Preferred shares dividend (note 17)
10,400

 
10,400

Net earnings attributable to common shareholders of Algonquin Power & Utilities Corp.
$
120,524

 
$
107,080

Basic net earnings per share from continuing operations (note 21)
$
0.44

 
$
0.43

Basic net earnings per share (note 21)
0.44

 
0.42

Diluted net earnings per share from continuing operations (note 21)
0.44

 
0.42

Diluted net earnings per share (note 21)
$
0.44

 
$
0.42

See accompanying notes to consolidated financial statements



Algonquin Power & Utilities Corp.
Unaudited Consolidated Statements of Comprehensive Income
 
(thousands of Canadian dollars)
Year ended December 31
 
2016
 
2015
Net earnings
$
92,374

 
$
85,504

Other comprehensive income:
 
 
 
Foreign currency translation adjustment, net of tax recovery of $nil and $nil, respectively (notes 1(v), 25(b)(iii) and 25(b)(iv))
(67,855
)
 
289,035

Change in fair value of cash flow hedges, net of tax expense of $18,109 and $12,010, respectively (note 25(b)(ii))
26,754

 
16,165

Change in unrealized appreciation in value of available-for-sale investments
213

 
(73
)
Change in pension and other post-employment benefits, net of tax expense of $1,433 and $4,923, respectively (note 10)
2,252

 
7,571

Other comprehensive (loss) income, net of tax
(38,636
)
 
312,698

Comprehensive income
53,738

 
398,202

Comprehensive (loss) income attributable to the non-controlling interests
(45,376
)
 
28,198

Comprehensive income attributable to shareholders of Algonquin Power & Utilities Corp.
$
99,114

 
$
370,004

See accompanying notes to consolidated financial statements



Algonquin Power & Utilities Corp.
Unaudited Consolidated Statement of Equity

 
(thousands of Canadian dollars)
For the year ended December 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Algonquin Power & Utilities Corp. Shareholders
 
 
 
 
 
Common
shares
 
Preferred
shares
 
Subscription
receipts
 
Additional
paid-in
capital
 
Accumulated
deficit
 
Accumulated
OCI
 
Non-
controlling
interests
 
Total
Balance, December 31, 2015
$
1,808,894

 
$
213,805

 
$
110,503

 
$
38,241

 
$
(523,116
)
 
$
286,737

 
$
356,800

 
$
2,291,864

Net earnings (loss)
—

 
—

 
—

 
—

 
130,924

 
—

 
(38,550
)
 
92,374

Redeemable non-controlling interests not included in equity (note 19)
—

 
—

 
—

 
—

 
—

 
—

 
4,952

 
4,952

Other comprehensive loss
—

 
—

 
—

 
—

 
—

 
(31,810
)
 
(6,826
)
 
(38,636
)
Dividends declared and distributions to non-controlling interests
—

 
—

 
—

 
—

 
(125,696
)
 
—

 
(3,926
)
 
(129,622
)
Dividends and issuance of shares under dividend reinvestment plan (note 15(a)(iii))
33,862

 
—

 
—

 
—

 
(33,862
)
 
—

 
—

 
—

Common shares issued upon conversion of subscription receipts (note 15 (a)(ii))
110,503

 
—

 
(110,503
)
 
—

 
—

 
—

 
—

 
—

Common shares issued pursuant to share-based awards (note 15(c))
18,944

 
—

 
—

 
(5,505
)
 
(4,274
)
 
—

 
—

 
9,165

Share-based compensation
—

 
—

 
—

 
5,916

 
—

 
—

 
—

 
5,916

Contributions received from non-controlling interests
—

 
—

 
—

 
—

 
—

 
—

 
12,752

 
12,752

Non-controlling interest of acquired operating entity (note 8(c))
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
237,156

 
$
237,156

Balance, December 31, 2016
$
1,972,203

 
$
213,805

 
$
—

 
$
38,652

 
$
(556,024
)
 
$
254,927

 
$
562,358

 
$
2,485,921





Algonquin Power & Utilities Corp.
Unaudited Consolidated Statement of Equity

 
(thousands of Canadian dollars)
For the year ended December 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Algonquin Power & Utilities Corp. Shareholders
 
 
 
 
 
Common
shares
 
Preferred
shares
 
Subscription
receipts
 
Additional
paid-in
capital
 
Accumulated
deficit
 
Accumulated
OCI
 
Non-
controlling
interests
 
Total
Balance, December 31, 2014
$
1,633,262

 
$
213,805

 
$
110,503

 
$
33,068

 
$
(505,305
)
 
$
34,213

 
$
316,842

 
$
1,836,388

Net earnings (loss)
—

 
—

 
—

 
—

 
117,480

 
—

 
(31,976
)
 
85,504

Redeemable non-controlling interests not included in equity (note 19)
—

 
—

 
—

 
—

 
—

 
—

 
3,571

 
3,571

Other comprehensive income
—

 
—

 
—

 
—

 
—

 
252,524

 
60,174

 
312,698

Dividends declared and distributions to non-controlling interests
—

 
—

 
—

 
—

 
(105,929
)
 
—

 
(2,626
)
 
(108,555
)
Dividends and issuance of shares under dividend reinvestment plan
29,302

 
—

 
—

 
—

 
(29,302
)
 
—

 
—

 
—

Common shares issued pursuant to public offering, net of costs (note 15(a)(i))
144,987

 
—

 
—

 
—

 
—

 
—

 
—

 
144,987

Common shares issued pursuant to share-based awards (note 15(c))
1,343

 
—

 
—

 
(282
)
 
(60
)
 
—

 
—

 
1,001

Share-based compensation
—

 
—

 
—

 
5,455

 
—

 
—

 
—

 
5,455

Contributions received from non-controlling interests
—

 
—

 
—

 
—

 
—

 
—

 
10,815

 
10,815

Balance, December 31, 2015
$
1,808,894

 
$
213,805

 
$
110,503

 
$
38,241

 
$
(523,116
)
 
$
286,737

 
$
356,800

 
$
2,291,864

See accompanying notes to consolidated financial statements




Algonquin Power & Utilities Corp.
Unaudited Consolidated Statements of Cash Flows
(thousands of Canadian dollars)
Year ended December 31
 
2016
 
2015
Cash provided by (used in):
 
 
 
Operating Activities
 
 
 
Net earnings from continuing operations
$
92,374

 
$
86,536

Adjustments and items not affecting cash:

 

Depreciation and amortization
195,751

 
151,627

Deferred taxes
28,675

 
36,403

Unrealized gain on derivative financial instruments
(18,689
)
 
(1,990
)
Share-based compensation expense
5,916

 
5,455

Cost of equity funds used for construction purposes
(2,774
)
 
(2,424
)
Pension and post-employment expense
(13,491
)
 
(3,333
)
Non-cash revenue and other income
(10,467
)
 
550

Write-down of long-lived assets
6,259

 
1,781

Unrealized gain on disposal of VIE
—

 
220

Changes in non-cash operating items (note 24)
3,704

 
(11,149
)
Cash used in discontinued operations
—

 
(1,806
)
 
287,258

 
261,870

Financing Activities
 
 
 
Cash dividends on common shares
(118,145
)
 
(79,121
)
Cash dividends on preferred shares
(10,400
)
 
(10,400
)
Cash contributions from non-controlling interests
13,468

 
15,222

Production-based cash contributions from non-controlling interest
9,454

 
10,815

Cash distributions to non-controlling interests
(4,307
)
 
(2,936
)
Issuance of common shares, net of costs
1,526

 
144,694

Issuance of convertible debentures, net of costs
357,694

 
—

Proceeds from exercise of share options
18,461

 
—

Shares surrendered to fund withholding taxes on exercised share options
(5,218
)
 
—

Increase in long-term debt
2,399,009

 
248,811

Decrease in long-term debt
(68,423
)
 
(196,149
)
Increase in other long-term liabilities
6,486

 
31,544

Decrease in other long-term liabilities
(4,269
)
 
(6,182
)
 
2,595,336

 
156,298

Investing Activities
 
 
 
Decrease (increase) in restricted cash
(2,007,732
)
 
2,900

Increase in other assets
(20,501
)
 
(2,155
)
Distributions received in excess of equity income
653

 
1,386

Receipt of principal on notes receivable
319,160

 
29,273

Additions to property, plant and equipment
(405,743
)
 
(204,195
)
Increase in long-term investments
(347,901
)
 
(138,560
)
Acquisitions of operating entities
(432,699
)
 
(3,717
)
Proceeds from sale of long-lived assets
—

 
5,516

 
(2,894,763
)
 
(309,552
)
Effect of exchange rate differences on cash
(2,231
)
 
6,928

Increase (decrease) in cash and cash equivalents
(14,400
)
 
115,544

Cash and cash equivalents, beginning of year
124,817

 
9,273

Cash and cash equivalents, end of year
$
110,417

 
$
124,817

 
 
 
 
Supplemental disclosure of cash flow information:
2016
 
2015
Cash paid during the year for interest expense
$
131,783

 
$
69,610

Cash paid during the year for income taxes
$
13,369

 
$
6,153

Non-cash financing and investing activities:
 
 
 
Property, plant and equipment acquisitions in accruals
$
146,301

 
$
44,834

Issuance of common shares under dividend reinvestment plan and share-based compensation plans
$
35,409

 
$
30,645

Issuance of common shares upon conversion of subscription receipts
$
110,503

 
$
—

Acquisition of equity investments in exchange for loan receivable
$
26,035

 
$
—


See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

Algonquin Power & Utilities Corp. (“APUC” or the “Company”) is an incorporated entity under the Canada Business Corporations Act. APUC's operations are organized across two primary North American business units consisting of the Renewable Generation Group and the Liberty Utilities Group. The Renewable Generation Group ("Renewable Generation Group") owns and operates a diversified portfolio of non-regulated renewable and thermal electric generation utility assets; the Liberty Utilities Group ("Liberty Utilities Group") owns and operates a portfolio of regulated electric, natural gas, water distribution and wastewater collection utility systems and transmission operations.
1.
Significant accounting policies
(a)
Basis of preparation
The accompanying consolidated financial statements and notes have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and follow disclosure required under Regulation S-X provided by the U.S. Securities and Exchange Commission.  
(b)
Basis of consolidation
The accompanying consolidated financial statements of APUC include the accounts of APUC, its wholly owned subsidiaries and variable interest entities (“VIEs”) where the Company is the primary beneficiary (note 1(l)). Intercompany transactions and balances have been eliminated. Interests in subsidiaries owned by third parties are included in non-controlling interests (note 1(q)).
(c)
Business combinations, intangible assets and goodwill
The Company accounts for acquisitions of entities or assets which meet the definition of a business as business combinations. The determination of whether the definition of a business has been met for a development stage project depends on the stage of development (permitting, customer contracting, financing, construction) and the significance of the development risk with respect to achieving commercial operation. Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed are measured at their fair value at the acquisition date. Acquisition costs are expensed in the period incurred. When the set of activities does not represent a business, the transaction is accounted for as an asset acquisition and includes acquisitions costs.
Intangible assets acquired are recognized separately at fair value if they arise from contractual or other legal rights or are separable. Power sales contracts are amortized on a straight-line basis over the remaining term of the contract ranging from 6 to 25 years from the date of acquisition. Interconnection agreements are amortized on a straight-line basis over their estimated life of 40 years. Customer relationships are amortized on a straight-line basis over their estimated life of 40 years.
Goodwill represents the excess of the purchase price of an acquired business over the fair value of the net assets acquired. Goodwill is not included in the rate-base on which regulated utilities are allowed to earn a return and is not amortized.
As at September 30 of each year, the Company assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit to which goodwill is attributed is less than its carrying amount. If it is more likely than not that a reporting unit’s fair value is less than its carrying amount or if a quantitative assessment is elected, the Company calculates the fair value of the reporting unit. The carrying amount of the reporting unit’s goodwill is considered not recoverable if the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value. An impairment charge is recorded for any excess of the carrying value of the goodwill over the implied fair value. Goodwill is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount.
(d)
Accounting for rate regulated operations
The regulated utility operating companies owned by the Company are subject to rate regulation generally overseen by the public utility commission of the states in which they operate (the “Regulator”). The Regulator provides the final determination of the rates charged to customers. APUC’s regulated utility operating companies are accounted for under the principles of U.S. Financial Accounting Standards Board (“FASB”)ASC Topic 980, Regulated Operations (“ASC 980”). Under ASC 980, regulatory assets and liabilities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process. Included in note 7 “Regulatory matters” are details of regulatory assets and liabilities, and their current regulatory treatment.

Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

1.
Significant accounting policies (continued)
(d)
Accounting for rate regulated operations (continued)
In the event the Company determines that its net regulatory assets are not probable of recovery, it would no longer apply the principles of the current accounting guidance for rate regulated enterprises and would be required to record an after-tax, non-cash charge or credit against earnings for any remaining regulatory assets or liabilities. The impact could be material to the Company’s reported financial condition and results of operations.
The electric, gas and water utilities’ accounts are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (“FERC”) and National Association of Regulatory Utility Commissioners. 
(e)
Cash and cash equivalents
Cash and cash equivalents include all highly liquid instruments with an original maturity of three months or less.
(f)
Restricted cash
Restricted cash represents reserves and amounts set aside pursuant to requirements of various debt agreements and requirements of ISO New England, Inc. As of December 31, 2016, restricted cash also includes cash of U.S. $1,495,774 transfered to a paying agent for purposes of distribution to holders of common shares of Empire on January 1, 2017 (note 3(a)). Cash reserves segregated from APUC’s cash balances are maintained in accounts administered by a separate agent and disclosed separately as restricted cash in these consolidated financial statements. APUC cannot access restricted cash without the prior authorization of parties not related to APUC.
(g)
Accounts receivable
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses adjusted to take into account current market conditions and customers’ financial condition, the amount of receivables in dispute, and the receivables aging and current payment patterns. Account balances are charged against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. The Company does not have any off-balance sheet credit exposure related to its customers.
(h)
Natural gas in storage
Natural gas in storage is reflected at weighted average cost or first-in-first-out as required by regulators and represents natural gas and liquefied natural gas that will be utilized in the ordinary course of business of the gas utilities and some generating facilities. Existing rate orders (note 7(c)) and other contracts allow the Company to pass through the cost of gas purchased directly to the customers along with any applicable authorized delivery surcharge adjustments. Accordingly, the recoverable value of gas in storage does not fall below the cost to the Company.
(i)
Supplies and consumables inventory
Supplies and consumables inventory (other than capital spares and rotatable spares, which are included in property, plant and equipment) are charged to inventory when purchased and then capitalized to plant or expensed, as appropriate, when installed, used or become obsolete. These items are stated at the lower of cost and replacement cost. Supplies and consumables inventory is included in other current assets.
(j)
Property, plant and equipment
Property, plant and equipment are recorded at cost. Capitalization of development projects begins when management, together with the relevant authority, authorized and has committed to the funding of a project and it is probable that costs will be realized through the use of the asset or ultimate construction and operation of a facility. Project development costs for rate-regulated entities, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are capitalized either as property, plant and equipment or regulatory asset when it is determined that recovery of such costs through regulated revenue of the completed project is probable.

Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

1.
Significant accounting policies (continued)
(j)
Property, plant and equipment (continued)
The costs of acquiring or constructing property, plant and equipment include the following: materials, labour, contractor and professional services, construction overhead directly attributable to the capital project (where applicable), interest for non-regulated property and allowance for funds used during construction (“AFUDC”) for regulated property. Where possible, individual components are recorded and depreciated separately in the books and records of the Company. Plant and equipment under capital leases are initially recorded at cost determined as the present value of minimum lease payments.
AFUDC represents the cost of borrowed funds and a return on other funds. Under ASC 980, an allowance for funds used during construction projects that are included in rate base is capitalized. This allowance is designed to enable a utility to capitalize financing costs during periods of construction of property subject to rate regulation. For operations that do not apply regulatory accounting, interest related only to debt is capitalized as a cost of construction in accordance with ASC 835, Interest. The interest capitalized that relates to debt reduces interest expense on the consolidated statements of operations. The AFUDC capitalized that relates to equity funds is recorded as interest, dividend, equity and other income on the consolidated statements of operations. 
 
2016
 
2015
Interest capitalized on non-regulated property
$
3,259

 
$
1,189

AFUDC capitalized on regulated property:
 
 
 
Allowance for borrowed funds
1,167

 
1,657

Allowance for equity funds
2,774

 
2,425

Total
$
7,200

 
$
5,271

Improvements that increase or prolong the service life or capacity of an asset are capitalized. Cost incurred for major expenditures or overhauls that occur at regular intervals over the life of an asset are capitalized and depreciated over the related interval. Maintenance and repair costs are expensed as incurred.
Investment tax credits and government grants related to capital expenditures are recorded as a reduction to the cost of assets and are amortized at the rate of the related asset as a reduction to depreciation expense. Contributions in aid of construction represent amounts contributed by customers, governments and developers to assist with the funding of some or all of the cost of utility capital assets. It also includes amounts initially recorded as advances in aid of construction (note 13(a)) but where the advance repayment period has expired. These contributions are recorded as a reduction in the cost of utility assets and are amortized at the rate of the related asset as a reduction to depreciation expense. Investment tax credits and government grants related to operating expenses such as maintenance and repairs costs are recorded as a reduction of the related expense.
The Company’s depreciation is based on the estimated useful lives of the depreciable assets in each category and is determined using the straight-line method with the exception of certain wind assets, as described below. The ranges of estimated useful lives and the weighted average useful lives are summarized below:
 
Range of useful lives
 
Weighted average
useful lives
 
2016
 
2015
 
2016
 
2015
Generation
3 - 60
 
3 - 60
 
32
 
32
Distribution
5 - 100
 
5 - 100
 
41
 
42
Equipment
5 - 50
 
5 - 50
 
11
 
14
The Company uses the unit-of-production method for certain components of its wind generating facilities where the useful life of the component is directly related to the amount of production. The benefits of components subject to wear and tear from the power generation process are best reflected through the unit-of-production method. The Company generally uses wind studies prepared by third parties to estimate the total expected production of each component.


Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

1.
Significant accounting policies (continued)
(j)
Property, plant and equipment (continued)
In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of the Liberty Utilities Group are replaced or retired, the original cost plus any removal costs incurred (net of salvage) are charged to accumulated depreciation with no gain or loss reflected in results of operations. Gains and losses will be charged to results of operations in the future through adjustments to depreciation expense. In the absence of regulator-approved accounting policies, gains and losses on the disposition of property, plant and equipment are charged to earnings as incurred. 
(k)
Impairment of long-lived assets
APUC reviews property, plant and equipment and intangible assets for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable.
Assets held and used: Recoverability of assets expected to be held and used is measured by comparing the carrying amount of an asset to undiscounted expected future cash flows. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value.
Assets held for sale: Recoverability of assets held for sale is measured by comparing the carrying amount of an asset to its fair value less cost to sell. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value less estimated costs to sell.
(l)
Variable interest entities
The Company performs analysis to assess whether its operations and investments represent VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements and jointly-owned facilities. VIEs of which the Company is deemed the primary beneficiary are consolidated. In circumstances where APUC is not deemed the primary beneficiary, the VIE is not consolidated (note 8).
The Company has equity and notes receivable interests in two power generating facilities. APUC has determined that both entities are considered a VIE mainly based on total equity at risk not being sufficient to permit the legal entity to finance its activities without additional subordinated financial support. The key decisions that affect the generating facilities’ economic performance relate to siting, permitting, technology, construction, operations and maintenance and financing. As APUC has both the power to direct the activities of the entities that most significantly impact its economic performance and the right to receive benefits or the obligation to absorb losses of the entities that could potentially be significant to the entity, the Company is considered the primary beneficiary.
Total net book value of generating assets and long-term debt of these facilities amounts to $87,189 (2015 - $104,243) and $40,398 (2015 - $62,138), respectively. The debt only has recourse over the generating assets. The financial performance of these facilities reflected on the consolidated statements of operations includes non-regulated energy sales of $29,132 (2015 - $18,651), operating expenses and amortization of $6,175 (2015 - $5,645) and interest expense of $4,064 (2015 - $4,407).
(m)
Long-term investments and notes receivable
Investments in which APUC has significant influence but not control are accounted using the equity method. Equity-method investments are initially measured at cost including transaction costs and interest when applicable. APUC records its share in the income or loss of its investees in interest, dividend, equity and other income in the consolidated statements of operations.
Notes receivable are financial assets with fixed or determined payments that are not quoted in an active market. Notes receivable are initially recorded at cost, which is generally face value. Subsequent to acquisition, the notes receivable are recorded at amortized cost using the effective interest method. The Company acquired these notes receivable as long-term investments and does not intend to sell these instruments prior to maturity. Interest from long-term investments is recorded as earned and collectability of both the interest and principal are reasonably assured.
If a loss in value of a long-term investment is considered other than temporary, an allowance for impairment on the investment is recorded for the amount of that loss. An allowance for impairment loss on notes receivable is recorded if it is expected that the Company will not collect all principal and interest contractually due. The impairment is measured based on the present value of expected future cash flows discounted at the note’s effective interest rate.

Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

1.
Significant accounting policies (continued)
(n)
Pension and other post-employment plans
The Company has established defined contribution pension plans, defined benefit pension plans, and other post-employment benefit (“OPEB”) plans for its various employee groups in Canada and the United States. Employer contributions to the defined contribution pension plans are expensed as employees render service. The Company recognizes the funded status of its defined benefit pension plans and OPEB plans on the consolidated balance sheets. The Company’s expense and liabilities are determined by actuarial valuations, using assumptions that are evaluated annually as of December 31, including discount rates, mortality, assumed rates of return, compensation increases, turnover rates and healthcare cost trend rates. The impact of modifications to those assumptions and modifications to prior services are recorded as actuarial gains and losses in accumulated other comprehensive income (“AOCI”) and amortized to net periodic cost over future periods using the corridor method. The costs of the Company’s pension for employees are expensed over the periods during which employees render service and are recognized as part of administrative expenses in the consolidated statements of operations.
(o)
Asset retirement obligations
The Company recognizes a liability for asset retirement obligations based on the fair value of the liability when incurred, which is generally upon acquisition, during construction or through the normal operation of the asset. Concurrently, the Company also capitalizes an asset retirement cost, equal to the estimated fair value of the asset retirement obligation, by increasing the carrying value of the related long-lived asset. The asset retirement costs are depreciated over the asset’s estimated useful life and are included in depreciation and amortization expense on the consolidated statements of operations, or regulatory assets when the amount is recoverable through rates. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the consolidated statements of operations, or regulatory assets when the amount is recoverable through rates. Actual expenditures incurred are charged against the obligation.
(p)
Share-based compensation
The Company has several share-based compensation plans: a share option plan; an employee share purchase plan (“ESPP”); a deferred share unit (“DSU”) plan; and a performance share unit (“PSU”) plan. Equity classified awards are measured at the grant date fair value of the award. The Company estimates grant date fair value of options using the Black-Scholes option pricing model. The fair value is recognized over the vesting period of the award granted, adjusted for estimated forfeitures. The compensation cost is recorded as administrative expense in the consolidated statements of operations and contributed surplus in equity. Contributed surplus is reduced as the awards are exercised, and the amount initially recorded in contributed surplus is credited to common shares.
(q)
Non-controlling interests
Non-controlling interests represent the portion of equity ownership in subsidiaries that is not attributable to the equity holders of APUC. Non-controlling interests are initially recorded at fair value and subsequently adjusted for the proportionate share of earnings and other comprehensive income (“OCI”) attributable to the non-controlling interests and any dividends or distributions paid to the non-controlling interests.
If a transaction results in the acquisition of all, or part, of a non-controlling interest in a consolidated subsidiary, the acquisition of the non-controlling interest is accounted for as an equity transaction. No gain or loss is recognized in net earnings or comprehensive income as a result of changes in the non-controlling interest, unless a change results in the loss of control by the Company.
Certain of the Company’s U.S. based wind and solar businesses are organized as limited liability corporations ("LLC") and partnerships and have non-controlling Class A membership equity investors (“Class A partnership units” or "Class A Equity Investors") which are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. These LLC and partnership's agreements have liquidation rights and priorities that are different from the underlying percentages ownership interests. In those situations, simply applying the percentage ownership interest to GAAP net income in order to determine earnings or losses would not accurately represent the income allocation and cash flow distributions that will ultimately be received by the investors. As such, the share of earnings attributable to the non-controlling interest holders in these entities is calculated using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting (note 19).

Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

1.
Significant accounting policies (continued)
(q)
Non-controlling interests (continued)
The HLBV method uses a balance sheet approach. A calculation is prepared at each balance sheet date to determine the amount that Class A Equity Investors would receive if an equity investment entity were to liquidate all of its assets and distribute that cash to the investors based on the contractually defined liquidation priorities. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period is the Class A Equity Investors' share of the earnings or losses from the investment for that period. Due to certain mandatory liquidation provisions of the LLC and partnership agreements, this could result in a net loss to APUC’s consolidated results in periods in which the Class A Equity Investors report net income. The calculation varies in its complexity depending on the capital structure and the tax considerations of the investments.
Equity instruments subject to redemption upon the occurrence of uncertain events not solely within APUC’s control are classified as temporary equity on the consolidated balance sheets. The Company records temporary equity at issuance based on cash received less any transaction costs. As needed, the Company reevaluates the classification of its redeemable instruments, as well as the probability of redemption. If the redemption amount is probable or currently redeemable, the Company records the instruments at their redemption value. Increases or decreases in the carrying amount of a redeemable instrument are recorded within deficit. When the redemption feature lapses or other events cause the classification of an equity instrument as temporary equity to be no longer required, the existing carrying amount of the equity instrument is reclassified to permanent equity at the date of the event that caused the reclassification.
(r)
Recognition of revenue
Revenue derived from non-regulated energy generation sales, which are mostly under long-term power purchase contracts, is recorded at the time electrical energy is delivered.
Qualifying renewable energy projects receive renewable energy credits ("REC") and solar renewable energy credits (“SRECs”) for the generation and delivery of renewable energy to the power grid. The energy credit certificates represent proof that 1 MW of electricity was generated from an eligible energy source. The REC and SREC can be traded and the owner of the REC or SREC can claim to have purchased renewable energy. RECs and SRECs are primarily sold under fixed contracts, and revenue for these contracts is recognized at the time of generation. Any REC's or SRECs generated above contracted amounts are held in inventory, with the offset recorded as a decrease in operating expenses.
Revenue related to utility electricity and natural gas sales and distribution are recorded when the electricity or natural gas is delivered. At the end of each month, the electricity and natural gas delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue and sales are based on the ratio of billable days versus unbilled days, amount of electricity or natural gas procured during that month, historical customer class usage patterns, weather, line loss, unaccounted-for gas and current tariffs.
Revenue for certain of the Company’s regulated utilities is subject to revenue decoupling mechanisms approved by their respective regulators which require to charge approved annual delivery revenue on a systematic basis over the 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 (note 7(e)).
Water reclamation and distribution revenues are recorded when water is processed or delivered to customers. At the end of each month, the water delivered and wastewater collected from the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue are based on the ratio of billable days versus unbilled days, amount of water procured and collected during that month, historical customer class usage patterns and current tariffs.
On occasion, a utility is permitted to implement new rates that have not been formally approved by the regulatory commission, which are subject to refund. The Company recognizes revenue based on the interim rate and if needed, establishes a reserve for amounts that could be refunded based on experience for the jurisdiction in which the rates were implemented.
Revenue is recorded net of sales taxes.

Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

1.
Significant accounting policies (continued)
(s)
Foreign currency translation
APUC’s reporting currency is the Canadian dollar.
The Company’s U.S. operations are determined to have the U.S. dollar as their functional currency since the preponderance of operating, financing and investing transactions are denominated in U.S. dollars. The financial statements of these operations are translated into Canadian dollars using the current rate method, whereby assets and liabilities are translated at the rate prevailing at the balance sheet date, and revenue and expenses are translated using average rates for the period.
Unrealized gains or losses arising as a result of the translation of the financial statements of these entities are reported as a component of OCI and are accumulated in a component of equity on the consolidated balance sheets, and are not recorded in income unless there is a complete or substantially complete sale or liquidation of the investment.
(t)
Income taxes
Income taxes are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance is recorded against deferred tax assets to the extent that it is considered more likely than not that the deferred tax asset will not be realized. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in earnings in the period that includes the date of enactment. Income tax credits are treated as a reduction to current income tax expense in the year the credit arises or future periods to the extent that realization of such benefit is more likely than not.
The organizational structure of APUC and its subsidiaries is complex and the related tax interpretations, regulations and legislation in the tax jurisdictions in which they operate are continually changing. As a result, there can be tax matters that have uncertain tax positions. The Company recognizes the effect of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs.
(u)Financial instruments and derivatives
Accounts receivable and notes receivable are measured at amortized cost. Long-term debt and Series C preferred shares are measured at amortized cost using the effective interest method, adjusted for the amortization or accretion of premiums or discounts.
Transaction costs that are directly attributable to the acquisition of financial assets are accounted for as part of the asset’s carrying value at inception. Transaction costs related to a recognized debt liability are presented in the consolidated balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts and premiums. Costs of arranging the Company’s revolving credit facilities and intercompany loans are recorded in other assets. Deferred financing costs, premiums and discounts on long-term debt are amortized using the effective interest method while deferred financing costs relating to the revolving credit facilities and intercompany loans are amortized on a straight-line basis over the term of the respective instrument.
The Company uses derivative financial instruments as one method to manage exposures to fluctuations in exchange rates, interest rates and commodity prices. APUC recognizes all derivative instruments as either assets or liabilities on the consolidated balance sheets at their respective fair values. The fair value recognized on derivative instruments executed with the same counterparty under a master netting arrangement are presented on a gross basis on the consolidated balance sheets. The amounts that could net settle are not significant. The Company applies hedge accounting to some of its financial instruments used to manage its foreign currency risk exposure, interest risk and price risk exposure associated with sales of generated electricity.



Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

1.
Significant accounting policies (continued)
(u)Financial instruments and derivatives (continued)
For derivatives designated in a cash flow hedge relationship, the effective portion of the change in fair value is recognized in OCI. The ineffective portion is immediately recognized in earnings. The amount recognized in AOCI is reclassified to earnings in the same period as the hedged cash flows affect earnings under the same line item in the consolidated statements of operations as the hedged item. If the hedging instrument no longer meets the criteria for hedge accounting, expires or is sold, terminated, exercised, or the designation is revoked, then hedge accounting is discontinued prospectively. The amount remaining in AOCI is transferred to the consolidated statements of operations in the same period that the hedged item affects earnings. If the forecasted transaction is no longer expected to occur, then the balance in AOCI is recognized immediately in earnings.
Foreign currency gain or loss on derivative or financial instruments designated as a hedge of the foreign currency exposure of a net investment in foreign operations that are effective as a hedge are reported in the same manner as the translation adjustment (in OCI) related to the net investment. To the extent that the hedge is ineffective, such differences are recognized in earnings.
The Company’s electric distribution and thermal generation facilities enter into power and gas purchase contracts for load serving and generation requirements. These contracts meet the exemption for normal purchase and normal sales and as such, are not required to be recorded at fair value as derivatives and are accounted for on an accrual basis. Counterparties are evaluated on an ongoing basis for non-performance risk to ensure it does not impact the conclusion with respect to this exemption.
(v)Fair value measurements
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 principal 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 the measurement date.
(w)
Commitments and contingencies
Liabilities for loss contingencies arising from environmental remediation, claims, assessments, litigation, fines, penalties and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred.
(x)
Use of estimates
The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of these consolidated financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the years presented, management has made a number of estimates and valuation assumptions, including the useful lives and recoverability of property, plant and equipment, intangible assets and goodwill; the recoverability of notes receivable and long-term investments; the recoverability of deferred tax assets; assessments of unbilled revenue; pension and OPEB obligations; timing effect of regulated assets and liabilities; contingencies related to environmental matters; the fair value of assets and liabilities acquired in a business combination; and, the fair value of financial instruments. These estimates and valuation assumptions are based on present conditions and management’s planned course of action, as well as assumptions about future business and economic conditions. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.

Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

2.     Recently issued accounting pronouncements
(a)
Recently adopted accounting pronouncements    
The FASB Issued ASU 2017-03 Accounting Changes and Error Corrections (Topic 250) and Investments—Equity Method and Joint Ventures (Topic 323) to enhance disclosures of new accounting standards, including a comparison to current accounting policies, and the progress status of implementation. This


ASU applies to ASU No. 2014-09, Revenue from Contracts with Customers (Topic


606); ASU No. 2016-02, Leases (Topic 842); and ASU 2016-03, Financial Instruments - Credit


Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, and subsequent


amendments. The Company has enhanced its disclosures regarding the impact that recently issued accounting standards will have on the Company's consolidated financial statements when such standards are adopted in a future period.
The FASB issued ASU 2016-19, Technical Corrections and Improvements, to clarify the codification, correct unintended application of guidance, or make minor improvements to the codification. The adoption of this ASU in the fourth quarter of 2016 had no impact on the Company’s consolidated financial statements.
The FASB issued ASU 2015-16 Business Combinations (Topic 805): Simplifying the Accounting for Measurement Period Adjustments. Under this ASU, adjustments to the provisional amounts recorded in a business combination continue to be calculated as if the accounting had been completed at the acquisition date. However, the ASU eliminates the requirement to retrospectively account for those adjustments and instead requires recognition in the period that the adjustments are identified. The adoption of this ASU effective January 1, 2016 had no impact on the Company's consolidated financial statements.
The FASB issued ASU 2015-05, Intangibles: Goodwill and Other Internal-Use Software (Subtopic 350-40), to provide guidance to customers about whether a cloud computing arrangement includes a software license. The prospective adoption of this ASU effective January 1, 2016 had no impact on the Company's consolidated financial statements.
The FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis, which ends the deferral granted to investment companies from applying the VIE guidance and makes targeted amendments to the current consolidation guidance. Some of the more notable amendments are (1) the identification of variable interests when fees are paid to a decision maker or service provider, (2) the VIE characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. The adoption of this ASU effective January 1, 2016 had no impact on the Company's consolidated financial statements.
The FASB issued ASU 2015-01, Income Statement: Extraordinary and Unusual Items (Subtopic 225-20), to simplify income statement classification by removing the concept of extraordinary items from U.S. GAAP. As a result, items that are both unusual and infrequent will no longer be separately reported net of tax after continuing operations. The adoption of this ASU effective January 1, 2016 had no impact on the Company's consolidated financial statements.
The FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity. ASU 2014-16 clarifies how current guidance should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. In addition, ASU 2014-16 clarifies that in evaluating the nature of a host contract, an entity should assess the substance of the relevant terms and features (that is, the relative strength of the debt-like or equity-like terms and features given the facts and circumstances) when considering how to weigh those terms and features. The adoption of this ASU effective January 1, 2016 had no impact on the Company's consolidated financial statements.
The FASB issued ASU 2014-15, Presentation of Financial Statements - Going Concern. This new standard provides that in connection with preparing financial statements for each annual and interim reporting period, an entity’s management should evaluate whether there are conditions or events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. The adoption of this standard as of December 31, 2016 had no impact on the Company’s consolidated financial statements. Its implementation leveraged existing financial reporting processes.


Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

2.     Recently issued accounting pronouncements (continued)
(a)    Recently adopted accounting pronouncements (continued)
The FASB issued ASU 2014-12, Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. This newly issued accounting standard is intended to resolve the diverse accounting treatment of those awards in practice. The adoption of this ASU effective January 1, 2016 had no impact on the Company's consolidated financial statements.
(b)
Recently issued accounting guidance not yet adopted
The FASB issued ASU 2017-04 Business Combinations (Topic 350): Intangibles - Goodwill and Other (Topic 350) Simplifying the Test for Goodwill Impairment. The update is intended to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. The standard is effective for fiscal years and interim periods beginning after December 15, 2019.
The FASB issued ASU 2017-01 Business Combinations (Topic 805): Clarifying the Definition of a Business. The update is intended to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The standard is effective for fiscal years and interim periods beginning after December 15, 2017.
The FASB issued ASU 2016-18 Statement of Cash Flows (Topic 230): Restricted Cash to eliminate current diversity in practice in the classification and presentation of changes in restricted cash on the statement of cash flows. The standard is effective for fiscal years and interim periods beginning after December 15, 2017. The Company currently present changes in restricted cash as investing activities. The adoption of this standard will change the presentation of restricted cash on the consolidated statement of cash flows.
The FASB issued ASU 2016-17 Consolidation (Topic 810): Interests Held through Related Parties That Are under Common Control. This ASU amends the consolidation guidance on how a reporting entity that is the single decision maker of a VIE should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. The standard is effective for fiscal years and interim periods beginning after December 15, 2016. Early adoption is permitted. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations.
The FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory. The new standard requires the recognition of current and deferred income taxes for an intra-entity transfer of an asset other than inventory. Current GAAP prohibits the recognition of current and deferred income taxes on these transactions until the asset has been sold to an outside party. The standard is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.
The FASB issued ASU 2016-15 Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts and Cash Payments in order to eliminate current diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The standard is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.


Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

2.     Recently issued accounting pronouncements (continued)
(b)
Recently issued accounting guidance not yet adopted (continued)
The FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments to provide financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. To achieve this objective, the amendments in this update replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses. The standard is effective for fiscal years and interim periods beginning after December 15, 2019. Early adoption for fiscal years and interim periods beginning after December 15, 2018 is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.
The FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718) to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The standard is effective for fiscal years and interim periods beginning after December 15, 2016. Early adoption is permitted. The adoption of this standard is expected to have no material impact on the Company's consolidated financial statements. The Company intends to continue with its current accounting policy to record the stock-based compensation expense adjusted for estimated forfeitures.
The FASB issued ASU 2016-06, Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments to clarify the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts, which is one of the criteria for bifurcating an embedded derivative. An entity performing the assessment under the amendments in this Update is required to assess the embedded call (put) options solely in accordance with the four-step decision sequence. The standard is effective for fiscal years and interim periods beginning after December 15, 2016. Early adoption is permitted. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations.
The FASB issued ASU 2016-05, Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships to clarify that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument does not, in and of itself, require dedesignation of that hedging relationship provided that all other hedge accounting criteria continue to be met. The application of this standard is effective for fiscal years and interim periods beginning after December 15, 2016. Early adoption is permitted. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations.
The FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among organizations utilizing leases. This ASU requires lessees to recognize the assets and liabilities arising from all leases on the balance sheet, but the effect of leases in the statement of operations and the statement of cash flows is largely unchanged. The standard is effective for fiscal years and interim periods beginning after December 15, 2018. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.
The FASB issued ASU 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities to simplify the measurement, presentation, and disclosure of financial instruments. The standard is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.
The FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, to simplify the subsequent measurement of inventory by replacing the current lower of cost and market test with a lower of cost and net realizable value test. The prospective application of this standard is effective for fiscal years and interim periods beginning after December 15, 2016. Early adoption is permitted. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations.


Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

2.     Recently issued accounting pronouncements (continued)
(b)
Recently issued accounting guidance not yet adopted (continued)
The FASB issued a new revenue recognition standard codified as ASC 606, Revenue from Contracts with Customers. This newly issued accounting standard provides accounting guidance for all revenue arising from contracts with customers and affects all entities that enter into contracts to provide goods or services to their customers unless the contracts are in the scope of other U.S. GAAP requirements, such as the leasing literature. The core principal of the new accounting guidance is that an entity should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASC 606 will also require significantly expanded disclosures regarding the qualitative and quantitative information of the Company's nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. This new revenue standard is required to be applied for fiscal years and interim periods beginning after December 15, 2017 using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. The Company has not elected to early adopt. The Company has identified existing customer contracts and tariffs that are within the scope of the new guidance and has begun an assessment in order to determine the method of adoption and the impact it may have on its consolidated financial statements. The Company also closely monitors outstanding industry specific interpretative issues, including contributions in aid of construction and collectability of sales to low income customers.
3.
Business acquisitions and development projects
(a)
Acquisition of Empire
Subsequent to year end, on January 1, 2017, the Company completed the acquisition of The Empire District Electric Company and its subsidiaries (“Empire”). Empire is a Joplin, Missouri based regulated electric, gas and water utility, serving customers in Missouri, Kansas, Oklahoma and Arkansas. 
The purchase price of approximately U.S.$2,400,000 for the acquisition of Empire consists of cash payment to Empire shareholders of U.S.$34.00 per common share and the assumption of approximately U.S.$855,000 of debt. The cash payment was funded with the acquisition facility for an amount of U.S.$1,336,440 (note 9(b)), proceeds received from the initial instalment of convertible debentures (note 14) and existing credit facility. The costs related to the acquisition have been expensed through the consolidated statements of operations.
Due to the timing of the acquisition, the Company has not completed the fair value measurements. The Company will continue to review information and perform further analysis prior to finalizing the allocation of the consideration paid to the fair value of the assets acquired and liabilities assumed and preparing the related pro forma information.
(b)
Luning Solar Facility
Luning Utilities (Luning Holdings) LLC (the “Luning Holdings”) is owned by the Calpeco Electric System. During 2016, a tax equity agreement was executed. The Class A partnership units are owned by a third-party tax equity investor who funded U.S.$7,826 as of December 31, 2016 and an amount of U.S.$31,212, subsequent to year-end, on February 17, 2017. With its interest, the tax equity investor will receive the majority of the tax attributes associated with the Luning Solar project. The Company accounts for this interest as “Redeemable non-controlling interest” outside of permanent equity on the consolidated balance sheets. Redemption is not considered probable as of December 31, 2016.Subsequent to year-end, on February 15, 2017, Luning Holdings obtained control of the Luning Solar Facility as it achieved commercial operation. The 50MWac solar generating facility is located in Mineral County, Nevada.
(c)
Bakersfield II Solar Facility
On December 14, 2016, the Company completed construction and placed in service a 10 MWac solar powered generating facility located adjacent to the Company’s 20 MWac Bakersfield I Solar Facility in Kern County, California (“Bakersfield II Solar Facility”). Commercial operations as defined by the power purchase agreement was reached on January 11, 2017.


Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

3.
Business acquisitions and development projects (continued)
(c)
Bakersfield II Solar Facility (continued)
The Bakersfield II Solar Facility is controlled by a subsidiary of APUC (the “Bakersfield II Partnership”). The Class A partnership units are owned by a third-party tax equity investor who funded U.S.$2,454 on November 29, 2016 and approximately U.S.$9,800 on February 28, 2017. With its partnership interest, the tax equity investor will receive the majority of the tax attributes associated with the project. The Company accounts for this interest as “Non-controlling interest” on the consolidated balance sheets.
(d)
Wind Turbine Components Purchase
In the fourth quarter of 2016, the Company purchased approximately $75,000 of wind turbine components that will qualify between 500 MW and 700 MW of new wind powered projects for the full U.S.$0.023/kWh renewable energy production tax credit under the safe harbor guidelines established by the U.S. Internal Revenue Service, provided that such projects are placed in service before the end of 2020.
(e)
Acquisition of Park Water System
On January 8, 2016, the Company completed the acquisition of Western Water Holdings, LLC which is the parent company of Park Water Company (“Park Water System”), a regulated water distribution utility. Park Water System owns and operates three regulated water utilities engaged in the production, treatment, storage, distribution, and sale of water in southern California and western Montana. Those three utilities were named Park Water Company, Apple Valley Ranchos Water Co. and Mountain Water Company. The total purchase price for the Park Water System is $353,077 (U.S.$249,540), net of the debt assumed of U.S.$91,750 and is subject to certain closing adjustments. All costs related to the acquisition have been expensed in the consolidated statements of operations.
The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date:
Working capital
$
2,045

Property, plant and equipment
345,254

Notes receivable
1,781

Goodwill
210,463

Regulatory assets
54,548

Other assets
185

Long-term debt
(146,727
)
Regulatory liabilities
(3,758
)
Pension and OPEB
(18,747
)
Deferred income tax liability, net
(51,795
)
Other liabilities
(40,172
)
Total net assets acquired
$
353,077

The determination of the fair value of assets acquired and liabilities assumed is based upon management's estimates and certain assumptions. Immaterial changes to the initial allocation were recorded during 2016.
Goodwill represents the excess of the purchase price over the aggregate fair value of net assets acquired. The contributing factors to the amount recorded as goodwill include future growth, potential synergies and cost savings in the delivery of certain shared administrative and other services. Goodwill is reported under the Distribution segment.






Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

3.
Business acquisitions and development projects (continued)
(e)
Acquisition of Park Water System (continued)
Mountain Water Company, the water utility in western Montana serving customers in and around the municipality of Missoula is currently the subject of a condemnation proceeding by the city of Missoula. On August 2, 2016 the Supreme Court of Montana upheld the District Court’s decision that the City of Missoula can proceed with the condemnation of Mountain Water Company’s assets. Upon taking possession of Mountain Water’s assets, the compensation to be paid by the City of Missoula for such taking has been determined by the valuation commissioners to be U.S.$88,600. In addition, post-summons capital expenditures and attorney’s fees as determined by the Montana court, property tax reimbursements and amounts in accordance with agreements entered into at the time of the Park Water acquisition should result in APUC receiving additional proceeds.
On December 22, 2015, various developers filed a lawsuit in Missoula County District Court against Mountain Water Company and the city of Missoula. The lawsuit pertains to Funded By Other (FBO) contracts between each developer and Mountain Water Company. Under those FBO contracts, the developers paid for facilities to provide water service and Mountain Water Company agreed to refund such amounts over a 40 year period.  These FBO contracts are recorded on the balance sheet of Mountain Water and reflect a non-discounted liability of U.S.$23,108 at the acquisition date. On February 21, 2017, the Montana district court issued an order finding that Mountain Water Company is liable for the developer refunds even after the city of Missoula condemns and takes possession of the utility assets. The amount of the refund obligations to be paid by Mountain Water Company is subject to further proceedings in the Montana district court.
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 useful life of the Park Water System assets is 40 years.
The Park Water System contributed revenue of $96,695 and pre-tax net earnings of $25,374 to the Company’s consolidated financial results for the year ended December 31, 2016.
(f)
Commercial operation of Morse Wind Facility
In 2015, the Company completed construction of a 23 MW wind generating facility located near Morse, Saskatchewan (“Morse Wind Facility”). Sale of power to the utility commenced in March 2015 at rates equivalent to those under the power purchase agreement. Commercial operation date as defined in the power purchase agreement occurred on April 22, 2015. The cost of the generating assets of $65,016 is recorded as property, plant and equipment on the consolidated balance sheets while $16,709 is recorded as intangible assets, for a total investment of $81,725. The weighted average useful life of the Morse Wind Facility is 35 years.
(g)
Acquisition of New Hampshire Gas
On January 2, 2015, the Company completed the acquisition of New Hampshire Gas, a regulated propane gas distribution utility located in Keene, New Hampshire. The New Hampshire Gas System services approximately 1,200 propane gas distribution customers. Total purchase price for the New Hampshire Gas System is U.S.$3,161.
(h)
Commercial operation of Bakersfield Solar I Facility
In 2014, the Company completed construction of a 20 MWac solar powered generating facility located in Kern County, California (“Bakersfield I Solar Facility”) which was placed in service on December 31, 2014. The Bakersfield I Solar Facility started selling power at the power purchase agreement price on May 15, 2015. The cost of these generating assets amounts to U.S.$59,281 and is recorded as property, plant and equipment on the consolidated balance sheets. The weighted average useful life of the Bakersfield Solar I Facility is 34 years.
The Bakersfield I Solar Facility is controlled by a subsidiary of APUC (the “Bakersfield I Partnership”). The Class A partnership units are owned by a third-party tax-equity investor who funded a total of U.S.$22,438 to the project. With its partnership interest, the tax equity investor will receive the majority of the tax attributes associated with the project.



Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

3.
Business acquisitions and development projects (continued)
(h)
Commercial operation of Bakersfield Solar I Facility (continued)
During a six-month period in year 2020, the Tax Investor has the right to withdraw from the Bakersfield I Solar Facility and require the Company to redeem its remaining interests for cash. As a result, the Company accounts for this interest as “Redeemable non-controlling interest” outside of permanent equity on the consolidated balance sheets. Redemption is not considered probable as of December 31, 2016.
(i)
Acquisition of Shady Oaks Wind Facility
Effective January 1, 2013, the Company acquired the 109.5 MW Shady Oaks wind-powered generating facility (“Shady Oaks Wind Facility”). 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 which are expected to be finalized in 2017. Changes in measurement of the final purchase price adjustment subsequent to December 31, 2013, the end of the business combination measurement period, are recorded in current period operations. To that effect, no gain or loss was recognized in 2016 (2015 - U.S.$nil).
4.
Accounts receivable
Accounts receivable as of December 31, 2016 include unbilled revenue of $57,822 (2015 - $49,002) from the Company’s regulated utilities. Accounts receivable as of December 31, 2016 are presented net of allowance for doubtful accounts of $7,064 (2015 - $7,966).
5.
Property, plant and equipment
Property, plant and equipment consist of the following: 
2016
 
 
 
 
 
 
Cost
 
Accumulated
depreciation
 
Net book
value
Generation
$
2,613,267

 
$
419,227

 
$
2,194,040

Distribution
2,638,488

 
462,454

 
2,176,034

Land
60,868

 
—

 
60,868

Equipment and other
139,961

 
44,700

 
95,261

Construction in progress
 
 
 
 
 
   Generation
197,405

 
—

 
197,405

   Distribution
166,338

 
—

 
166,338

 
$
5,816,327

 
$
926,381

 
$
4,889,946

2015
 
 
 
 
 
 
Cost
 
Accumulated
depreciation
 
Net book
value
Generation
$
2,138,748

 
$
358,200

 
$
1,780,548

Distribution
2,075,059

 
265,741

 
1,809,318

Land
23,258

 
—

 
23,258

Equipment and other
129,555

 
37,443

 
92,112

Construction in progress
 
 
 
 
 
   Generation
68,265

 
—

 
68,265

   Distribution
103,669

 
—

 
103,669

 
$
4,538,554

 
$
661,384

 
$
3,877,170

Generation assets include cost of $142,246 (2015 - $158,514) and accumulated depreciation of $39,958 (2015 - $38,507) related to facilities under capital lease or owned by consolidated VIEs. Depreciation expense of facilities under capital lease was $2,117 (2015 - $2,117).

Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

5.
Property, plant and equipment (continued)
On September 16, 2016, Revenu Québec issued a notice of assessment approving the Company's Canadian renewable and conservation expense ("CRCE") refundable tax credit claim for the St Damase wind facility in the amount of $14,086. The Company received the tax credit in cash on October 6, 2016. The tax credit together with interest received was recorded, net of related costs, as a reduction of the related assets. As at December 31, 2016, investment tax credits, CRCE tax credit, government grants and contributions received in aid of construction of $49,794 (2015 - $9,623) have been credited to the cost of the assets.
Water and wastewater distribution assets include expansion costs of $1,000 on which the Company does not currently earn a return. 
6.
Intangible assets and goodwill
Intangible assets consist of the following:
2016
 
 
 
 
 
 
Cost
 
Accumulated
amortization
 
Net book
value
Power sales contracts
$
72,207

 
$
44,641

 
$
27,566

Customer relationships
35,979

 
10,999

 
24,980

Interconnection agreements
13,000

 
557

 
12,443

 
$
121,186

 
$
56,197

 
$
64,989

2015
 
 
 
 
 
 
Cost
 
Accumulated
amortization
 
Net book
value
Power sales contracts
$
75,239

 
$
40,244

 
$
34,995

Customer relationships
37,083

 
10,371

 
26,712

Interconnection agreements
13,000

—

230

 
12,770

 
$
125,322

 
$
50,845

 
$
74,477

Estimated amortization expense for intangible assets for the next year is $3,880, $3,530 in year two, $3,080 in year three, $2,220 in year four and $2,220 in year five.
Changes in goodwill are as follows:
 
Distribution
Balance, January 1, 2015
$
92,328

Business acquisitions
290

Foreign exchange
17,875

Balance, December 31, 2015
$
110,493

Business acquisitions (note 3(e))
210,463

Foreign exchange
(14,315
)
Balance, December 31, 2016
$
306,641


Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

7.
Regulatory matters
The Company’s regulated utility operating companies 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 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 revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate-setting process.
At any given time, the Company can have several regulatory proceedings underway. The financial effects of these proceedings are reflected in the consolidated financial statements based on regulatory approval obtained to the extent that there is a financial impact during the applicable reporting period.
On January 31, 2017, the Georgia Public Service Commission approved a Final Order for the Peach State Gas System of a U.S.$686 annual revenue increase effective February 1, 2017.
On December 8, 2016, the California Public Utilities Commission approved a Final Order for the CalPeco Electric System of a U.S.$8,318 annual revenue increase effective January 1, 2017 for services rendered on or after January 1, 2016. The Commission also required CalPeco Electric System to apply the flow through method of accounting for income tax expense related to repair costs for regulatory purposes (note 7(g)).
On November 21, 2016, the Arizona Corporation Commission approved a Final Order for the Bella Vista Water System and Rio Rico Water & Sewer System of a combined revenue increase of U.S.$1,935 effective November 1, 2016.
In April 2016, the Granite State Electric System filed a general rate application. In June 2016, the New Hampshire Public Utility Commission approved a temporary annual rate increase of U.S.$2,355, effective July 1, 2016. A Final Order is expected in Q2 2017.
On April 22, 2016, the Arizona Corporation Commission approved a Final Order for the Black Mountain Sewer System of a U.S.$175 annual revenue increase effective May 1, 2016.
On February 18, 2016, the Georgia Public Service Commission approved a Final Order for the Peach State Gas System of a U.S.$2,725 annual revenue increase effective March 1, 2016.
On February 10, 2016, the New England Gas System received a Final Order from the Massachusetts Department of Public Utilities approving an annual revenue increase of U.S.$7,800 effective March 1, 2016 and an additional U.S. $500 effective March 1, 2017.
On June 26, 2015, the EnergyNorth Gas System received a Final Order from the New Hampshire Public Utility Commission approving a U.S.$12,400 annual revenue increase effective July 1, 2015.
On March 12, 2015, the Pine Bluff Water System received a Final Order from the Arkansas Public Service Commission approving an annual revenue increase of U.S.$1,087 effective March 15, 2015.
On February 11, 2015, the Midstates Gas System received a Final Order from the Illinois Commerce Commission approving an annual revenue increase of U.S.$4,625 effective February 20, 2015.


Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

7.
Regulatory matters (continued)
Regulatory assets and liabilities consist of the following: 
 
2016
 
2015
Regulatory assets
 
 
 
Environmental remediation (a)
$
104,160

 
$
116,747

Pension and post-employment benefits (b)
75,527

 
69,537

Commodity costs adjustment (c)
6,972

 
7,643

Rate case costs (d)
8,572

 
6,535

Rate adjustment mechanism (e)
40,602

 
14,804

Debt premium (f)
25,173

 
5,132

Taxes (g)
10,182

 
5,926

Other
20,776

 
18,991

Total regulatory assets
$
291,964

 
$
245,315

Less current regulatory assets
(48,440
)
 
(32,213
)
Non-current regulatory assets
$
243,524

 
$
213,102

 
 
 
 
Regulatory liabilities
 
 
 
Cost of removal (h)
$
110,330

 
$
107,988

Rate-base offset (i)
20,946

 
24,984

Commodity costs adjustment (c)
33,891

 
32,423

Pension and post-employment benefits (b)
5,481

 
397

Taxes (g)
1,501

 
188

Other
10,585

 
9,367

Total regulatory liabilities
$
182,734

 
$
175,347

Less current regulatory liabilities
(47,769
)
 
(44,167
)
Non-current regulatory liabilities
$
134,965

 
$
131,180

(a)
Environmental remediation
Actual expenditures incurred for the clean-up of certain former gas manufacturing facilities (note 13(b)) are recovered through rates over a period of 7 years and are subject to an annual cap.
(b)
Pension and post-employment benefits
As part of certain business acquisitions, the regulators authorized a regulatory asset or liability being set up for the amounts of pension and post-employment benefits that have not yet been recognized in net periodic cost and were presented as AOCI prior to the acquisition. An amount of $29,037 relates to an acquisition and was authorized for recognition as an asset by the regulator. Recovery is anticipated to be approved in a final rate order to be received on completion of the next general rate case. The balance is recovered through rates over the future service years of the employees at the time the regulatory asset was set up (an average of 10 years) or consistent with the treatment of OCI under ASC 712 Compensation Non-retirement Post-employment Benefits and ASC 715 Compensation Retirement Benefits before the transfer to regulatory asset occurred. The pension and post-employments benefits liability is related to tracking accounts pertaining solely to Park Water Company. The amounts recorded in these accounts occur when actual expenses have been less than adopted and refunds are expected to occur in future periods.
(c)
Commodity costs adjustment
The revenue from the utilities includes a component which is designed to recover the cost of electricity and natural gas through rates charged to customers. To the extent actual costs of power or natural gas purchased differ from power or natural gas costs recoverable through current rates, that difference is not recorded on the consolidated statements of operations but rather is deferred and recorded as a regulatory asset or liability on the consolidated balance sheets.

Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

7.
Regulatory matters (continued)
(c)    Commodity costs adjustment (continued)
These differences are reflected in adjustments to rates and recorded as an adjustment to cost of electricity and natural gas in future periods, subject to regulatory review. Derivatives are often utilized to manage the price risk associated with natural gas purchasing activities in accordance with the expectations of state regulators. The gains and losses associated with these derivatives (note 25(b)(i)) are recoverable through the commodity costs adjustment.
(d)
Rate case costs
The costs to file, prosecute and defend rate case applications are referred to as rate case costs. These costs are capitalized and amortized over the period of rate recovery granted by the regulator.
(e)
Rate adjustment mechanism
Revenue for Calpeco Electric System, Park Water System, Peach State Gas System and New England Gas Systems are subject to a revenue decoupling mechanism approved by their respective regulator which require charging approved annual delivery revenue on a systematic basis over the 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. In addition, retroactive rate adjustments for services rendered but to be collected over a period not exceeding 24 months are accrued upon approval of the Final Order.
(f)
Debt premium
Debt premium on acquired debt is recovered as a component of the weighted average cost of debt.
(g)
Taxes
Under flow-through accounting, the income tax effects of certain tax items are reflected in cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. This regulatory treatment was applied to the tax benefit generated by repair costs that were previously capitalized for tax purposes in CalPeco Electric System's Final Order issued December 8, 2016. In this instance, the agreed upon rate increase was less than it would have been absent the flow-through treatment by U.S.$1,501. A regulatory asset established to reflect the future increases in income taxes payable will be recovered from customers as the temporary differences reverse. As a result of this regulatory treatment, a tax benefit is recorded consistent with the flow-through method with respect to costs considered repairs for income tax purposes and capitalized for book purposes.
(h)
Cost of removal
The regulatory liability for cost of removal represents amounts that have been collected from ratepayers for costs that are expected to be incurred in the future to retire the utility plant.
(i)
Rate-base offset
The regulators imposed a rate-base offset that will reduce the revenue requirement at future rate proceedings. The rate-base offset declines on a straight-line basis over a period of 10-16 years.
As recovery of regulatory assets is subject to regulatory approval, if there were any changes in regulatory positions that indicate recovery is not probable, the related cost would be charged to earnings in the period of such determination. The Company generally earns carrying charges on the regulatory balances related to commodity cost adjustment, retroactive rate adjustments and rate case costs.

Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

8.
Long-term investments
Long-term investments consist of the following:
 
2016
 
2015
Equity-method investees
 
 
 
Red Lily I Wind Facility (a)
$
23,504

 
$
—

Deerfield Wind Project (b)
34,727

 
2,240

Odell Wind Facility (c)
—

 
42,287

Amherst Island Wind Project (d)
558

 
—

Interests in natural gas pipeline developments (e)
—

 
5,623

Other
5,630

 
2,323

 
$
64,419

 
$
52,473

Notes receivable
 
 
 
Development loans (f)
$
32,125

 
$
96,924

Red Lily Senior loan Tranche 2, interest at 6.31% (a)
—

 
11,588

Red Lily Subordinated loan Tranche 1, interest at 12.5% (a)
—

 
6,565

Other
6,058

 
4,306

 
38,183

 
119,383

Available-for-sale investment
169

 
2,946

Other investments
2,662

 
—

Total long-term investments
$
105,433

 
$
174,802

(a)
Red Lily I Wind Facility
Up to April 12, 2016, the Red Lily I Partnership (the “Partnership”) was 100% owned by an independent investor. APUC provided operation and supervision services to the Red Lily I project ("Red Lily I Wind Facility"), a 26.4 MW wind energy facility located in southeastern Saskatchewan.
The Company’s investment in the Red Lily I Wind Facility as at January 1, 2015 was in the form of participation in a portion of the senior and subordinated debt facilities of the Partnership. On February 23, 2016, a second tranche of subordinated loan for an amount equal to $15,588 was advanced to the Partnership by the Company. The proceeds from this additional subordinated debt were used by the Partnership to repay Tranche 2 of the Partnership’s senior debt, including the Company’s portion.
Effective April 12, 2016, the Company exercised its option to subscribe for a 75% equity interest in the Partnership in exchange for the outstanding amount on its Tranche 1 and Tranche 2 subordinated loans. The carrying value of the Company's investment of $22,153 exceeds by $858 the Company's proportionate share of the Partnership's net assets as at that date. The difference is attributable to property, plant and equipment and is amortized over the assets' weighted average useful lives.
Due to certain participating rights being held by the minority investor, the decisions which most significantly impact the economic performance of Red Lily I require unanimous consent. As such, APUC is deemed, under U.S. GAAP, to not have control over the Partnership. As APUC exercises significant influence over operating and financial policies of Red Lily I, the Company accounts for the Partnership using the equity method. The Red Lily I Wind Facility contributed equity income of $1,288 to the Company's consolidated financial results from acquisition to December 31, 2016.






Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

8.
Long-term investments (continued)
(b)
Deerfield Wind Project
On October 19, 2015, the Company acquired a 50% equity interest in Deerfield Wind SponsorCo LLC (“Deerfield SponsorCo”), which indirectly owns a 150 MW construction-stage wind development project (“Deerfield Wind Project”) in the state of Michigan.
Upon the acquisition of the Deerfield Wind Project by Deerfield SponsorCo, the two members each contributed U.S.$1,000 to the capital of Deerfield SponsorCo. On October 12, 2016, third-party construction loan financing was provided to the Deerfield Wind Project in the amount of U.S.$262,900 and a tax equity agreement was executed. Concurrently, each member contributed another U.S.$19,891 to the capital of Deerfield SponsorCo. The Company holds an option to acquire the other 50% interest for total contributions, subject to certain adjustments at any time prior to the date that is 90 days following commencement of operations expected early 2017. The interest capitalized during the year ended December 31, 2016 to the investment while the Deerfield Wind Project is under construction amounts to $6,072 (2015 - $94).
As of December 31, 2016, Deerfield SponsorCo is considered a VIE namely due to the low level of its equity at that point. The Company is not considered the primary beneficiary of Deerfield SponsorCo as the two members have joint control and all decisions must be unanimous. As APUC exercises significant influence over operating and financial policies of Deerfield SponsorCo, the Company is accounting for the entity as an equity method investment. As at December 31, 2016, the Company’s maximum exposure to loss of $171,239 is comprised of the carrying value of the equity method investment as well as the carrying value of the development loan and outstanding exposure related to credit support as described in note 8(f).
Construction was completed subsequent to year-end and sale of power to the utility under the power purchase agreement started on February 21, 2017.
(c)Odell Wind Facility
Up to September 15, 2016, the Company held a 50% equity interest in Odell SponsorCo LLC, which indirectly owns a 200 MW construction-stage wind development project (“Odell Wind Facility”) in the state of Minnesota.
Construction was completed during the year and sale of power to the utility under the power purchase agreement started on July 29, 2016. The interest capitalized during the year ended December 31, 2016 to the equity-method investment while the Odell Wind Facility was under construction amounts to $3,331 (2015 - $4,415). On August 5, 2016, tax equity financing was provided to the Odell Wind Facility by two U.S. financial institutions in the amount of U.S. $180,000.
On September 15, 2016, the Company acquired the remaining 50% interest in Odell SponsorCo LLC for U.S.$26,500 and as a result, obtained control of the facility. The Company accounted for the business combination using the acquisition method of accounting, which requires, that the fair value of assets acquired, liabilities assumed and non-controlling interest in the subsidiary, be recognized on the consolidated balance sheets as of the acquisition date. It further requires that pre-existing relationships such as the existing development loan between the two parties (note 8(f)) and prior investments of business combinations achieved in stages also be remeasured at fair value. An income approach was used to value these items. A net gain of nil was recorded on acquisition.
The following table summarizes the allocation of the assets acquired and liabilities assumed at the acquisition date:
Working capital
$
12,745

Property, plant and equipment
469,258

Asset retirement obligation
(4,813
)
Deferred tax liability
(4,308
)
Development loan from Algonquin Power Co (note 8(f))
(172,085
)
Non-controlling interest (tax equity investors)
(237,156
)
Net assets
$
63,641





Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

8.
Long-term investments (continued)
(d)Amherst Island Wind Project
Windlectric Inc. ("Windlectric") owns a 75 MW construction-stage wind development project (“Amherst Island Wind Project”) in the province of Ontario. On December 20, 2016, Windlectric, a wholly owned subsidiary of the Company at the time, issued fifty percent of its common shares for $50 to a third party and as a result is no longer controlled by APUC. The Company holds an option to acquire the remaining common shares at a fixed price any time prior to the date that is 90 days following commencement of operations which is expected in 2018.
Windlectric is considered a VIE namely due to the low level of equity at risk at that point. The Company is not considered the primary beneficiary of Windlectric as the two shareholders have joint control and all decisions must be unanimous. As such, on the transaction date, the Company deconsolidated the assets and liabilities of Windlectric and recorded its retained non-controlling investment in equity and notes receivable and payable at fair value. A net gain of nil was recorded on acquisition. The Company is accounting for its investment in the joint venture under the equity method. As of December 31, 2016, the Company’s maximum exposure to loss of $159,993 is comprised of the carrying value of the equity method investment as well as the carrying value of the development loan and outstanding exposure related to credit support as described in note 8(f).
(e)
Natural gas pipeline developments
During 2016, APUC wrote off an amount of $6,367 representing the total value of its equity interest in the natural gas development projects, as both projects have been canceled by the developer.
(f)
Development loans
The Company entered into a committed loan and credit support facility with Odell SponsorCo, Deerfield SponsorCo and Windlectric (collectively, the “Joint Ventures”). During construction, the Company is obligated to provide Joint Ventures with cash advances and credit support (in the form of letters of credit, escrowed cash, or guarantees) in amounts necessary for the continued development and construction of the Joint Ventures’ Wind Projects. The loans bear interest at an annual rate of 7%-10% on outstanding principal amount until commercial operation date and either mature on that date or 5% thereafter until maturity date. The letters of credit are charged an annual fee of 2% on their stated amount. Any loan outstanding to Joint Ventures, to the extent not otherwise repaid earlier, is repayable in cash within 30 days of the fifth anniversary of the commercial operation date for Odell SponsorCo and Deerfield SponsorCo and December 31, 2018 for Windlectric.
As of December 31, 2015, the Company had outstanding loans of U.S.$62,751 from Odell SponsorCo. Following acquisition of control of Odell SponsorCo LLC (note 8(c)), amounts advanced to the Odell Wind Project were eliminated on consolidation. The effects of foreign currency exchange rate fluctuations on these advances of a long-term investment nature are recorded in other comprehensive income effective August 5, 2016.
As of December 31, 2016, the Company had outstanding loans of U.S.$1,789 (2015 - U.S.$7,281) from Deerfield SponsorCo for development costs of the Joint Venture’ Wind Project.
Following the deconsolidation of Windlectric (note 8(d)) on December 20, 2016, amounts advanced by the Company to Windlectric are no longer eliminated and instead are classified as notes receivable. As of December 31, 2016, the Company had outstanding loans of $29,723 from Windlectric.
As of December 31, 2016, the following credit support was issued by the Company: $26,854 letters of credit and guarantees of obligations on behalf of the Joint Ventures, to the utilities under the PPAs; a guarantee of the obligations of the Joint Ventures under the wind turbine, transmission line, transformer, and other supply agreements; a guarantee of the obligations of the Joint Ventures under the engineering, procurement, and construction management agreements; a U.S.$7,614 surety bond and guarantee of the obligations of the Deerfield Wind Project under the decommissioning plan; a U.S.$31,000 letter of credit and guarantee of the obligations of Deerfield SponsorCo under the construction financing agreement . The initial value of the guarantee obligations is recognized under other long-term liabilities and was valued at $429 using a probability weighted discounted cash flow (level 3).
No interest revenue is accrued on the loans due to insufficient collateral in the Joint Ventures.

Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

9.
Long-term debt
Long-term debt consists of the following:
Borrowing type
 
Weighted average coupon
 
Maturity
 
Par value
 
2016
 
2015
Senior Unsecured Revolving Credit Facilities
 
—

 
2017-2019
 
N/A

 
$
242,947

 
$
27,300

Senior Unsecured Bank Credit Facilities
 
—

 
2017-2019
 
N/A

 
2,140,122

 
—

Canadian Dollar Borrowings
 
 
 
 
 
 
 
 
 
 
Senior Unsecured Notes
 
4.99
%
 
2018-2022
 
$
490,000

 
487,389

 
481,991

Senior Secured Project Notes
 
10.29
%
 
2020-2027
 
$
35,600

 
35,600

 
37,347

U.S. Dollar Borrowings
 
 
 
 
 
 
 
 
 
 
Senior Unsecured Notes
 
4.16
%
 
2017-2045
 
US$
525,000

 
700,600

 
721,581

Senior Unsecured Utility Notes
 
5.68
%
 
2017-2028
 
US$
130,709

 
174,206

 
186,446

Senior Secured Utility Bonds
 
6.97
%
 
2020-2043
 
US$
83,500

 
132,551

 
32,130

 
 
 
 
 
 
 
 
$
3,913,415

 
$
1,486,795

Less: current portion
 
 
 
 
 
 
 
(10,075
)
 
(8,945
)
 
 
 
 
 
 
 
 
$
3,903,340

 
$
1,477,850

Long-term debt issued at a subsidiary level relating to a specific operating facility is generally collateralized by the respective facility with no other recourse to the Company. Long-term debt whether or not collateralized have certain financial covenants, which must be maintained on a quarterly basis. Non-compliance with the covenants could restrict cash distributions/dividends to the Company from the specific facilities.
(a)
Senior unsecured revolving credit facilities
APUC has a senior unsecured revolving credit of U.S.$65,000 maturing November 19, 2017. The interest rate is equal to the bankers' acceptance or LIBOR plus a credit spread.
Liberty Utilities Co. has a senior unsecured revolving credit facility of U.S.$200,000 maturing September 30, 2018. The interest rate is equal to LIBOR plus a credit spread.
Algonquin Power Co. has a senior unsecured revolving credit facility of $350,000 maturing July 31, 2019. The interest rate is equal to the bankers' acceptance or LIBOR plus a credit spread.
Algonquin Power Co. has an extendible one-year letter of credit facility agreement.  The facility provides for issuances of letters of credit up to a maximum of $50,000 and U.S.$30,000.  If the facility is not extended at maturity, cash collateral equal to letters of credit outstanding at that date would be posted by the Company.
As part of the Park Water System's acquisition on January 8, 2016 (note 3(b)), the Company assumed U.S.$4,250 of debt outstanding under its revolving credit facilities. Shortly after the closing of the acquisition, the Park Water System repaid and closed the revolving credit facilities.
(b)
Senior unsecured bank credit facilities
On December 30, 2016, in connection with the acquisition of Empire (note 3(a)), the Company drew U.S.$1,336,440 from the acquisition facility it obtained from a syndicate of banks earlier in 2016. The non-revolving term credit facilities are comprised of a U.S.$1,065,000 debt facility and a U.S.$271,440 equity facility both repayable in full on December 30, 2017. The funds drawn were transferred to a paying agent on December 30, 2016 for purposes of distribution to holders of the common shares of Empire (note 3(a)) on January 1, 2017. The total amount of cash held by the paying agent of U.S.$1,495,774 is comprised of this acquisition facility draw of U.S.$1,336,440 and cash proceeds received from the initial instalment of convertible debentures (note 14) and is presented as restricted cash on the consolidated balance sheets. Subsequent to year end, on February 7, 2017, upon receipt of the Final Instalment from the Debentures (note 14) the Company repaid U.S. $567,650 under the acquisition Facility.


Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

9.
Long-term debt (continued)
(b)
Senior unsecured bank credit facilities (continued)
On January, 4, 2016, the Company. entered into a U.S.$235,000 term credit facility with two U.S. banks. The term credit facility is available for acquisitions and general corporate purposes and matures on July 5, 2018.
As part of the Park Water System' s acquisition on January 8, 2016 (note 3(e)), the Company assumed U.S.$22,500 of debt outstanding under a non-revolving term credit facility. The term credit facility bears a variable interest rate based on LIBOR plus a credit spread and matures in 2019 but is repayable on demand without penalty.
(c)
Canadian dollar senior unsecured notes
Subsequent to year end, on January 17, 2017 APCo issued $300,000 senior unsecured debentures bearing interest at 4.09% and with a maturity date of February 17, 2027. The debentures were sold at a price of $99.929 per $100.00 principal amount.
(d)
U.S. dollar senior unsecured utility notes
Subsequent to year-end, on February 8, 2017, the U.S.$707 Bella Vista Water unsecured notes were fully repaid.
Subsequent to year end, on March 1, 2017, Liberty Utilities Group's financing entity entered into an agreement to issue U.S.$750,000 senior unsecured notes in six tranches. The closing of the offering is scheduled to occur before the end of March 2017 with the proceeds to be applied to repay the acquisition facility (note 9(b)) and other existing indebtedness. The notes are of varying maturities from 3 to 30 years with a weighted average life of approximately 15 years and a weighted average coupon of 4.0%.
On April 30, 2015, the Liberty Utilities Group's financing entity issued U.S.$160,000 of senior unsecured 30-year notes bearing a coupon of 4.13% via a private placement in the U.S.. The funds were drawn in two tranches: U.S.$90,000 was drawn on closing and U.S.$70,000 was drawn on July 15, 2015.
(e)
U.S. dollar senior secured notes
On May 12, 2015, the U.S.$76,000 senior debt for the Shady Oaks Wind Facility was repaid.
(f)
U.S. Senior Secured Utility Bonds
As part of the Park Water System' s acquisition on January 8, 2016 (note 3(e)), the Company assumed U.S.$65,000 of debt outstanding under six tranches of first mortgage bonds. The First Mortgage bonds have maturities ranging between 2020 and 2043 with coupons ranging from 4.53% to 8.82%.
On October 1, 2015, the U.S.$9,800 LPSCo Water System IDA bonds were fully repaid.
As of December 31, 2016, the Company had accrued $25,520 in interest expense (2015 - $25,161). Interest expense on the long-term debt in 2016 was $87,143 (2015 - $72,213).
Principal payments due in the next five years and thereafter are as follows: 
2017
 
2018
 
2019
 
2020
 
2021
 
Thereafter
 
Total
$
1,871,864

 
$
461,058

 
$
284,243

 
$
147,264

 
$
157,626

 
$
979,210

 
$
3,901,265

Short-term obligations of $1,861,788 that were refinanced on a long-term basis before the issuance of the financial statements are presented as long-term debt.

Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

10.
Pension and other post-employment benefits
The Company provides defined contribution pension plans to substantially all of its employees. The Company’s contributions for 2016 were $5,223 (2015 - $4,132).
In conjunction with previous utility acquisitions, the Company assumed defined benefit pension and OPEB plans for qualifying employees in the related acquired businesses. The legacy plans of the electricity and gas utilities are non-contributory defined pension plans covering substantially all employees of the acquired businesses. Benefits are based on each employee’s years of service and compensation. The Company also provides a defined benefit cash balance pension plan covering substantially all its new employees and current employees at its water utilities, under which employees are credited with a percentage of base pay plus a prescribed interest rate credit. The OPEB plans provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age and length of service requirements and, in most cases, retirees must cover a portion of the cost of their coverage.
(a)
Net pension and OPEB obligation
The following table sets forth the projected benefit obligations, fair value of plan assets, and funded status of the Company’s plans as of December 31:
 
Pension benefits
 
OPEB
 
2016
 
2015
 
2016
 
2015
Change in projected benefit obligation
 
 
 
 
 
 
 
Projected benefit obligation, beginning of year
$
269,382

 
$
241,963

 
$
76,565

 
$
68,257

Projected benefit obligation assumed from business combination
63,811

 
—

 
9,749

 
—

Modifications to pension plan
(2,754
)
 
(4,995
)
 
(1,235
)
 
—

Service cost
8,435

 
6,663

 
2,916

 
3,093

Interest cost
13,029

 
9,642

 
3,525

 
2,914

Actuarial (gain) loss
6,773

 
(16,098
)
 
(2,870
)
 
(8,466
)
Contributions from retirees
—

 
—

 
547

 
412

Benefits paid
(15,845
)
 
(13,024
)
 
(3,230
)
 
(2,447
)
(Gain) loss on foreign exchange
(10,897
)
 
45,231

 
(2,870
)
 
12,802

Projected benefit obligation, end of year
$
331,934

 
$
269,382

 
$
83,097

 
$
76,565

Change in plan assets
 
 
 
 
 
 
 
Fair value of plan assets, beginning of year
176,172

 
156,990

 
18,149

 
14,295

Plan assets acquired in business combination
44,258

 
—

 
10,563

 
—

Actual return (loss) on plan assets
17,221

 
(5,657
)
 
1,854

 
20

Employer contributions
21,775

 
7,975

 
2,317

 
3,028

Benefits paid
(15,845
)
 
(12,589
)
 
(2,683
)
 
(2,036
)
Gain (loss) on foreign exchange
(7,212
)
 
29,453

 
(1,061
)
 
2,842

Fair value of plan assets, end of year
$
236,369

 
$
176,172

 
$
29,139

 
$
18,149

Unfunded status
$
(95,565
)
 
$
(93,210
)
 
$
(53,958
)
 
$
(58,416
)
Amounts recognized in the consolidated balance sheets consists of:
 
 
 
 
 
 
 
Current liabilities
(436
)
 
(470
)
 
(1,242
)
 
(1,062
)
Non-current liabilities
(95,129
)
 
(92,740
)
 
(52,716
)
 
(57,354
)
Net amount recognized
$
(95,565
)
 
$
(93,210
)
 
$
(53,958
)
 
$
(58,416
)

Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

10.
Pension and other post-employment benefits (continued)
(a)
Net pension and OPEB obligation (continued)
The accumulated benefit obligation for the pension plans was $317,025 and $251,932 as of December 31, 2016 and 2015, respectively.
During 2016 and 2015, the Company permanently froze the accrual of retirement benefits for participants under existing plans. Subsequent to the effective date, these employees began accruing benefits under the Company’s cash balance plan. The plan amendments resulted in a decrease to the projected benefit obligation of U.S.$2,217 (2015 -$3,941) which is recorded as a prior service credit in OCI. In conjunction with the plan amendments, the assets and projected benefit obligations of amended plans were revalued at the closest month-end date which resulted in an actuarial loss of U.S.$8,204 (2015 gain - U.S.$1,998) recorded in OCI.
Change in AOCI (before tax)
Pension
 
OPEB
 
Actuarial losses (gains)
 
Past service gains
 
Actuarial losses (gains)
 
Past service gains
Balance, January 1, 2015
$
29,314

 
$
(563
)
 
$
5,896

 
$
—

Additions to AOCI
1,505

 
(4,864
)
 
(7,554
)
 
—

Amortization in current period
(1,358
)
 
457

 
(680
)
 
—

Balance at December 31, 2015
$
29,461

 
$
(4,970
)
 
$
(2,338
)
 
$
—

Additions to AOCI
4,479

 
(2,754
)
 
(3,242
)
 
(1,235
)
Amortization in current period
(1,965
)
 
765

 
(80
)
 
347

Balance at December 31, 2016
$
31,975

 
$
(6,959
)
 
$
(5,660
)
 
$
(888
)
Expected amortization in 2017
$
(1,437
)
 
$
836

 
$
545

 
$
—

(b)
Assumptions
Weighted average assumptions used to determine net benefit cost for 2016 and 2015 were as follows: 
 
Pension benefits
 
OPEB
 
2016
 
2015
 
2016
 
2015
Discount rate
4.16
%
 
3.71
%
 
4.23
%
 
3.82
%
Expected return on assets
6.41
%
 
6.44
%
 
5.50
%
 
5.50
%
Rate of compensation increase
3.00
%
 
3.01
%
 
N/A

 
N/A

Health care cost trend rate
 
 
 
 
 
 
 
Before Age 65
 
 
 
 
6.50
%
 
7.00
%
Age 65 and after
 
 
 
 
6.50
%
 
7.00
%
Assumed Ultimate Medical Inflation Rate
 
 
 
 
4.75
%
 
5.00
%
Year in which Ultimate Rate is reached
 
 
 
 
2023

 
2019










Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

10.
Pension and other post-employment benefits (continued)
(b)
Assumptions (continued)
Weighted average assumptions used to determine net benefit obligation for 2016 and 2015 were as follows: 
 
Pension benefits
 
OPEB
 
2016
 
2015
 
2016
 
2015
Discount rate
3.95
%
 
4.16
%
 
4.04
%
 
4.23
%
Rate of compensation increase
3.00
%
 
3.00
%
 
N/A

 
N/A

Health care cost trend rate
 
 
 
 
 
 
 
Before Age 65
 
 
 
 
6.25
%
 
6.50
%
Age 65 and after
 
 
 
 
6.25
%
 
6.50
%
Assumed Ultimate Medical Inflation Rate
 
 
 
 
4.75
%
 
4.75
%
Year in which Ultimate Rate is reached
 
 
 
 
2023

 
2023

The mortality assumption for December 31, 2016 was updated to the projected generationally scale MP-2016, adjusted to reflect the ultimate improvement rates in the 2016 Social Security Administration intermediate assumptions.
In selecting an assumed discount rate, the Company uses a modeling process that involves selecting a portfolio of high-quality corporate debt issuances (AA- or better) whose cash flows (via coupons or maturities) match the timing and amount of the Company’s expected future benefit payments. The Company considers the results of this modeling process, as well as overall rates of return on high-quality corporate bonds and changes in such rates over time, to determine its assumed discount rate.
The rate of return assumptions are based on projected long-term market returns for the various asset classes in which the plans are invested, weighted by the target asset allocations.
The effect of a one percent change in the assumed health care cost trend rate (“HCCTR”) for 2016 is as follows: 
 
2016
Effect of a 1 percentage point increase in the HCCTR on:
 
Year-end benefit obligation
$
11,343

Total service and interest cost
1,019

Effect of a 1 percentage point decrease in the HCCTR on:
 
Year-end benefit obligation
$
(9,430
)
Total service and interest cost
(846
)
(c)
Benefit costs
The following table lists the components of net benefit costs for the pension plans and OPEB recorded as part of operating expenses in the consolidated statements of operations. The employee benefit costs related to businesses acquired are recorded in the consolidated statements of operations from the date of acquisition.
 
Pension benefits
 
OPEB
 
2016
 
2015
 
2016
 
2015
Service cost
$
8,435

 
$
6,663

 
$
2,916

 
$
3,093

Interest cost
13,029

 
9,642

 
3,525

 
2,914

Expected return on plan assets
(14,854
)
 
(11,989
)
 
(1,265
)
 
(713
)
Amortization of net actuarial loss
1,965

 
1,398

 
80

 
510

Amortization of prior service credits
(765
)
 
(471
)
 
(347
)
 
—

Net benefit cost
$
7,810

 
$
5,243

 
$
4,909

 
$
5,804


Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

10.
Pension and other post-employment benefits (continued)
(d)
Plan assets
The Company’s investment strategy for its pension and post-employment plan assets is to maintain a diversified portfolio of assets with the primary goal of meeting long-term cash requirements as they become due.
The Company’s target asset allocation is as follows:
Asset Class
 
Target (%)
 
Range (%)
Equity securities
 
72
%
 
49% - 79%

Debt securities
 
28
%
 
21% - 51%

Other
 
—
%
 
—
%
The fair values of investments as of December 31, 2016, by asset category, are as follows:
Asset Class
 
Level 1
 
Percentage
Equity securities
 
192,018

 
72
%
Debt securities
 
72,664

 
28
%
Other
 
825

 
—
%
As of December 31, 2016, the funds do not hold any material investments in APUC. 
(e)
Cash flows
The Company expects to contribute $18,159 to its pension plans and $4,295 to its post-employment benefit plans in 2017.
The expected benefit payments over the next ten years are as follows: 
 
2017
 
2018
 
2019
 
2020
 
2021
 
2022-2026
Pension plan
$
20,650

 
$
17,486

 
$
18,291

 
$
19,111

 
$
20,139

 
$
116,146

OPEB
3,692

 
3,818

 
4,033

 
4,548

 
4,833

 
27,708

11.    Mandatorily redeemable Series C preferred shares
APUC has 100 redeemable Series C preferred shares issued and outstanding. 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 (fifty-three thousand and four hundred dollars per share) and have a contractual cumulative cash dividend paid quarterly until the date of redemption based on a prescribed payment schedule indexed in proportion to the increase in CPI over the term of the shares. 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.
As these shares are mandatorily redeemable for cash, they are classified as liabilities in the consolidated financial statements. 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.









Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

11.    Mandatorily redeemable Series C preferred shares (continued)
Estimated dividend payments due in the next five years and dividend and redemption payments thereafter are:
2017
$
908

2018
1,068

2019
1,282

2020
1,344

2021
1,364

Thereafter to 2031
17,150

Redemption amount
5,340

 
28,456

Less amounts representing interest
(9,996
)
 
18,460

Less current portion
(908
)
 
$
17,552

 
12.
Other assets
Other assets consist of the following:
 
2016
 
2015
Supplies and consumables inventory
$
15,568

 
$
14,977

Income tax receivable
2,951

 
3,096

Deferred financing costs
10,198

 
3,211

Other
6,136

 
4,306

 
34,853

 
25,590

Less current portion
(18,519
)
 
(18,073
)
 
$
16,334

 
$
7,517

 
13.
Other long-term liabilities and deferred credits
Other long-term liabilities consist of the following: 
 
2016
 
2015
Advances in aid of construction (a)
$
105,191

 
$
92,285

Environmental remediation obligation (b)
63,378

 
71,529

Asset retirement obligations (c)
24,822

 
17,799

Customer deposits (d)
14,881

 
15,074

Deferred income (e)
—

 
13,682

Deferred credits (f)
44,544

 
25,544

Other
22,790

 
23,843

 
275,606

 
259,756

Less current portion
(43,157
)
 
(36,621
)
 
$
232,449

 
$
223,135








Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

13.
Other long-term liabilities and deferred credits (continued)
(a)
Advances in aid of construction
The Company’s regulated utilities have various agreements with real estate development companies (the “developers”) conducting business within the Company’s utility service territories, whereby funds are advanced to the Company by the developers to assist with funding some or all of the costs of the development.
In many instances, developer advances can be subject to refund but the refund is non-interest bearing. Refunds of developer advances are made over periods generally ranging from 10 to 40 years. Advances not refunded within the prescribed period are usually not required to be repaid. After the prescribed period has lapsed, any remaining unpaid balance is transferred to contributions in aid of construction and recorded as an offsetting amount to the cost of property, plant and equipment. In 2016, $23,986 (2015 - $4,637) was transferred from advances in aid of construction to contributions in aid of construction.
(b)
Environmental remediation obligation
Prior to their acquisition by the Company, EnergyNorth Gas, Granite State Electric and New England Gas Systems 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 agency with authority for each of the respective sites.
The Company estimates the remaining undiscounted, unescalated cost of these MGP-related environmental cleanup activities will be $76,853 (2015 - $78,495) which at discount rates ranging from 3.9% to 4.7% represents the recorded accrual of $63,378 as of December 31, 2016 (2015 - $71,529). Approximately $27,976 is expected to be incurred over the next three years with the balance of cash flows to be incurred over the following 28 years.
Changes in the environmental remediation obligation are as follows:
 
2016
 
2015
Opening Balance
$
71,529

 
$
70,072

  Remediation activities
(1,389
)
 
(10,621
)
  Accretion
2,464

 
2,147

  Changes in cash flow estimates
2,088

 
3,171

  Revision in assumptions
(9,101
)
 
(5,843
)
  Foreign exchange rate adjustment
(2,213
)
 
12,603

Closing Balance
$
63,378

 
$
71,529

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, as of December 31, 2016, the Company has reflected a regulatory asset of $104,160 (2015 - $116,747) for the MGP and related sites (note 7(a)).
(c)
Asset retirement obligations
Asset retirement obligations mainly relate to legal requirements to: (i) remove wind farm facilities upon termination of land leases; (ii) cut (disconnect from the distribution system), purge (cleanup of natural gas and PCB contaminants) and cap gas mains within the gas distribution and transmission system when mains are retired in place, or sections of gas main are removed from the pipeline system; (iii) clean and remove storage tanks containing waste oil and other waste contaminants; and (iv) remove asbestos upon major renovation or demolition of structures and facilities.  During the year, APUC recorded additional asset retirement obligations for renewable generation facilities being constructed of $393 (2015 - $506), changes in estimates of $1,022 (2015 - $nil) and accretion expense of $1,055 (2015 - $854).
(d)
Customer deposits
Customer deposits result from the Company’s obligation by state regulators to collect a deposit from customers of its facilities under certain circumstances when services are connected. The deposits are refundable as allowed under the facilities’ regulatory agreement.  


Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

13.
Other long-term liabilities and deferred credits (continued)
(e)
Deferred income
Proceeds received from insurance in advance of repairs, rates collected subject to dispute and other similar proceeds are deferred until they are virtually certain of being realized.
(f)
Deferred credits
Deferred credits include unresolved contingent consideration related to prior acquisitions which are expected to be paid and deferred tax credits (note 20).
14.
Convertible Unsecured Subordinated Debentures
    
Maturity date
March 31, 2026

Interest rate
5.00
%
Conversion price per share
$
10.60

Carrying value at December 31, 2015
$
—

Receipt of initial instalment, net of deferred financing costs
357,694

Amortization of deferred financing costs
925

Carrying value at December 31, 2016
$
358,619

Face value at December 31, 2016
$
382,950

On March 1, 2016, the Company completed the sale of $1,000,000 aggregate principal amount of 5.0% convertible debentures. On March 9, 2016, the underwriters exercised their option to purchase $150,000 additional convertible debentures bringing the total amount of the offering to $1,150,000.
The convertible debentures were sold on an instalment basis at a price of $1,000 principal amount of debenture, of which $333 was received on closing of the debenture offering and the remaining $667 (the “Final Instalment”) is receivable on a date (“Final Instalment Date”) to be fixed following satisfaction of conditions precedent to the closing of the acquisition of Empire (note 3(a)). The proceeds received from the initial instalment were $382,950. The Company incurred deferred financing costs of $25,255, which are being amortized to interest expense over 10 years, the contractual term of the convertible debentures, using the effective interest rate method.
The convertible debentures represented by the initial instalment receipt are classified as a non-current liability on the consolidated balance sheets as settlement in cash is not expected to occur within 12 months. The convertible debentures mature on March 31, 2026 and bear interest at an annual rate of 5% per $1,000 principal amount of convertible debentures until and including the Final Instalment Date, after which the interest rate will be 0%. The interest expense recorded is $48,205 (2015 - $nil).
The Final Instalment Date took place subsequent to year-end, on February 2, 2017. The proceeds received from the Final instalment were $767,050, before financing costs of $23,000. As the Final Instalment Date occurred prior to the first anniversary of the closing of the debenture offering, holders of the convertible debentures who paid the final instalment by February 2, 2017 received, in addition to the payment of accrued and unpaid interest, a make-whole payment, representing the interest that would have accrued from the day following the Final Instalment Date up to and including March 1, 2017.
APUC may issue up to 108,490,566 common shares upon conversion of the outstanding debentures. As at March 1, 2017, a total of 107,517,895 common shares of the company were issued, representing conversion into common shares of more than 99.1% of the convertible debentures.
After the Final Instalment Date, any debentures not converted into common shares may be redeemed by the Company at a price equal to their principal amount plus any unpaid interest, which accrued prior to and including the Final Instalment Date. At maturity, the Company will have the right to pay the principal amount due in cash or in common shares. In the case of common shares, such shares will be valued at 95% of their weighted average trading price on the Toronto Stock Exchange for the 20 consecutive trading days ending five trading days preceding the maturity date.

Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

15.
Shareholders’ capital
(a)
Common shares
Number of common shares: 
 
 
2016
 
2015
Common shares, beginning of year
 
255,869,419

 
238,149,468

Public offering (i) and subscription receipts (ii)
 
12,938,457

 
14,355,000

Dividend reinvestment plan (iii)
 
2,322,618

 
3,230,697

Exercise of share-based awards (c)
 
2,956,524

 
134,254

Common shares, end of year
 
274,087,018

 
255,869,419

Authorized
APUC is authorized to issue an unlimited number of common shares. The holders of the common shares are entitled to dividends if, as and when declared by the Board of Directors (the “Board”); to one vote per share at meetings of the holders of common shares; and upon liquidation, dissolution or winding up of APUC to receive pro rata the remaining property and assets of APUC, subject to the rights of any shares having priority over the common shares.
The Company has a shareholders’ rights plan (the “Rights Plan”) which expires in 2019. Under the Rights Plan, one right is issued with each issued share of the Company. The rights remain attached to the shares and are not exercisable or separable unless one or more certain specified events occur. If a person or group acting in concert acquires 20 percent or more of the outstanding shares (subject to certain exceptions) of the Company, the rights will entitle the holders thereof (other than the acquiring person or group) to purchase shares at a 50 percent discount from the then current market price. The rights provided under the Rights Plan are not triggered by any person making a “Permitted Bid”, as defined in the Rights Plan.
(i)Public offering
In December 2015, APUC issued 14,355,000 common shares at $10.45 per share pursuant to a public offering for proceeds of $150,010 before issuance costs of $6,735 or $5,023 net of taxes.
(ii)
Subscription receipts
On December 29, 2014, the Company received total proceeds of $77,503 from the issuance to Emera Inc. (“Emera”) of 8,708,170 subscription receipts at a price of $8.90 per share in connection with the Odell SponsorCo investment (note 8(c)). Effective June 30, 2016, Emera converted the subscription receipts for no additional consideration on a one-for-one basis into common shares and received 661,693 additional common shares in lieu of dividends declared during the holding period.
On December 29, 2014, the Company received total proceeds of $33,000 from the issuance to Emera of 3,316,583 subscription receipts at a price of $9.95 per share in connection with the Park Water System acquisition (note 3(e)). Effective June 30, 2016, Emera converted the subscription receipts for no additional consideration on a one-for-one basis into common shares and received 252,011 additional common shares in lieu of dividends declared during the holding period.
(iii)
Dividend reinvestment plan
The Company has a common shareholder dividend reinvestment plan, which provides an opportunity for shareholders to reinvest dividends for the purpose of purchasing common shares. Additional common shares acquired through the reinvestment of cash dividends are purchased in the open market or are issued by APUC at a discount of up to 5% from the average market price, all as determined by the Company from time to time. Subsequent to year-end, APUC issued an additional 823,738 common shares under the dividend reinvestment plan.





Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

15.
Shareholders’ capital (Continued)
(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.
The Company has the following Series A and Series D preferred shares issued and outstanding as at December 31, 2016 and 2015:
Preferred shares
Number of shares
 
Price per share
 
Carrying amount
Series A
4,800,000

 
$
25

 
$
116,546

Series D
4,000,000

 
$
25

 
97,259

 
 
 
 
 
$
213,805

The holders of Series A and Series D preferred shares are entitled to receive fixed cumulative preferential dividends as and when declared by the Board at an annual amount of $1.125 and $1.25 per share, respectively, for each year up to, but excluding December 31, 2018 and March 31, 2019, respectively. The Series A and Series D dividend rate will reset on those dates and every five years thereafter at a rate equal to the then five-year Government of Canada bond yield plus 2.94% and 3.28%, respectively. The Series A and Series D preferred shares are redeemable at $25 per share at the option of the Company on December 31, 2018 and March 31, 2019, respectively, and every fifth year thereafter.
The holders of Series A and Series D preferred shares have the right to convert their shares into cumulative floating rate preferred shares, Series B and Series E, respectively, subject to certain conditions, on December 31, 2018 and March 31, 2019, respectively, and every fifth year thereafter. The Series B and Series E preferred shares will be entitled to receive quarterly floating-rate cumulative dividends, as and when declared by the Board, at a rate equal to the then ninety-day Government of Canada treasury bill yield plus 2.94% and 3.28%, respectively. The holders of Series B and Series E preferred shares will have the right to convert their shares back into Series A and Series D preferred shares on December 31, 2018 and March 31, 2019, respectively and every fifth year thereafter. The Series A, Series B, Series D and Series E preferred shares do not have a fixed maturity date and are not redeemable at the option of the holders thereof.
The Company has 100 redeemable Series C preferred shares issued and outstanding. The mandatorily redeemable Series C preferred shares are recorded as a liability on the consolidated balance sheets (note 11).
(c)
Share-based compensation
For the year ended December 31, 2016, APUC recorded $5,675 (2015 - $5,330) in total share-based compensation expense detailed as follows: 
 
2016
 
2015
Share options
$
3,006

 
$
2,742

Directors deferred share units
683

 
404

Employee share purchase
238

 
158

Performance share units
1,748

 
2,026

Total share-based compensation
$
5,675

 
$
5,330

The compensation expense is recorded as part of administrative expenses in the consolidated statements of operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.
As of December 31, 2016, total unrecognized compensation costs related to non-vested options and PSUs were $3,221 and $2,221, respectively, and are expected to be recognized over a period of 1.77 and 1.74 years, respectively.




Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

15.
Shareholders’ capital (continued)
(c)
Share-based compensation (continued)
(i)
Share option plan
The Company’s share option plan (the “Plan”) permits the grant of share options to key officers, directors, employees and selected service providers. The aggregate number of shares that may be reserved for issuance under the Plan must not exceed 8% of the number of shares outstanding at the time the options are granted.
The number of shares subject to each option, the option price, the expiration date, the vesting and other terms and conditions relating to each option shall be determined by the Board from time to time. Dividends on the underlying shares do not accumulate during the vesting period. Option holders may elect to surrender any portion of the vested options which is then exercisable in exchange for the “In-the-Money Amount”. In accordance with the Plan, the “In-The-Money Amount” represents the excess, if any, of the market price of a share at such time over the option price, in each case such “In-the-Money Amount” being payable by the Company in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards.
In the case of qualified retirement, the Board may accelerate the vesting of the unvested options then held by the optionee at the Board’s discretion. All vested options may be exercised within ninety days after retirement. In the case of death, the options vest immediately and the period over which the options can be exercised is one year. In the case of disability, options continue to vest and be exercisable in accordance with the terms of the grant and the provisions of the plan. Employees have up to thirty days to exercise vested options upon resignation or termination.
In 2016, the shareholders of APUC approved a provision whereby in the event that the Company restates its financial results, any unpaid or unexercised options may be cancelled at the discretion of the Board (or the compensation committee of the Board (“Compensation Committee”)) in accordance with the terms of the Company's clawback policy.
The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on a straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date. The Company determines the fair value of options granted using the Black-Scholes option-pricing model. The risk-free interest rate is based on the zero-coupon Canada Government bond with a similar term to the expected life of the options at the grant date.  Expected volatility was estimated based on the adjusted historical volatility of the Company’s shares.  The expected life was estimated to equal the contractual life of the options. The dividend yield rate was based upon recent historical dividends paid on APUC shares.
The following assumptions were used in determining the fair value of share options granted: 
 
2016
 
2015
Risk-free interest rate
0.9
%
 
1.3
%
Expected volatility
23
%
 
38
%
Expected dividend yield
4.5
%
 
4.0
%
Expected life
5.50 years

 
8 years

Weighted average grant date fair value per option
$
1.26

 
$
2.45













Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

15.
Shareholders’ capital (continued)
(c)
Share-based compensation (continued)
(i)
Share option plan (continued)
Share option activity during the years is as follows: 
 
Number of
awards
 
Weighted
average
exercise
price
 
Weighted
average
remaining
contractual
term
(years)
 
Aggregate
intrinsic
value
Balance at January 1, 2015
5,537,127

 
$
6.09

 
4.96
 
$
19,648

Granted
1,627,525

 
9.75

 
8.00
 


Balance at December 31, 2015
7,164,652

 
$
6.92

 
4.74
 
$
28,561

Granted
2,596,025

 
10.86

 
8.00
 


Exercised
(3,715,663
)
 
5.25

 
2.06
 
20,790

Balance at December 31, 2016
6,045,014

 
$
9.64

 
6.27
 
$
10,595

Exercisable at December 31, 2016
2,120,539

 
$
8.36

 
5.16
 
$
6,420

(ii)
Employee share purchase plan
Under the Company’s employee share purchase plan (“ESPP”), eligible employees may have a portion of their earnings withheld to be used to purchase the Company’s common shares. The Company will match (a) 20% of the employee contribution amount for the first five thousand dollars per employee contributed annually and 10% of the employee contribution amount for contributions over five thousand dollars up to ten thousand dollars annually, for Canadian employees, and (b) 15% of the employee contribution amount for the first fifteen thousand dollar per employee contributed annually, for U.S. employees. Common shares purchased through the Company match portion shall not be eligible for sale by the participant for a period of one year following the contribution date on which such shares were acquired. At the Company’s option, the common shares may be (i) issued to participants from treasury at the average share price or (ii) acquired on behalf of participants by purchases through the facilities of the TSX by an independent broker. The aggregate number of common shares reserved for issuance from treasury by APUC under the ESPP shall not exceed 2,000,000 common shares.
The Company uses the fair value based method to measure the compensation expense related to the Company’s contribution. For the year ended December 31, 2016, a total of 144,264 common shares (2015 - 111,355) were issued to employees under the ESPP.
(iii)
Directors deferred share units
Under the Company’s Deferred Share Unit Plan, non-employee directors of the Company may elect annually to receive all or any portion of their compensation in DSUs in lieu of cash compensation. Directors’ fees are paid on a quarterly basis and at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one of the Company’s common shares. Dividends accumulate in the DSU account and are converted to DSUs based on the market value of the shares on that date. DSUs cannot be redeemed until the director retires, resigns, or otherwise leaves the Board. The DSUs provide for settlement in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards. As of December 31, 2016, 224,663 (2015 - 157,471) DSUs were outstanding pursuant to the election of the directors to defer a percentage of their director’s fee in the form of DSUs. The aggregate number of common shares reserved for issuance from treasury by APUC under the DSU Plan shall not exceed 1,000,000 common shares.





Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

15.
Shareholders’ capital (continued)
(c)
Share-based compensation (continued)
(iv)
Performance share units
The Company offers a PSU plan to its employees as part of the Company’s long-term incentive program. PSUs are granted annually for three-year overlapping performance cycles. PSUs vest at the end of the three-year cycle and will be calculated based on established performance criteria. At the end of the three-year performance periods, the number of common shares issued can range from 0% to 197.5% of the number of PSUs granted. Dividends accumulating during the vesting period are converted to PSUs based on the market value of the shares on that date and are recorded in equity as the dividends are declared. None of these PSUs have voting rights. Any PSUs not vested at the end of a performance period will expire. The PSUs provide for settlement in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards.
Compensation expense associated with PSUs is recognized rateably over the performance period and assumes that performance goals will be achieved at 100%. If goals met differ, compensation cost recognized is adjusted to reflect the performance conditions achieved.
A summary of the PSUs follows: 
 
Number of awards
 
Weighted
average
grant-date
fair value
 
Weighted
average
remaining
contractual
term (years)
 
Aggregate
intrinsic
value
Balance at January 1, 2015
440,086

 
$
6.57

 
1.81

 
$
4,242

Granted, including dividends
212,250

 
9.72

 
2.62

 
—

Exercised
(41,131
)
 
6.86

 
—

 
381

Forfeited
(47,089
)
 
8.30

 
—

 
—

Balance at December 31, 2015
564,116

 
$
7.59

 
1.63

 
$
6,155

Granted, including dividends
219,315

 
11.62

 
2.00

 
—

Exercised
(181,875
)
 
8.29

 
—

 
2,115

Forfeited
(22,568
)
 
9.64

 
—

 
—

Balance at December 31, 2016
578,988

 
$
9.82

 
1.74

 
$
6,595

Exercisable at December 31, 2016
215,790

 
$
8.22

 
—

 
$
2,458

 

Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

16.Accumulated Other comprehensive income (loss)
AOCI consists of the following balances, net of tax:
    
 
Foreign currency cumulative translation
 
Unrealized gain on cash flow hedges
 
Net change on available-for-sale investments
 
Pension and post-employment actuarial changes
 
Total
Balance, January 1, 2015
$
32,496

 
$
23,164

 
$
1

 
$
(21,448
)
 
$
34,213

OCI (loss) before reclassifications
228,861

 
21,896

 
(73
)
 
6,487

 
257,171

Amounts reclassified
—

 
(5,731
)
 
—

 
1,084

 
(4,647
)
Net current period OCI
228,861

 
16,165

 
(73
)
 
7,571

 
252,524

Balance, December 31, 2015
$
261,357

 
$
39,329

 
$
(72
)
 
$
(13,877
)
 
$
286,737

OCI before reclassifications
(61,029
)
 
34,308

 
213

 
1,648

 
(24,860
)
Amounts reclassified
—

 
(7,554
)
 
—

 
604

 
(6,950
)
Net current period OCI
$
(61,029
)
 
$
26,754

 
$
213

 
$
2,252

 
$
(31,810
)
Balance, December 31, 2016
$
200,328

 
$
66,083

 
$
141

 
$
(11,625
)
 
$
254,927

Amounts reclassified from AOCI for unrealized gain (loss) on cash flow hedges affected revenue from non-regulated energy sales while those for pension and post-employment actuarial changes affected administrative expenses.
17.
Dividends
All dividends of the Company are made on a discretionary basis as determined by the Board. The Company declares and pays the dividend on its commons shares in U.S. dollars. Dividends declared in Canadian equivalent dollars during the year were as follows:
 
2016
 
2015
 
Dividend
 
Dividend per share
 
Dividend
 
Dividend per share
Common shares
$
149,158

 
$
0.5452

 
$
124,831

 
$
0.4867

Series A preferred shares
$
5,400

 
$
1.1250

 
$
5,400

 
$
1.1250

Series D preferred shares
$
5,000

 
$
1.2500

 
$
5,000

 
$
1.2500

18.
Related party transactions
Emera Inc.
A member of the Board of APUC is an executive at Emera. During 2016, the Energy Services Business sold electricity to Maine Public Service Company, and Bangor Hydro subsidiaries of Emera, amounting to U.S.$10,185 (2015 - U.S.$6,658). During 2016, Liberty Utilities purchased natural gas amounting to U.S. $3,939 (2015 - U.S.$2,292) from Emera for its gas utility customers. Both the sale of electricity to Emera and the purchase of natural gas from Emera followed a public tender process the results of which were approved by the regulator in the relevant jurisdiction. On May 13, 2016, a subsidiary of the Company and Emera Utility Services Inc. entered into a design, engineering, supply and construction agreement for the Tinker transmission upgrade project. The total cost of the contract is estimated at $8,797 and is expected to be completed in 2017. The contract followed a market based request for proposal process. On October 14, 2016, APUC paid $680 to Emera as reimbursement for professional services incurred and accrued in 2014.
There was U.S.$757 included in accruals in 2016 (2015 - U.S.$491) related to these transactions at the end of the year.


Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

18.
Related party transactions (continued)
Equity-method investments
The Company provides administrative services to its equity-method investees and is reimbursed for incurred costs. To that effect, the Company charged its equity-method investees $3,313 (2015 - $2,021) during the year.
Trafalgar
The Company owned debt on seven hydroelectric facilities owned by Trafalgar Power Inc. and an affiliate ("Trafalgar"). In 1997, Trafalgar went into default under its debt obligations and an entity partially and indirectly owned by Senior Executives (the "Related Entity"), moved to foreclose on the assets on behalf of the Company. Subsequent to the foreclosure action, Trafalgar went into bankruptcy. APUC and the Related Entity have jointly pursued litigation and bankruptcy proceedings with Trafalgar since 2002.
In 2003 and 2004, the Company reimbursed the Related Entity $1,000 of the approximately $2,000 in third-party legal fees it had initially funded and APUC agreed to fund future legal fees and other liabilities. It was agreed that any net proceeds from the litigation and bankruptcy proceedings would be shared proportionally to the quantum of net legal costs funded by each party.
On June 30, 2016, the Company received U.S. $10,083 in proceeds from the settlement of this matter and, subsequent to quarter-end, paid U.S. $2,900 to the Related Entity as its proportionate share. The gain to APUC, net of legal and other liabilities, of approximately U.S. $6,600 was recorded in the second quarter of 2016.
The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.
19.
Non-controlling interests and Redeemable non-controlling interest
Net loss attributable to non-controlling interests consists of the following:
 
2016
 
2015
HLBV and other adjustments attributable to:
 
 
 
Non-controlling interest -Class A partnership units (i)
$
(35,451
)
 
$
(30,371
)
Non-controlling interest -redeemable Class A partnership units (i)
(4,952
)
 
(3,571
)
Other net earnings attributable to non-controlling interests
1,853

 
1,966

Net effect of non-controlling interests
$
(38,550
)
 
$
(31,976
)
(i)
The non-controlling Class A membership equity investors (“Class A partnership units”) in the Company's U.S. wind power and solar power generating facilities are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. The share of earnings attributable to the non-controlling interest holders in these subsidiaries is calculated using the HLBV method of accounting as described in note 1(q).
As of December 31, 2016, non-controlling interests of $562,358 (2015 - $356,800) includes Class A partnership units held by tax equity investors in certain U.S. wind power and solar generating facilities of $561,308 (2015 - $355,842) and other non-controlling interests of $1,050 (2015 - $958).
Non-controlling interests in subsidiaries that are redeemable upon the occurrence of uncertain events not solely within APUC’s control are classified as temporary equity on the consolidated balance sheets. The redeemable non-controlling interests in subsidiaries balance is determined using the hypothetical liquidation at book value method subsequent to initial recognition, however, if the redemption amount is probable or currently redeemable, the Company records the instruments at their redemption value. Redemption is not considered probable as of December 31, 2016.







Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

19.
Non-controlling interests and Redeemable non-controlling interest (continued)
Changes in redeemable non-controlling interest are as follows:
 
2016
 
2015
Opening balance
$
25,751

 
$
12,146

Net loss attributable to redeemable non-controlling interest
(4,952
)
 
(3,571
)
Contributions from redeemable non-controlling interests (notes 3(b) and 3(h))
10,171

 
15,222

Dividends declared and distributions to redeemable non-controlling interest
(590
)
 
(309
)
Foreign exchange
(946
)
 
2,263

Closing balance
$
29,434

 
$
25,751

20.
Income taxes
The provision for income taxes in the consolidated statements of operations represents an effective tax rate different than the Canadian enacted statutory rate of 26.5% (2015 - 26.5%). The differences are as follows:
 
2016
 
2015
Expected income tax expense at Canadian statutory rate
$
34,317

 
$
34,516

Increase (decrease) resulting from:

 

Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates
(11,363
)
 
(5,943
)
Non-controlling interests share of income
13,973

 
12,511

Allowance for equity funds used during construction
(1,100
)
 
(935
)
Capital gain rate differential
(3,612
)
 
(961
)
Non-deductible acquisition costs
1,996

 
365

Change in valuation allowance
2,841

 
109

Recognition of deferred credit
—

 
(2,448
)
Adjustment relating to prior periods
(711
)
 
2,431

CRA Settlement
—

 
2,709

Other
795

 
1,359

Income tax expense
$
37,136

 
$
43,713

For the years ended December 31, 2016 and 2015, earnings from continuing operations before income taxes consist of the following:
 
2016
 
2015
Canadian operations
$
29

 
$
28,481

U.S. operations
129,481

 
101,768

 
$
129,510

 
$
130,249











Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

20.
Income taxes (continued)
Income tax expense (recovery) attributable to income (loss) consists of: 
 
Current
 
Deferred
 
Total
Year ended December 31, 2016
 
 
 
 
 
Canada
$
7,533

 
$
(10,501
)
 
$
(2,968
)
United States
928

 
39,176

 
40,104

 
$
8,461

 
$
28,675

 
$
37,136

Year ended December 31, 2015
 
 
 
 
 
Canada
$
5,272

 
$
1,959

 
$
7,231

United States
2,038

 
34,444

 
36,482

 
$
7,310

 
$
36,403

 
$
43,713

The tax effect of temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases that give rise to significant portions of the deferred tax assets and deferred tax liabilities as of December 31, 2016 and 2015 are presented below:
 
2016
 
2015
Deferred tax assets:
 
 
 
Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs
$
458,508

 
$
399,754

Pension and OPEB
57,751

 
57,969

Acquisition-related costs
4,773

 
6,035

Environmental obligation
25,683

 
28,230

Reserves and other non-deductible costs
11,390

 
2,503

Regulatory liabilities
76,315

 
68,166

Other
15,302

 
5,404

Total deferred income tax assets
649,722

 
568,061

Less valuation allowance
(21,656
)
 
(17,478
)
Total deferred tax assets
628,066

 
550,583

Deferred tax liabilities:
 
 
 
Property, plant and equipment
(562,124
)
 
(444,385
)
Intangible assets
(9,197
)
 
(2,760
)
Outside basis in partnership
(187,717
)
 
(164,692
)
Regulatory accounts
(108,506
)
 
(96,436
)
Financial derivatives
(17,649
)
 
—

Other
(1,007
)
 
—

Total deferred tax liabilities
(886,200
)
 
(708,273
)
Net deferred tax liabilities
$
(258,134
)
 
$
(157,690
)
Consolidated Balance Sheets Classification:
 
 
 
  Deferred tax assets
$
30,005

 
$
18,109

  Deferred tax liabilities
(288,139
)
 
$
(175,799
)
Net deferred tax liabilities
$
(258,134
)
 
$
(157,690
)






Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

20.
Income taxes (continued)
The valuation allowance for deferred tax assets as at December 31, 2016 was $21,656 (2015 - $17,478). The valuation allowance primarily relates to operating losses that, in the judgment of management, are not more likely than not to be realized. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities (including the impact of available carryback and carryforward periods), projected future taxable income, and tax-planning strategies in making this assessment.
As of December 31, 2016, the Company had non-capital losses carried forward available to reduce future year’s taxable income, which expire as follows: 
Year of expiry
Non-capital loss carryforwards
2020 and onwards
$
1,116,631

On June 26, 2015, the Company entered into an agreement with the Canada Revenue Agency (“CRA”) regarding CRA’s proposal to reassess APUC’s 2009 through 2013 income tax filings in relation to a unit exchange transaction that occurred on October 27, 2009. The agreement resulted in a $16,042 reduction in the APUC’s deferred tax assets and a proportional reduction of $13,333 in its deferred credits (note 13(f)). Consequently, the Company’s results for 2015 reflect a $2,709 net non-cash charge to deferred income tax expense.
The Company has provided for deferred income taxes for the estimated tax cost of distributed earnings of its subsidiaries. Deferred income taxes have not been provided on approximately $88,306 of undistributed earnings of certain foreign subsidiaries, as the Company has concluded that such earnings are indefinitely reinvested and should not give rise to additional tax liabilities. A determination of the amount of the unrecognized tax liability relating to the remittance of such undistributed earnings is not practicable.
21.
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 and subscription receipts outstanding (note 15 (a)(ii)). Diluted net earnings per share is computed using the weighted-average number of common shares, subscription receipts outstanding, additional shares issued subsequent to year-end under the dividend reinvestment plan, PSUs and DSUs outstanding during the year and, if dilutive, potential incremental common shares resulting from the application of the treasury stock method to outstanding share options.
The reconciliation of the net earnings and the weighted average shares used in the computation of basic and diluted earnings per share are as follows:
 
2016
 
2015
Net earnings attributable to shareholders of APUC
$
130,924

 
$
117,480

Series A Preferred shares dividend
5,400

 
5,400

Series D Preferred shares dividend
5,000

 
5,000

Net earnings attributable to common shareholders of APUC
$
120,524

 
$
107,080

Discontinued operations
—

 
(1,032
)
Net earnings attributable to common shareholders of APUC from continuing operations – Basic and Diluted
$
120,524

 
$
108,112

Weighted average number of shares
 
 
 
Basic
271,832,430

 
253,172,088

Effect of dilutive securities
2,244,602

 
3,344,632

Diluted
274,077,032

 
256,516,720

The shares potentially issuable as a result of 1,665,131 share options (2015 - 1,627,525) are excluded from this calculation as they are anti-dilutive.


Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

21.
Basic and diluted net earnings per share (continued)
The convertible debentures (note 14) are convertible into common shares at any time after the Final Instalment Date, but prior to maturity or redemption by the Company. As the Final Instalment Date occurred subsequent to year-end, on February 2, 2017, the contingency had not been met on December 31, 2016 and as such, the shares issuable upon conversion of the convertible debentures are not included in diluted earnings per share above. Beginning February 2, 2017, assuming full payment of the final instalment, 108,490,566 common shares will be included as a component of the Company’s diluted EPS. As at March 1, 2017, a total of 107,517,895 common shares of the company were issued, representing conversion into common shares of more than 99.1% of the convertible debentures.
22.
Segmented information
APUC's operations are organized across two primary North American business units consisting of the Renewable Generation Group and the Liberty Utilities Group.
The Renewable Generation Group ("Renewable Generation Group") owns and operates a diversified portfolio of non-regulated renewable and thermal electric generation utility assets; the Liberty Utilities Group ("Liberty Utilities Group") owns and operates a portfolio of regulated electric, natural gas, water distribution and wastewater collection utility systems and transmission operations.
As at December 31, 2016, APUC has three reporting segments: Generation, Transmission and Distribution.The Transmission segment is not significant and as a result is not presented separately in the tables below but grouped within Corporate.
For purposes of evaluating divisional performance, the Company allocates the realized portion of any gains or losses on financial instruments to specific divisions. The unrealized portion of any gains or losses on derivative instruments not designated in a hedging relationship is not considered in management’s evaluation of divisional performance and is therefore allocated and reported in the corporate segment. The results of operations and assets for these segments are reflected in the tables below.
 
Year ended December 31, 2016
 
Generation
 
Distribution
 
Corporate
 
Total
Revenue
$
265,949

 
$
830,069

 
$
—

 
$
1,096,018

Fuel, power and water purchased
21,260

 
274,055

 
—

 
295,315

Net revenue
244,689

 
556,014

 
—

 
800,703

Operating expenses
72,346

 
258,664

 
1,991

 
333,001

Administrative expenses
19,656

 
26,272

 
421

 
46,349

Depreciation and amortization
80,094

 
102,657

 
4,148

 
186,899

Gain on foreign exchange
—

 
—

 
(436
)
 
(436
)
Operating income (loss) from continuing operations
72,593

 
168,421

 
(6,124
)
 
234,890

Interest expense
21,847

 
50,616

 
59,129

 
131,592

Interest, dividend, equity and other income
32

 
(5,125
)
 
(5,480
)
 
(10,573
)
Other expenses (gain)
(14,403
)
 
(18,119
)
 
16,883

 
(15,639
)
Earnings (loss) before income taxes
$
65,117

 
$
141,049

 
$
(76,656
)
 
$
129,510

Property, plant and equipment
$
2,455,336

 
$
2,345,436

 
$
89,174

 
$
4,889,946

Equity-method investees
59,021

 
914

 
4,484

 
64,419

Total assets
2,771,651

 
5,343,023

 
134,786

 
8,249,460

Capital expenditures
141,420

 
235,744

 
28,579

 
405,743


Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

22.
Segmented information (continued)
 
Year ended December 31, 2015
 
Generation
 
Distribution
 
Corporate
 
Total
Revenue
$
244,751

 
$
783,104

 
$
—

 
$
1,027,855

Fuel and power purchased
27,990

 
348,883

 
—

 
376,873

Net revenue
216,761

 
434,221

 
—

 
650,982

Operating expenses
63,601

 
214,064

 
1,741

 
279,406

Administrative expenses
10,822

 
20,725

 
8,283

 
39,830

Depreciation and amortization
67,293

 
82,513

 
—

 
149,806

Gain on foreign exchange
—

 
—

 
(2,631
)
 
(2,631
)
 
75,045

 
116,919

 
(7,393
)
 
184,571

Interest expense
29,395

 
34,971

 
1,627

 
65,993

Interest, dividend and other income
(1,154
)
 
(3,974
)
 
(3,967
)
 
(9,095
)
Other expense (gain)
(5,623
)
 
391

 
2,656

 
(2,576
)
Earnings (loss) before income taxes
$
52,427

 
$
85,531

 
$
(7,709
)
 
$
130,249

Property, plant and equipment
$
1,899,103

 
$
1,890,353

 
$
87,714

 
$
3,877,170

Equity-method investees
44,638

 
769

 
7,066

 
52,473

Total assets
2,345,905

 
2,508,267

 
137,553

 
4,991,725

Capital expenditures
55,992

 
119,967

 
28,236

 
204,195

The majority of non-regulated energy sales are earned from contracts with large public utilities. The following utilities contributed more than 10% of these total revenues in either 2016 or 2015: Ontario Hydro 12% (2015 - 9%); Hydro Québec 11% (2015 - 13%); Manitoba Hydro 12% (2015 - 13%); PJM 13% (2015 - 14%); and ComEd 10% (2015 - 11%). The Company has mitigated its credit risk to the extent possible by selling energy to large utilities in various North American locations.
APUC operates in the independent power and utility industries in both Canada and the United States. Information on operations by geographic area is as follows:
 
2016
 
2015
Revenue
 
 
 
Canada
$
100,403

 
$
86,977

United States
995,615

 
940,878

 
$
1,096,018

 
$
1,027,855

Property, plant and equipment
 
 
 
Canada
$
558,271

 
$
592,598

United States
4,331,675

 
3,284,572

 
$
4,889,946

 
$
3,877,170

Intangible assets
 
 
 
Canada
$
36,611

 
$
40,186

United States
28,378

 
34,291

 
$
64,989

 
$
74,477

Revenue is attributed to the two countries based on the location of the underlying generating and utility facilities.



Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

23.Commitments and contingencies
(a)
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 financial statements. Accruals for any contingencies related to these items are recorded in the consolidated financial statements at the time it is concluded that its occurrence is probable and the related liability is estimable.
(b)
Commitments
In addition to the commitments related to the proposed acquisitions and development projects disclosed in notes 3 and 8, the following significant commitments exist as of December 31, 2016.
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
Power purchase (i)
$
63,330


$
36,622


$
37,398


$
38,822


$
38,822


$
—


$
214,994

Gas supply and service agreements (ii)
62,179


45,468


37,407


31,636


17,400


64,284


258,374

Service agreements
41,446


42,252


42,508


45,178


46,019


503,671


721,074

Capital projects
66,696


19,538


69


69


69


17


86,458

Operating leases
7,342


6,851


6,519


6,403


6,480


123,604


157,199

Total
$
240,993


$
150,731


$
123,901


$
122,108


$
108,790


$
691,576


$
1,438,099

(i)
Power purchase: APUC’s electric distribution facilities have commitments to purchase physical quantities of power for load serving requirements. The commitment amounts included in the table above are based on market prices as of December 31, 2016. However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism.
(ii)
Gas supply and service agreements: APUC’s gas distribution facilities and thermal generation facilities have commitments to purchase physical quantities of natural gas under contracts for purposes of load serving requirements and of generating power.
24.
Non-cash operating items
The changes in non-cash operating items consist of the following:
 
2016
 
2015
Accounts receivable
$
6,612

 
$
6,715

Natural gas in storage
6,877

 
3,049

Supplies and consumable inventory
692

 
(2,968
)
Income taxes receivable
145

 
(2,529
)
Prepaid expenses
(6,161
)
 
(7,833
)
Accounts payable
24,524

 
(18,261
)
Accrued liabilities
(9,454
)
 
(28,495
)
Current income tax liability
(4,552
)
 
1,820

Net regulatory assets and liabilities
(14,979
)
 
37,353

 
$
3,704

 
$
(11,149
)

Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

25.
Financial instruments
(a)
Fair value of financial instruments
2016
Carrying
amount
 
Fair
Value
 
Level 1
 
Level 2
 
Level 3
Notes receivable
$
38,183

 
$
47,933

 
$
—

 
$
47,933

 
$
—

Derivative instruments (1):
 
 
 
 
 
 
 
 
 
Energy contracts designated as a cash flow hedge
84,554

 
84,554

 
—

 
—

 
84,554

Interest rate swap designated as a hedge
48,093

 
48,093

 
—

 
48,093

 
—

Currency forward contract not designated as a hedge
17,864

 
17,864

 
—

 
17,864

 
—

Commodity contracts for regulated operations
359

 
359

 
—

 
359

 
—

Total derivative instruments
150,870

 
150,870

 
—

 
66,316

 
84,554

Total financial assets
$
189,053

 
$
198,803

 
$
—

 
$
114,249

 
$
84,554

Long-term debt
$
3,913,415

 
$
3,999,266

 
$
517,637

 
$
3,481,629

 
$
—

Convertible debentures
358,619

 
455,975

 
455,975

 
—

 
—

Preferred shares, Series C
18,460

 
18,613

 
—

 
18,613

 
—

Derivative instruments (1):
 
 
 
 
 
 
 
 
 
Cross-currency swap designated as a net investment hedge
95,404

 
95,404

 
—

 
95,404

 
—

Interest rate swap designated as a hedge
13,385

 
13,385

 
—

 
13,385

 
—

Commodity contracts for regulated operations
36

 
36

 
—

 
36

 
—

Total derivative instruments
108,825

 
108,825

 
—

 
108,825

 
—

Total financial liabilities
$
4,399,319

 
$
4,582,679

 
$
973,612

 
$
3,609,067

 
$
—

(1) Balance of $314 associated with certain weather derivatives have been excluded, as they are accounted for based on intrinsic value rather than fair value.

Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

25.
Financial instruments (continued)
(a)Fair value of financial instruments (continued)
2015
Carrying
amount
 
Fair
Value
 
Level 1
 
Level 2
 
Level 3
Notes receivable
$
119,383

 
$
126,468

 
$
—

 
$
126,468

 
$
—

Derivative instruments:
 
 
 
 
 
 
 
 
 
Energy contracts designated as a cash flow hedge
88,357

 
88,357

 
—

 
—

 
88,357

Commodity contracts for regulatory operations
4

 
4

 
—

 
4

 
—

Total derivative instruments
88,361

 
88,361

 
—

 
4

 
88,357

Total financial assets
$
207,744

 
$
214,829

 
$
—

 
$
126,472

 
$
88,357

Long-term debt
$
1,486,795

 
$
1,547,346

 
$
511,829

 
$
1,035,517

 
$
—

Preferred shares, Series C
18,527

 
17,303

 
—

 
17,303

 
—

Derivative instruments:
 
 
 
 
 
 
 
 
 
Energy contracts designated as a cash flow hedge
446

 
446

 
—

 
—

 
446

Cross-currency swap designated as a net investment hedge
101,559

 
101,559

 
—

 
101,559

 
—

Interest rate swaps designated as a hedge
9,659

 
9,659

 
—

 
9,659

 
—

Interest rate swaps not designated as a hedge
1,918

 
1,918

 
—

 
1,918

 
—

Commodity contracts for regulated operations
1,676

 
1,676

 
—

 
1,676

 
—

Total derivative instruments
115,258

 
115,258

 
—

 
114,812

 
446

Total financial liabilities
$
1,620,580

 
$
1,679,907

 
$
511,829

 
$
1,167,632

 
$
446


Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

25.
Financial instruments (continued)
(a)
Fair value of financial instruments (continued)
The Company has determined that the carrying value of its short-term financial assets and liabilities approximates fair value as of December 31, 2016 and 2015 due to the short-term maturity of these instruments.
Notes receivable fair values (level 2) 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. 
The Company’s level 2 fair value of long-term debt at fixed interest rates and Series C preferred shares has been determined using a discounted cash flow method and current interest rates.
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 Company’s level 3 instruments consist of energy contracts for electricity sales. The significant unobservable inputs used in the fair value measurement of energy contracts are the internally developed forward market prices ranging from $24.44 to $105.03 with a weighted average of $37.36 as of December 31, 2016.  The processes and methods of measurement are developed using the market knowledge of the trading operations within the Company and are derived from observable energy curves adjusted to reflect the illiquid market of the hedges and, in some cases, the variability in deliverable energy.  Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measurement. The change in the fair value of the energy contracts is detailed in notes 25(b)(ii) and 25(b)(iv).
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.
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 years ended December 31, 2016 and 2015.
(b)
Derivative instruments
Derivative instruments are recognized on the consolidated balance sheets as either assets or liabilities and measured at fair value at 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 purchases associated with its regulated gas service territories. The Company’s strategy is to minimize fluctuations in gas sale prices to regulated customers.
The following are commodity volumes, in dekatherms (“dths”) associated with the above derivative contracts:
 
2016
Financial contracts: Gas swaps
384,999

        Gas options
844,167

 
1,229,166

The accounting for these derivative instruments is subject to guidance for rate-regulated enterprises. Therefore, the fair value of these derivatives is recorded as current or long-term assets and liabilities, with offsetting positions recorded as regulatory assets and regulatory liabilities in the consolidated balance sheets. Gains or losses on the settlement of these contracts are included in the calculation of deferred gas costs (note 7(c)). 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 earnings impact.

Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

25.
Financial instruments (continued)
(b)
Derivative instruments (continued)
(i)
Commodity derivatives – regulated accounting (continued)
The following table presents the impact of the change in the fair value of the Company’s natural gas derivative contracts had on the consolidated balance sheets: 
 
 
2016
 
 
2015
Regulatory assets:
 
 
 
 
 
Gas swap contracts
U.S.
$
—

 
U.S.
$
1,058

Gas option contracts
U.S.
$
27

 
U.S.
$
154

Regulatory liabilities:
 
 
 
 
 
Gas swap contracts
U.S.
$
175

 
U.S.
$
3

Gas option contracts
U.S.
$
92

 
U.S.
$
—

(ii)
Cash flow hedges
The Company reduces the price risk on the expected future sale of power generation at Sandy Ridge, Senate and Minonk Wind Facilities by entering into the following long-term energy derivative contracts. 
Notional quantity
(MW-hrs)
 
Expiry
 
Receive average
prices (per MW-hr)
 
Pay floating price
(per MW-hr)
686,340

 
 December 2022
 
U.S. $
 
42.81

 
PJM Western HUB
2,930,009

 
 December 2022
 
U.S. $
 
30.25

 
NI HUB
3,663,549

 
 December 2027
 
U.S. $
 
36.46

 
ERCOT North HUB
On October 25, 2016, the Company entered into forward contracts to purchase U.S.$250,000 10-year U.S. Treasury bills at an interest rate of 1.8395% and U.S.$250,000 30-year U.S. Treasury bills at an interest rate of 2.5539% settling on February 13, 2017 in order to reduce the interest rate risk related to the probable issuance on that date of U.S.$500,000 bonds in relation to the acquisition of Empire (note 9(d)). The change in fair value resulted in a gain of U.S.$35,815 for the year ended December 31, 2016.
The Company is party to a 10-year forward-starting interest rate swap beginning on July 25, 2018 in order to reduce the interest rate risk related to the probable issuance on that date of a 10-year $135,000 bond. The change in fair value resulted in a loss of $3,726 for the year ended December 31, 2016 (2015 - loss of $4,974), which is recorded in OCI.
The following table summarizes OCI attributable to derivative financial instruments designated as a cash flow hedge: 
 
2016
 
2015
 
 
 
 
Effective portion of cash flow hedge, loss
$
34,355

 
$
21,932

Amortization of cash flow hedge
(47
)
 
(36
)
Gain reclassified from AOCI
(7,554
)
 
(5,731
)
OCI attributable to shareholders of APUC
$
26,754

 
$
16,165

The Company expects $10,024 of unrealized gains currently in AOCI to be reclassified into non-regulated energy sales within the next twelve months, as the underlying hedged transactions settle.

Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

25.
Financial instruments (continued)
(b)
Derivative instruments (continued)
(iii)
Foreign exchange hedge of net investment in foreign operation
The Company is exposed to currency fluctuations from its U.S. based operations. APUC manages this risk primarily through the use of natural hedges by using U.S. long-term debt to finance its U.S. operations and a combination of foreign exchange forward contracts and spot purchases. APUC only enters into foreign exchange forward contracts with major Canadian financial institutions having a credit rating of A or better, thus reducing credit risk on these forward contracts.
The Company designates the amounts drawn on the Renewable Generation Group’s revolving credit facility denominated in U.S. dollars in excess of the principal amount on the USD loans receivable from its equity investees as a hedge of the foreign currency exposure of its net investment in the Renewable Generation Group’s U.S. operations. The related foreign currency transaction gain or loss designated as, and effective as, a hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A foreign currency loss of nil for the year ended December 31, 2016 (2015 - nil) was recorded in OCI.
Concurrent with its $150,000, $200,000 and $300,000 debenture offerings in December 2012, January 2014, and January 2017, respectively, the Company entered into cross currency swaps, coterminous with the debentures, to effectively convert the Canadian dollar denominated offering into U.S. dollars. The Company designated the entire notional amount of the cross currency fixed-for-fixed interest rate swap and related short-term U.S. dollar payables created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure of its net investment in the Generation Group’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 U.S. dollar accruals that are designated as, and are effective as, a hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A gain of $2,189 (2015 - loss of $68,195) was recorded in OCI in 2016 for the December 2012 and January 2014 swaps.
(iv)
Other derivatives
The Company provides energy requirements to various customers under contracts at fixed rates. While the production from the Tinker Hydroelectric Facility 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 though 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 contract 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.
The Company is exposed to interest rate fluctuations related to certain of its floating rate debt obligation, including certain project specific debt and its revolving credit facilities, its interest rate swaps as well as interest earned on its cash on hand. The Company currently hedges some of that risk (note 25(b)(ii)).
The Company was party to an interest rate swap whereby the Company paid a fixed interest rate of 4.47% on a notional amount of $58,791 and received floating interest at 90 day CDOR. The swap expired on September 2015. This interest rate swap was not accounted for as a hedge.
The Company is exposed to foreign exchange fluctuations related to U.S dollar denominated development loans from projects accounted for as equity investments (note 8(f)). This risk was mitigated through the use of currency forward contracts to sell U.S. $38,400 for $47,225 between July 29, 2016 and September 29, 2016. As of December 31, 2016, these instruments had settled. This currency forward contract was not accounted for as a hedge.





Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

25.
Financial instruments (continued)
(b)
Derivative instruments (continued)
(iv)
Other derivatives (continued)
The Company is exposed to foreign exchange fluctuations related to the expected acquisition of the Empire shares denominated in U.S dollar (note 3(a)). This risk is mitigated through the conversion to U.S. dollars of $359,950 from the proceeds received on the initial instalment of convertible unsecured subordinated debentures (note 14) and the use of a currency forward contract to buy an amount of U.S. $567,665 for $744,050 on January 31, 2017. As of December 31, 2016, the estimated fair value of the instrument was an asset of $17,864. This currency forward contract was not accounted for as a hedge.
For derivatives that are not designated as 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 effects on the consolidated statements of operations of derivative financial instruments not designated as hedges consist of the following:
 
2016
 
2015
Change in unrealized loss (gain) on derivative financial instruments:
 
 
 
Interest rate swaps
$
—

 
$
(1,383
)
Energy derivative contracts
(426
)
 
886

Currency forward contract
(19,810
)
 
1,918

Total change in unrealized loss (gain) on derivative financial instruments
$
(20,236
)
 
$
1,421

Realized loss (gain) on derivative financial instruments:
 
 
 
Interest rate swaps
—

 
1,498

Energy derivative contracts
951

 
(579
)
Currency forward contract
(1,371
)
 
—

Total realized loss (gain) on derivative financial instruments
$
(420
)
 
$
919

Loss (gain) on derivative financial instruments not accounted for as hedges
(20,656
)
 
2,340

Ineffective portion of derivative financial instruments accounted for as hedges
1,518

 
(2,610
)
 
$
(19,138
)
 
$
(270
)
Amounts recognized in the consolidated statements of operations consist of:
 
 
 
Gain on derivative financial instruments
$
(15,849
)
 
$
(2,188
)
Loss (gain) on foreign exchange
$
(3,289
)
 
$
1,918

 
$
(19,138
)
 
$
(270
)
Effective May 1, 2016, the Company entered into a weather derivative contract as an economic hedge for revenue from its St. Leon I wind powered generating facility in the event the wind resource availability falls below a normal range. Non-exchange-traded options are accounted for using the intrinsic method. Changes in the intrinsic value of $158 in 2016 is reflected in non-regulated energy sales in the consolidated statement of operations. Premiums paid related to these weather derivative agreements are expensed over each respective contract period.
(c)
Risk management
In the normal course of business, the Company is exposed to financial risks that potentially impact its operating results. The Company employs risk management strategies with a view of mitigating these risks to the extent possible on a cost effective basis. Derivative financial instruments are used to manage certain exposures to fluctuations in exchange rates, interest rates and commodity prices. The Company does not enter into derivative financial agreements for speculative purposes.

Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

25.
Financial instruments (continued)
(c)
Risk management (continued)
This note provides disclosures relating to the nature and extent of the Company’s exposure to risks arising from financial instruments, including credit risk and liquidity risk, and how the Company manages those risks.
Credit risk
Credit risk is the risk of an unexpected loss if a customer or counterparty to a financial instrument fails to meet its contractual obligations. The Company’s financial instruments that are exposed to concentrations of credit risk are primarily cash and cash equivalents, accounts receivable, notes receivable and derivative instruments. The Company limits its exposure to credit risk with respect to cash equivalents by ensuring available cash is deposited with its senior lenders all of which have a credit rating of A or better. The Company does not consider the risk associated with the Renewable Generation Group accounts receivable to be significant as over 80% of revenue from power generation is earned from large utility customers having a credit rating of BBB or better, and revenue is generally invoiced and collected within 45 days.
The remaining revenue is primarily earned by the Liberty Utilities Group which consists of water and wastewater, electric and gas utilities in the United States. In this regard, the credit risk related to the Liberty Utilities Group accounts receivable balances of U.S.$100,417 is spread over thousands of customers. The Company has processes in place to monitor and evaluate this risk on an ongoing basis including background credit checks and security deposits from new customers. In addition, the state regulators of the Liberty Utilities Group allow for a reasonable bad debt expense to be incorporated in the rates and therefore recovered from rate payers.
As of December 31, 2016, the Company’s maximum exposure to credit risk for these financial instruments was as follows: 
 
December 31, 2016
 
Canadian $
 
US $
Cash and cash equivalents and restricted cash
$
16,874

 
$
1,578,704

Accounts receivable
14,571

 
135,660

Allowance for doubtful accounts
—

 
(5,261
)
Notes receivable
31,406

 
5,048

 
$
62,851

 
$
1,714,151

In addition, the Company continuously monitors the creditworthiness of the counterparties to its foreign exchange, interest rate, and energy derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. The counterparties consist primarily of financial institutions. This concentration of counterparties may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.
Liquidity risk
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company’s approach to managing liquidity risk is to ensure, to the extent possible, that it will always have sufficient liquidity to meet liabilities when due. As of December 31, 2016, in addition to cash on hand of $110,417 the Company had $295,915 available to be drawn on its senior debt facilities. Each of the Company’s revolving credit facilities contain covenants which may limit amounts available to be drawn.







Algonquin Power & Utilities Corp.
Unaudited Notes to the Consolidated Financial Statements
December 31, 2016 and 2015
(in thousands of Canadian dollars, except as noted and per share amounts)

25.
Financial instruments (continued)
(c)
Risk management (continued)
Liquidity risk (continued)
The Company’s liabilities mature as follows: 
 
Due less
than 1
year
 
Due 2 to 3
years
 
Due 4 to 5
years
 
Due after
5 years
 
Total
Long-term debt obligations
$
1,871,864

 
$
745,301

 
$
304,890

 
$
979,210

 
$
3,901,265

Convertible Debentures
—

—

—

 
—

 
358,619

 
358,619

Advances in aid of construction
3,140

 
—

 
—

 
102,051

 
105,191

Interest on long-term debt
194,831

 
152,976

 
110,718

 
347,700

 
806,225

Purchase obligations
398,910

 
—

 
—

 
—

 
398,910

Environmental obligation
4,043

 
23,933

 
7,123

 
41,754

 
76,853

Derivative financial instruments:
 
 
 
 
 
 
 
 
 
Cross-currency swap
4,144

 
7,660

 
49,358

 
34,242

 
95,404

Interest rate swaps
—

 
13,385

 
—

 
—

 
13,385

Energy derivative and commodity contracts
34

 
2

 
—

 
—

 
36

Other obligations
32,624

 
—

 
—

 
47,212

 
79,836

Total obligations
$
2,509,590

 
$
943,257

 
$
472,089

 
$
1,910,788

 
$
5,835,724

26.
Comparative figures
Certain of the comparative figures have been reclassified to conform to the financial statement presentation adopted in the current year.