EX-99.1 2 a2017q3-exhibit991xfinanci.htm EXHIBIT 99.1 2017 Q3 FINANCIAL STATEMENTS Exhibit
Unaudited Interim Consolidated Financial Statements of
Algonquin Power & Utilities Corp.
For the three and nine months ended September 30, 2017 and 2016



Algonquin Power & Utilities Corp.
Unaudited Interim Consolidated Balance Sheets

(thousands of Canadian dollars)
 
 
 
 
September 30, 2017
 
December 31, 2016
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
76,462

 
$
110,417

Accounts receivable, net (note 4)
225,946

 
189,658

Fuel and natural gas in storage
56,676

 
21,625

Supplies and consumables inventory
51,886

 
15,568

Regulatory assets (note 5)
74,148

 
48,440

Prepaid expenses
35,318

 
26,562

Derivative instruments (note 21)
22,786

 
76,631

Other assets (note 6)
11,824

 
2,951

 
555,046

 
491,852

Property, plant and equipment, net
7,790,421

 
4,889,946

Intangible assets, net
60,139

 
64,989

Goodwill (note 3(c))
1,173,013

 
306,641

Regulatory assets (note 5)
450,997

 
243,524

Derivative instruments (note 21)
76,421

 
74,553

Long-term investments (note 6)
110,405

 
105,433

Deferred income taxes (note 16)
59,970

 
30,005

Restricted cash
16,059

 
2,026,183

Other assets
14,266

 
16,334

 
$
10,306,737

 
$
8,249,460




Algonquin Power & Utilities Corp.
Unaudited Interim Consolidated Balance Sheets

(thousands of Canadian dollars)
 
 
 
 
September 30, 2017
 
December 31, 2016
LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
70,804

 
$
90,592

Accrued liabilities
333,330

 
308,318

Dividends payable (note 13)
56,537

 
38,973

Regulatory liabilities (note 5)
53,946

 
47,769

Long-term debt (note 7)
8,426

 
10,075

Other long-term liabilities and deferred credits (note 9)
44,842

 
43,157

Derivative instruments (note 21)
16,233

 
4,178

Other liabilities
6,009

 
3,487

 
590,127

 
546,549

Long-term debt (note 7)
4,424,023

 
3,903,340

Convertible debentures (note 10)
2,603

 
358,619

Regulatory liabilities (note 5)
216,727

 
134,965

Deferred income taxes (note 16)
876,146

 
288,139

Derivative instruments (note 21)
67,726

 
104,647

Pension and other post-employment benefits obligation (note 8)
225,058

 
147,845

Other long-term liabilities (note 9)
271,192

 
232,449

Preferred shares, Series C
17,449

 
17,552

 
6,100,924

 
5,187,556

Redeemable non-controlling interest
60,790

 
29,434

Equity:
 
 
 
Preferred shares
213,805

 
213,805

Common shares (note 11(a))
3,138,541

 
1,972,203

Additional paid-in capital
39,746

 
38,652

Deficit
(611,141
)
 
(556,024
)
Accumulated other comprehensive income (note 12)
48,025

 
254,927

Total equity attributable to shareholders of Algonquin Power & Utilities Corp.
2,828,976

 
1,923,563

Non-controlling interests (notes 3(a), 3(e) and 6(a))
725,920

 
562,358

Total equity
3,554,896

 
2,485,921

Commitments and contingencies (note 19)

 

Subsequent events (notes 7 and 22)

 

 
$
10,306,737

 
$
8,249,460

See accompanying notes to unaudited interim consolidated financial statements




Algonquin Power & Utilities Corp.
Unaudited Interim Consolidated Statements of Operations
 
(thousands of Canadian dollars, except per share amounts)
Three Months Ended September 30
 
Nine Months Ended September 30
 
2017
 
2016
 
2017
 
2016
Revenue
 
 
 
 
 
 
 
Regulated electricity distribution
$
272,616

 
$
54,245

 
$
751,409

 
$
165,548

Regulated gas distribution
59,438

 
49,372

 
340,518

 
282,307

Regulated water reclamation and distribution
47,952

 
50,978

 
141,795

 
139,385

Non-regulated energy sales
56,505

 
56,390

 
201,313

 
176,149

Other revenue
6,805

 
10,292

 
19,421

 
22,395

 
443,316

 
221,277

 
1,454,456

 
785,784

Expenses
 
 
 
 
 
 
 
Operating expenses
142,279

 
80,349

 
453,639

 
244,731

Regulated electricity purchased
81,874

 
28,352

 
222,587

 
92,284

Regulated gas purchased
13,276

 
9,291

 
116,806

 
88,880

Regulated water purchased
3,333

 
3,504

 
9,232

 
9,228

Non-regulated energy purchased
5,379

 
6,018

 
17,679

 
15,042

Administrative expenses
14,438

 
12,071

 
45,746

 
33,864

Depreciation and amortization
71,407

 
39,733

 
238,422

 
134,267

Loss (gain) on foreign exchange
2,643

 
(3,355
)
 
(1,193
)
 
(1,782
)
 
334,629

 
175,963

 
1,102,918

 
616,514

Operating income
108,687

 
45,314

 
351,538

 
169,270

Interest expense on convertible debentures and amortization of acquisition financing (notes 7(b) and 10)
—

 
16,994

 
17,638

 
39,386

Interest expense on long-term debt and others
45,613

 
17,773

 
142,580

 
53,511

Interest, dividend, equity and other income
(2,455
)
 
(1,505
)
 
(8,514
)
 
(6,435
)
Other gains
—

 
(2,343
)
 
(78
)
 
(8,555
)
Acquisition-related costs (note 3)
1,050

 
2,148

 
61,527

 
9,638

Loss (gain) on long-lived assets, net (note 19(a))
816

 
150

 
(4,007
)
 
(2,459
)
Loss (gain) on derivative financial instruments (note 21(b)(iv))
(14
)
 
(4,419
)
 
1,356

 
(2,902
)
 
45,010

 
28,798

 
210,502

 
82,184

Earnings before income taxes
63,677

 
16,516

 
141,036

 
87,086

Income tax expense (note 16)
 
 
 
 
 
 
 
Current
3,163

 
2,532

 
10,731

 
7,899

Deferred
11,620

 
(737
)
 
46,470

 
17,732

 
14,783

 
1,795

 
57,201

 
25,631

Net earnings
48,894

 
14,721

 
83,835

 
61,455

Net effect of non-controlling interests (note 15)
(10,546
)
 
(3,024
)
 
(49,279
)
 
(23,123
)
Net earnings attributable to shareholders of Algonquin Power & Utilities Corp.
$
59,440

 
$
17,745

 
$
133,114

 
$
84,578

Series A and D Preferred shares dividend (note 13)
2,600

 
2,600

 
7,800

 
7,800

Net earnings attributable to common shareholders of Algonquin Power & Utilities Corp.
$
56,840

 
$
15,145

 
$
125,314

 
$
76,778

Basic net earnings per share (note 17)
$
0.15

 
$
0.06

 
$
0.34

 
$
0.28

Diluted net earnings per share (note 17)
$
0.15

 
$
0.05

 
$
0.33

 
$
0.28

See accompanying notes to unaudited interim consolidated financial statements



Algonquin Power & Utilities Corp.
Unaudited Interim Consolidated Statements of Comprehensive Income
 
(thousands of Canadian dollars)
Three Months Ended September 30
 
Nine Months Ended September 30
 
2017
 
2016
 
2017
 
2016
Net earnings
$
48,894

 
$
14,721

 
$
83,835

 
$
61,455

Other comprehensive income:
 
 
 
 
 
 
 
Foreign currency translation adjustment, net of tax recovery of $247 and $991 (2016 - tax recovery of $nil and $nil), respectively (notes 21(b)(iii) and 21(b)(iv))
(133,578
)
 
53,659

 
(274,649
)
 
(128,367
)
Change in fair value of cash flow hedges, net of tax expense of $3,834 and $4,827 (2016 - tax expense of $4,746 and recovery of $1,341), respectively (note 21(b)(ii))
6,911

 
(19,789
)
 
8,481

 
(6,148
)
Change in unrealized appreciation in value of available-for-sale investments
—

 
(7
)
 
(26
)
 
20

Change in pension and other post-employment benefits, net of tax expense of $39 and $1,236 (tax expense of $137 and recovery of $2,257), respectively (note 8)
36

 
263

 
1,977

 
(3,532
)
Other comprehensive (loss) income, net of tax
(126,631
)
 
34,126

 
(264,217
)
 
(138,027
)
Comprehensive (loss) income
(77,737
)
 
48,847

 
(180,382
)
 
(76,572
)
Comprehensive (loss) income attributable to the non-controlling interests
(39,062
)
 
1,174

 
(106,594
)
 
(43,006
)
Comprehensive (loss) income attributable to shareholders of Algonquin Power & Utilities Corp.
$
(38,675
)
 
$
47,673

 
$
(73,788
)
 
$
(33,566
)
See accompanying notes to unaudited interim consolidated financial statements



Algonquin Power & Utilities Corp.
Unaudited Interim Consolidated Statement of Equity

 
(thousands of Canadian dollars)
For the nine months ended September 30, 2017
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Algonquin Power & Utilities Corp. Shareholders
 
 
 
 
 
Common
shares
 
Preferred
shares
 
Additional
paid-in
capital
 
Accumulated
deficit
 
Accumulated
OCI
 
Non-
controlling
interests
 
Total
Balance, December 31, 2016
$
1,972,203

 
$
213,805

 
$
38,652

 
$
(556,024
)
 
$
254,927

 
$
562,358

 
$
2,485,921

Net earnings (loss)
—

 
—

 
—

 
133,114

 
—

 
(49,279
)
 
83,835

Redeemable non-controlling interests not included in equity (note 15)
—

 
—

 
—

 
—

 
—

 
10,379

 
10,379

Other comprehensive loss
—

 
—

 
—

 
—

 
(206,902
)
 
(57,315
)
 
(264,217
)
Dividends declared and distributions to non-controlling interests
—

 
—

 
—

 
(152,735
)
 
—

 
(3,685
)
 
(156,420
)
Dividends and issuance of shares under dividend reinvestment plan
33,550

 
—

 
—

 
(33,550
)
 
—

 
—

 
—

Common shares issued upon conversion of convertible debentures
1,113,292

 
—

 
—

 
—

 
—

 
—

 
1,113,292

Common shares issued pursuant to share-based awards (note 11(b))
19,496

 
—

 
(6,369
)
 
(1,946
)
 
—

 
—

 
11,181

Share-based compensation (note 11(b))
—

 
—

 
7,463

 
—

 
—

 
—

 
7,463

Contributions received from non-controlling interests (notes 3(a), 3(e) and 6(a))
—

 
—

 
—

 
—

 
—

 
263,462

 
263,462

Balance, September 30, 2017
$
3,138,541

 
$
213,805

 
$
39,746

 
$
(611,141
)
 
$
48,025

 
$
725,920

 
$
3,554,896

See accompanying notes to unaudited interim consolidated financial statements




Algonquin Power & Utilities Corp.
Unaudited Interim Consolidated Statements of Cash Flows
(thousands of Canadian dollars)
Three Months Ended September 30
 
Nine Months Ended September 30
 
2017
 
2016
 
2017
 
2016
Cash provided by (used in):
 
 
 
 
 
 
 
Operating Activities
 
 
 
 
 
 
 
Net earnings
$
48,894

 
$
14,721

 
$
83,835

 
$
61,455

Adjustments and items not affecting cash:
 
 
 
 

 

Depreciation and amortization
80,045

 
41,605

 
251,359

 
142,875

Deferred taxes
11,620

 
(737
)
 
46,470

 
17,732

Unrealized loss (gain) on derivative financial instruments
1,439

 
(6,754
)
 
4,421

 
(5,732
)
Share-based compensation expense
2,620

 
1,449

 
7,181

 
4,083

Cost of equity funds used for construction purposes
(711
)
 
(857
)
 
(1,846
)
 
(1,945
)
Pension and post-employment expense
(18,965
)
 
(6,497
)
 
(13,252
)
 
(9,273
)
Non-cash revenue and other income
110

 
(1,607
)
 
(208
)
 
(7,182
)
Write-down (gain) on long-lived assets
849

 
(2
)
 
(3,980
)
 
6,936

Changes in non-cash operating items (note 20)
(6,755
)
 
(18,725
)
 
(86,030
)
 
(42,974
)
 
119,146

 
22,596

 
287,950

 
165,975

Financing Activities
 
 
 
 
 
 
 
Increase in long-term debt
224,531

 
174,116

 
1,738,740

 
527,357

Decrease in long-term debt
(80,819
)
 
—

 
(2,483,980
)
 
(48,049
)
Issuance of convertible debentures, net of costs
—

 
(422
)
 
743,881

 
357,880

Cash dividends on common shares
(44,240
)
 
(30,027
)
 
(127,089
)
 
(87,846
)
Cash dividends on preferred shares
(2,600
)
 
(2,600
)
 
(7,800
)
 
(7,800
)
Cash contributions from non-controlling interests
14,004

 
—

 
293,637

 
—

Production-based cash contributions from non-controlling interest
—

 
—

 
10,622

 
9,454

Cash distributions to non-controlling interests
(1,670
)
 
(777
)
 
(3,071
)
 
(3,204
)
Issuance of common shares, net of costs
68

 
364

 
184

 
1,045

Proceeds from settlement of derivative assets
—

 
—

 
48,380

 
—

Proceeds from exercise of share options
—

 
(1,000
)
 
12,761

 
18,493

Shares surrendered to fund withholding taxes on exercised share options
—

 
—

 
(4,293
)
 
(5,218
)
Increase in other long-term liabilities
535

 
23

 
16,340

 
4,252

Decrease in other long-term liabilities
(836
)
 
(379
)
 
(7,219
)
 
(3,200
)
 
108,973

 
139,298

 
231,093

 
763,164

Investing Activities
 
 
 
 
 
 
 
Increase (decrease) in restricted cash
5,099

 
(3,949
)
 
2,015,239

 
—

Acquisitions of operating entities
—

 
(100,005
)
 
(2,047,401
)
 
(432,283
)
Divestiture of operating entity
—

 
—

 
111,043

 
—

Additions to property, plant and equipment
(165,434
)
 
(92,257
)
 
(569,857
)
 
(233,959
)
Decrease (increase) in other assets
101

 
2,181

 
(2,648
)
 
(10,942
)
Distributions received in excess of equity income
2,444

 
2,024

 
2,834

 
1,454

Receipt of principal on notes receivable
—

 
—

 
—

 
11,685

Increase in long-term investments
(15,191
)
 
(196,166
)
 
(49,368
)
 
(338,111
)
 
(172,981
)
 
(388,172
)
 
(540,158
)
 
(1,002,156
)
Effect of exchange rate differences on cash
(10,533
)
 
4,720

 
(12,840
)
 
(3,816
)
Increase (decrease) in cash and cash equivalents
44,605

 
(221,558
)
 
(33,955
)
 
(76,833
)
Cash and cash equivalents, beginning of period
31,857

 
269,078

 
110,417

 
124,353

Cash and cash equivalents, end of period
$
76,462

 
$
47,520

 
$
76,462

 
$
47,520

 
 
 
 
 
 
 
 
Supplemental disclosure of cash flow information:
2017
 
2016
 
2017
 
2016
Cash paid during the period for interest expense
$
50,013

 
$
47,492

 
$
140,437

 
$
106,414

Cash paid during the period for income taxes
$
1,778

 
$
2,244

 
$
10,111

 
$
10,931

Non-cash financing and investing activities:
 
 
 
 
 
 
 
Property, plant and equipment acquisitions in accruals
$
142,116

 
$
38,613

 
$
142,116

 
$
38,613

Issuance of common shares under dividend reinvestment plan and share-based compensation plans
$
15,260

 
$
7,406

 
$
36,262

 
$
26,994

Issuance of common shares upon conversion of convertible debentures (note 10)

$
562

 
$
—

 
$
1,100,924

 
$
—

Issuance of common shares upon conversion of subscription receipts
$
—

 
$
110,503

 
$
—

 
$
110,503

Acquisition of equity investments in exchange of loan receivable and payable
$
2,353

 
$
22,153

 
$
2,353

 
$
22,153

See accompanying notes to unaudited interim consolidated financial statements

Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(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 Liberty Power Group and the Liberty Utilities Group. The Liberty Power Group owns and operates a diversified portfolio of non-regulated renewable and thermal electric generation assets; the 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 unaudited interim consolidated financial statements and notes have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and Article 10 of Regulation S-X provided by the U.S. Securities and Exchange Commission (“SEC”). In the opinion of management, the unaudited interim consolidated financial statements include all adjustments that are of a recurring nature and necessary for a fair presentation of the results of interim operations.
The significant accounting policies applied to these unaudited interim consolidated financial statements of APUC are consistent with those disclosed in the consolidated financial statements of APUC for the year ended December 31, 2016 except for adopted accounting policies described in note 2(a).
Effective January 1, 2017, the acquisition date, the unaudited consolidated results of The Empire District Electric Company ("Empire") are consolidated within APUC (note 3(c)). Empire’s accounting policies align with those used by APUC’s except certain Empire-specific policies including policies approved by the regulator as described below.
(b)     Seasonality
APUC's operating results are subject to seasonal fluctuations that could materially impact quarter-to-quarter operating results and, thus, one quarter's operating results are not necessarily indicative of a subsequent quarter's operating results. APUC's wind energy assets, wind resources is typically stronger in spring, fall and winter and weaker in summer. APUC’s hydroelectric energy assets are primarily “run-of-river” and as such fluctuate with the natural water flows. During the winter and summer periods, flows are generally slower, while during the spring and fall periods flows are heavier. APUC's solar energy assets experience greater insolation in summer, weaker in winter. APUC’s water and wastewater utility assets’ revenues fluctuate depending on the demand for water. During drier, hotter periods of the year, which occurs generally in the summer, demand for water is typically higher than during cooler, wetter periods of the year. During the winter period, natural gas distribution utilities experience higher demand than during the summer period. Where decoupling mechanisms exist, total volumetric revenue is prescribed by the Regulator and fluctuates based on usage while total fixed revenue will not fluctuate through the year. Different electrical distribution utilities can experience higher or lower demand in the summer or winter depending on the specific regional weather, industry characteristics and existence of a decoupling mechanism.
(c)     Commonly owned facilities
Empire owns undivided interests in three electric generating facilities with ownership interest ranging from 7.52% to 60% with a corresponding share of capacity and generation from the facility used to serve Empire's customers. Empire's investment in the undivided interest is recorded as plant in service and recovered through rate base. Empire's share of operating costs are recognized in operating, maintenance and fuel expenditures excluding depreciation expense.
As at and during the nine months ended September 30, 2017 the following amounts related to commonly owned facilities were recognized in the unaudited interim consolidated financial statements:     
Cost of ownership in plant in service
 
$
822,730

Accumulated Depreciation
 
$
222,499

Expenditures
 
$
76,261


Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(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 2016-17 Consolidation (Topic 810): Interests Held through Related Parties That Are under Common Control. This update 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 adoption of this update in the first quarter of 2017 had no impact on the Company's unaudited interim 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 adoption of this update in the first quarter of 2017 had no material impact on the Company's unaudited interim consolidated financial statements. The Company continues 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 adoption of this update in the first quarter of 2017 had no impact on the Company's unaudited interim consolidated financial statements.
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 adoption of this update in the first quarter of 2017 had no impact on the Company's unaudited interim 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 adoption of this update in the first quarter of 2017 had no impact on the Company's unaudited interim consolidated financial statements.
(b)Recently issued accounting guidance not yet adopted
The FASB issued 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities, to improve the financial reporting of hedging relationships to better portray the economic results of an entity's risk management activities in its financial statements. The update also makes certain targeted improvements to simplify the application of the hedge accounting guidance. The update is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years . Early application is permitted in any interim period after issuance of the update. The Company is currently assessing the impacts of this update.
The FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718): Scope of Modification Accounting, to provide clarity and reduce both diversity in practice and cost and complexity when applying the guidance in Topic 718, Compensation-Stock Compensation, to a change to the terms or conditions of a share-based payment award. The update clarifies that an entity should account for the effects of a modification unless all of the following are met: (1) the fair value of the modified award is the same as the fair value of the original award immediately before the original award is modified, (2) the vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award was modified, and (3) the classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the original award is modified. The update is effective for fiscal years and interim periods, beginning after December 15, 2017. Early adoption is permitted. The Company will apply the guidance in this update for future modifications.



Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(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 2017-07 Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-retirement Benefit Cost, to improve the reporting of defined benefit pension cost and post-retirement benefit cost (net benefit cost) in the financial statements. This update requires the service cost component to be reported in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The update will also only allow the service cost component to be eligible for capitalization when applicable. The update is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is permitted. The adoption of the presentation component of the standard will change the presentation of net benefit cost in the Company's consolidated statements of operations. The Company is currently in the process of evaluating the impact of adoption of this standard on the eligibility for capitalization of the other components of net benefit cost on its consolidated financial statements, given the application of ASC 980 Regulated Operations and ongoing regulatory developments.
The FASB issued ASU 2017-05 Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. The update clarifies the scope of the standard as well as provides additional guidance on partial sales of nonfinancial assets. The update is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is permitted however the update must be adopted at the same time as ASU 2014-09. No impact on the consolidated financial statements is expected from the adoption of this update.
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 is in the final stages of the impact assessment. At this point, the Company does not expect changes to the pattern of revenue recognition and is considering adopting the new revenue recognition standard using the modified retrospective method. A final evaluation of the impact on internal controls and financial statement disclosures is being finalized. The Company is on track for implementation of this standard by the effective date.
3.
Business acquisitions and development projects
(a)
Great Bay Solar Project
On August 12, 2015, the Company acquired rights to develop a 75 MWac solar project in Somerset County, Maryland. The project consists of four separate sites and is expected to be placed in service in Q4 2017. As of September 30, 2017, two of the four sites had been synchronized with the power grid.
The Great Bay Solar Facility is controlled by a subsidiary of APUC ("Great Bay Holdings, LLC"). On September 18, 2017, an equity capital contribution agreement was signed with a third-party tax equity investor committing to total funding of U.S. $62,500 in consideration for Class A membership interests. Initial equity capital contribution of U.S. $12,500 was received on September 18, 2017. Through 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.

Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

3.
Business acquisitions and development projects (continued)
(b)
Acquisition of the St. Lawrence Gas Company, Inc.
On August 31, 2017, the Company entered into a definitive agreement to acquire St. Lawrence Gas Company, Inc. ("SLG"). SLG is a rate-regulated natural gas distribution utility serving approximately 16,000 customers in northern New York state. The total purchase price for the transaction is U.S. $70,000, less total third-party debt of SLG outstanding at closing, and subject to customary working capital adjustments. Closing of the transaction remains subject to regulatory approval and other closing conditions and is expected to occur in late 2018 or early 2019.
(c)
Acquisition of Empire
On January 1, 2017, the Company completed the acquisition of Empire, 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. $2,414,000 for the acquisition of Empire consists of cash payments 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 7(b)), proceeds received from the initial instalment of convertible debentures (note 10) and an existing credit facility. The costs related to the acquisition have been expensed through the consolidated statements of operations.
The following table summarizes the preliminary allocation of the assets acquired and liabilities assumed at the acquisition date:
Working capital
$
54,874

Property, plant and equipment
2,764,905

Goodwill
990,828

Regulatory assets
281,695

Other assets
52,347

Long-term debt
(1,218,563
)
Regulatory liabilities
(112,920
)
Pension and other post-employment benefits
(107,907
)
Deferred income tax liability, net
(579,317
)
Other liabilities
(103,317
)
Total net assets acquired
$
2,022,625

Cash and cash equivalent
$
2,338

Total net assets acquired, net of cash and cash equivalent
$
2,020,287

The determination of the fair value of assets acquired and liabilities assumed is based upon management's preliminary estimates and certain assumptions.  Due to the timing of the acquisition, the Company has not completed the fair value measurements, particularly the relative fair value of each of the individual utilities acquired.  The Company will continue to review information and perform further analysis prior to finalizing the fair value of the consideration paid and the fair value of the assets acquired and liabilities assumed.
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.
Property, plant and equipment, exclusive of computer software, 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 Empire's assets is 39 years.



Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

3.
Business acquisitions and development projects (continued)
(c)
Acquisition of Empire (continued)
The table below presents the unaudited consolidated pro forma revenue and net income for the three and nine months ended ended September 30, 2017 and 2016, assuming the acquisition of Empire had occurred on January 1, 2016. Pro forma net income includes the impact of fair value adjustments incorporated in the preliminary purchase price allocation above and adjustments necessary to reflect the financing costs as if the acquisition had been financed on January 1, 2016. However, non-recurring acquisition-related expenses are excluded from net income.
 
Three Months Ended September 30
Nine Months Ended September 30
 
2017
2016
2017
2016
Revenues
$
443,316

$
449,953

$
1,454,456

$
1,401,497

Net earnings attributable to common shareholders
$
55,517

$
33,841

$
181,119

$
168,274

This pro forma information does not purport to represent what the actual results of operations of the Company would have been had the acquisition occurred on this date nor does it purport to predict the results of operations for future periods.
(d)
Luning Solar Facility
On February 15, 2017, Luning Utilities (Luning Holdings) LLC (the “Luning Holdings”) obtained control of the Luning Solar Facility upon achieving commercial operation. Luning Holdings is owned by the Calpeco Electric System, a regulated electric distribution utility of the Company. The Luning Solar Facility is a 50MWac solar generating facility located in Mineral County, Nevada acquired for a total purchase price of U.S.$110,856.
The Class A tax equity investor funded approximately U.S. $39,000 of the acquisition cost and will receive the majority of the tax attributes associated with the Luning Solar project. During a six-month period in year 2022, the tax investor has the right to withdraw from Luning Holdings 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 September 30, 2017.
The following table summarizes the preliminary allocation of the assets acquired and liabilities assumed at the acquisition date:
Working capital
$
198

Property, plant and equipment
145,045

Asset retirement obligation
(714
)
Non-controlling interest (tax equity)
(50,548
)
Total net assets acquired
$
93,981

The determination of the fair value of assets acquired and liabilities assumed is based upon management's preliminary estimates and certain assumptions.  Due to the timing of the acquisition, the Company has not completed the fair value measurements.
(e)
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.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

3.
Business acquisitions and development projects (continued)
(e)
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. Through 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.
4.
Accounts receivable
Accounts receivable as of September 30, 2017 include unbilled revenue of $47,280 (December 31, 2016 - $57,822) from the Company’s regulated utilities. Accounts receivable as of September 30, 2017 are presented net of allowance for doubtful accounts of $7,718 (December 31, 2016 - $7,064).
5.
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.
On January 1, 2017, the Company completed the acquisition of Empire, an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. Empire also provides regulated water utility distribution services to three towns in Missouri. The Empire District Gas Company, a wholly owned subsidiary, is engaged in the distribution of natural gas in Missouri. These businesses are subject to regulation by the Missouri Public Service Commission, the State Corporation Commission of the State of Kansas, the Corporation Commission of Oklahoma, the Arkansas Public Service Commission and the Federal Energy Regulatory Commission. In general, the commissions set rates at a level that allows the utilities to collect total revenues or revenue requirements equal to the cost of providing service, plus an appropriate return on invested capital.
At any given time, the Company can have several regulatory proceedings underway. The financial effects of these proceedings are reflected in the unaudited interim consolidated financial statements based on regulatory approval obtained to the extent that there is a financial impact during the applicable reporting period.
In August 2017, the Corporation Commission of the State of Oklahoma approved an Environmental Compliance Rider of U.S. $992 annually effective August 31, 2017.
In April 2017, the State of Iowa Department of Commerce Utilities Board approved a rate increase of U.S. $1,000 for the Midstates Gas system effective June 18, 2017.
In May 2017, the Illinois Commerce Commission approved a rate increase of U.S. $2,200 for the Midstates Gas system effective June 7, 2017.
In April 2017, the EnergyNorth Gas System filed for a distribution rate case with the New Hampshire Public Utility Commission. On June 30, 2017, the Commission approved a temporary revenue increase of U.S. $6,750, effective July 1, 2017 which are to remain in place until the end of the Company's permanent rate case.
In June 2016, the New Hampshire Public Utility Commission approved a temporary annual rate increase for the Granite State Electric System of U.S. $2,355, effective July 1, 2016. On April 12, 2017, the New Hampshire Public Utility Commission approved a Final Order of a total U.S. $3,750 annual revenue increase retroactive to July 1, 2016, and a U.S. $2,474 step adjustment for plant additions made in 2016, effective May 1, 2017.
In April 2017, the Massachusetts Department of Public Utilities approved a rate increase of U.S. $2,928 for the New England Natural Gas Company, for its 2017 gas system enhancement plan. The rates are effective May 1, 2017.


Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

5.
Regulatory matters (continued)
In March 2017, the Arizona Corporate Commission approved a rate increase of U.S. $152 for Entrada Del Oro Sewer, effective April 1, 2017.
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.
Regulatory assets and liabilities consist of the following: 
 
September 30, 2017
 
December 31, 2016
Regulatory assets
 
 
 
Environmental remediation
$
97,437

 
$
104,160

Pension and post-employment benefits
140,745

 
75,527

Debt premium
75,093

 
25,173

Fuel and commodity costs adjustments
26,243

 
6,972

Rate adjustment mechanism
47,227

 
40,602

Clean Energy and other customer programs
25,081

 
2,106

Deferred construction costs (a)
17,988

 
—

Asset retirement
18,490

 
2,113

Income taxes
34,231

 
10,182

Rate case costs
9,021

 
8,572

Other
33,589

 
16,557

Total regulatory assets
$
525,145

 
$
291,964

Less current regulatory assets
(74,148
)
 
(48,440
)
Non-current regulatory assets
$
450,997

 
$
243,524

 
 
 
 
Regulatory liabilities
 
 
 
Cost of removal
$
159,564

 
$
110,330

Rate-base offset
17,236

 
20,946

Fuel and commodity costs adjustments
41,789

 
33,891

Deferred compensation received in relation to lost production
12,450

 
—

Deferred construction costs - fuel related (a)
9,294

 
—

Pension and post-employment benefits
10,249

 
5,481

Income Taxes
7,070

 
1,501

Other
13,021

 
10,585

Total regulatory liabilities
$
270,673

 
$
182,734

Less current regulatory liabilities
(53,946
)
 
(47,769
)
Non-current regulatory liabilities
$
216,727

 
$
134,965

(a)
Deferred construction costs reflects deferred costs from Empire's 2005 regulatory plan related to construction costs and fuel related costs of specific generating facilities. These amounts are being recovered over the life of the plants.

Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

6.
Long-term investments
Long-term investments consist of the following:
 
September 30, 2017
 
December 31, 2016
Equity-method investees
 
 
 
Red Lily
$
21,670

 
$
23,504

Deerfield Wind Project (a)
—

 
34,727

Amherst Island Wind Project
1,881

 
558

Other
6,101

 
5,630

 
$
29,652

 
$
64,419

Notes receivable
 
 
 
Development loans (b)
$
78,551

 
$
32,125

Other
4,119

 
6,058

 
82,670

 
38,183

Available-for-sale investment
—

 
169

Other investments
2,536

 
2,662

Total long-term investments
114,858

 
105,433

Less current portion classified within other assets
(4,453
)
 
—

Total long-term investments
$
110,405

 
$
105,433

(a)Deerfield Wind Project
Up to March 14, 2017, the Company held 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.
On October 12, 2016, third-party construction loan financing was provided to the Deerfield Wind Project in the amount of U.S. $262,900. Construction was completed during the first quarter and sale of power to the utility under the power purchase agreement started on February 21, 2017. On May 10, 2017, tax equity funding of U.S. $166,595 was received.
On March 14, 2017, the Company acquired the remaining 50% interest in Deerfield SponsorCo for U.S. $21,585 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 and liabilities assumed in the subsidiary be recognized on the consolidated balance sheet as of the acquisition date. It further requires that pre-existing relationships such as the existing development loan between the two parties (note 6(b)) 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 preliminary allocation of the assets acquired and liabilities assumed at the acquisition date:
Working capital
$
(14,551
)
Property, plant and equipment
442,086

Construction loan
(352,666
)
Asset retirement obligation
(2,816
)
Deferred revenue
(1,556
)
Deferred tax liability
(1,979
)
Net assets acquired
$
68,518

Cash and cash equivalent
4,183

Net assets acquired, net of cash and cash equivalent
$
64,335


Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

6.
Long-term investments (continued)
(b)
Development loans
As at September 30, 2017, the Company has a loan and credit support facility with Windlectric Inc. Windlectric Inc. ("Windlectric") owns a 75 MW construction-stage wind development project (“Amherst Island Wind Project”) in the province of Ontario. During construction, the Company provides Windlectric 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 Amherst Island Wind Project. The loan bears interest at an annual rate of 10% on outstanding principal amount and matures on December 31, 2018.
During the second quarter, the Company also provided a one-year loan of U.S. $3,318 to a wind project developer in the United States.
As of December 31, 2016, the Company had outstanding loans of U.S. $1,789 from Deerfield SponsorCo. Following acquisition of control of Deerfield SponsorCo LLC (note 6(a)), amounts advanced to the Deerfield Wind Project are 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 March 14, 2017.
No interest revenue was accrued on the loans due to insufficient collateral in the Joint Ventures.
7.
Long-term debt
Long-term debt consists of the following:
Borrowing type
 
September 30, 2017
 
December 31, 2016
Senior Unsecured Revolving Credit Facilities (a)
 
$
653,433

 
$
242,947

Senior Unsecured Bank Credit Facilities (b)
 
168,480

 
2,140,122

Canadian Dollar Borrowings
 
 
 
 
Senior Unsecured Notes (c)
 
781,566

 
487,389

Senior Secured Project Notes
 
34,032

 
35,600

U.S. Dollar Borrowings
 
 
 
 
Senior Unsecured Notes (d)
 
1,519,502

 
700,600

Senior Unsecured Utility Notes (e)
 
281,599

 
174,206

Senior Secured Utility Bonds (f)
 
993,837

 
132,551

 
 
$
4,432,449

 
$
3,913,415

Less: current portion
 
(8,426
)
 
(10,075
)
 
 
$
4,424,023

 
$
3,903,340

Long-term debt issued at a subsidiary level (project notes, utility notes or utility bonds) 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.
Short-term obligations of $681,800 for which the maturity has been extended beyond 12 months subsequent to the end of the quarter or that are expected to be refinanced using the long-term credit facilities are presented as long-term debt.



Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

7.
Long-term debt (continued)
(a)
Senior unsecured revolving credit facilities
During the quarter, the Company increased its APUC credit facility from $65,000 to $165,000 and the maturity was extended to November 19, 2018.
Subsequent to quarter end on October 6, 2017 the Liberty Power Group's revolving credit facility was increased to U.S. $500,000 and the maturity was extended to October 6, 2022.
Liberty Power entered into a $150,000 bilateral revolving credit facility on April 19, 2017 with a maturity date of August 19, 2018. Drawings under the facility of $118,685 at September 30, 2017 were fully repaid on October 6, 2017.
As at September 30, 2017, the Liberty Utilities Group's committed bank lines consisted of a U.S. $200,000 senior unsecured revolving credit facility and a U.S. $200,000 revolving credit facility at Empire ("Empire Facility") assumed in connection with the acquisition of Empire (note 3(c)). The facilities mature on September 30, 2018 and October 20, 2019 respectively. The Empire Facility is used primarily as a backstop to commercial paper issued by Empire.
(b)
Senior unsecured bank credit facilities
On December 30, 2016, in connection with the acquisition of Empire (note 3(c)), the Company drew U.S. $1,336,440 from the acquisition facility it obtained from a syndicate of banks earlier in 2016. 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(c)) on January 1, 2017. Following receipt of the Final Instalment from the convertible debentures on February 7, 2017 (note 10) and the senior notes financing on March 24, 2017 (note 7(d)), the Company fully repaid the acquisition Facility.
On March 24, 2016, the Company repaid U.S. $100,000 of borrowings under the Corporate Term Facility with proceeds from the closing of the U.S. $750,000 senior unsecured notes (notes 7(e)).
In June 2017, the Company repaid a U.S. $22,500 bank term facility related to Park Water systems.
Subsequent to quarter end, the Liberty Utilities Group extended the maturity on its term loan facility to July 5, 2019.
(c)
Canadian dollar senior unsecured notes
On January 17, 2017, the Liberty Power Group 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.
In September 2017, the Company acquired an investment in an equity-investee in exchange for a note payable to the other partner of $669. Repayment of the note is expected in 2019.
(d)
U.S. dollar senior unsecured notes
On March 24, 2017, the Liberty Utilities Group issued U.S. $750,000 senior unsecured notes in six tranches. The proceeds were applied to repay the acquisition facility (note 7(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%. In anticipation of the financing, the Liberty Utilities Group had entered into forward contracts to lock in the underlying U.S. Treasury interest rates. Considering the effect of the hedges, the effective weighted average rate paid by the Liberty Utilities Group will be 3.6%.
(e)
U.S. dollar senior unsecured utility notes
On February 8, 2017, the U.S. $707 Bella Vista Water unsecured utility notes were fully repaid.
On January 1, 2017, in connection with the acquisition of Empire (note 3(c)), the Company assumed U.S. $102,000 in unsecured utility notes. The notes consist of two tranches, with maturities in 2033 and 2035 with coupons at 6.7% and 5.8%.

Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

7.
Long-term debt (continued)
(f)
U.S. dollar senior secured utility bonds
On January 1, 2017 in connection with the acquisition of Empire (note 3(c)), the Company assumed U.S. $733,000 in secured utility notes. The bonds are secured by a first mortgage indenture and consist of ten tranches with maturities ranging between 2018 and 2044 with coupons ranging from 3.58% to 6.82%.
In June 2017, outstanding bonds payable for the Park Water systems in the amount of U.S. $63,000 were repaid using proceeds from the Mountain Water condemnation discussed in note 19(a).
(g)
U.S. dollar senior secured project notes
On March 14, 2017, in connection with the acquisition of Deerfield SponsorCo (note 6(a)), the Company assumed U.S. $262,219 in construction loan. The loans bear interest at an annual rate of 2.33% on any outstanding principal amount. On May 10, 2017, the construction loan was repaid from proceeds received from tax equity (note 6(a)) and cash contributions from APUC.
8.
Pension and other post-employment benefits
In connection with the acquisition of Empire, the Company assumed pension and other post-employment benefits ("OPEB") obligations of $107,907. Empire District Electric provides the following plans to employees:
•
A noncontributory defined benefit pension plan for all employees hired before January 1, 2014 meeting minimum age and service requirements.
•
A cash balance defined benefit pension plan for all employees hired after January 1, 2014.
•
A supplemental retirement program (“SERP”) for designated officers of Empire. The SERP plan was frozen effective January 1, 2017.
•
Certain healthcare and life insurance benefits to eligible retired employees, their dependents and survivors. Participants generally become eligible for retiree healthcare benefits after reaching age 55 with 5 years of service. Employees hired after January 1, 2014 are offered unsubsidized retiree healthcare benefits upon retirement.
The following table outlines the aggregate financial position for the key plans as at January 1, 2017:    
 
Pension benefits
SERP
OPEB
Projected benefit obligation
$
329,158

$
17,073

$
131,264

Fair value of Plan Assets
247,740

—

122,900

Unfunded status
$
(81,418
)
$
(17,073
)
$
(8,364
)
Empire has rate orders with Missouri, Kansas and Oklahoma allowing the recovery of pension costs. As a result, Empire records the Missouri, Kansas and Oklahoma portion of any costs above or below the amount included in rates as a regulatory asset or liability, respectively.
On June 22, 2017, all Mountain Water employees were terminated as a result of the condemnation of the Mountain Water assets to the city of Missoula (note 19(a)). The pension and OPEB obligations of these employees remain with the Company. The assets and projected benefit obligations of the plans were revalued at June 30, 2017 and resulted in an actuarial gain of U.S. $2,354 recorded in other comprehensive income and a curtailment gain of U.S. $853 recorded against the loss on long-lived assets.
The following tables list the components of net benefit costs for pension and OPEB recorded as part of operating expenses in the unaudited interim consolidated statements of operations. The employee benefit costs related to businesses acquired are recorded in the unaudited interim consolidated statements of operations from the date of acquisition.
8.
Pension and other post-employment benefits (continued)
 
Pension benefits
 
Three Months Ended September 30
 
Nine Months Ended September 30
 
2017
 
2016
 
2017
 
2016
Service cost
$
4,249

 
$
2,132

 
$
13,853

 
$
6,482

Interest cost
6,237

 
3,150

 
19,540

 
9,578

Expected return on plan assets
(8,089
)
 
(3,419
)
 
(24,917
)
 
(10,394
)
Amortization of net actuarial loss
376

 
742

 
1,088

 
2,257

Amortization of prior service credits
(195
)
 
(188
)
 
(610
)
 
(572
)
Amortization of regulatory asset/liability
3,635

 
1,085

 
11,376

 
3,298

Net benefit cost
$
6,213

 
$
3,502

 
$
20,330

 
$
10,649


 
OPEB
 
Three Months Ended September 30
 
Nine Months Ended September 30
 
2017
 
2016
 
2017
 
2016
Service cost
$
1,528

 
$
796

 
$
4,937

 
$
2,419

Interest cost
2,037

 
904

 
6,498

 
2,751

Expected return on plan assets
(2,044
)
 
(298
)
 
(6,367
)
 
(906
)
Amortization of net actuarial loss
(130
)
 
136

 
(226
)
 
414

Amortization of prior service credits
(82
)
 
(453
)
 
(256
)
 
(1,377
)
Amortization of regulatory asset/liability
336

 
246

 
1,052

 
749

Net benefit cost
$
1,645

 
$
1,331

 
$
5,638

 
$
4,050


Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

9.
Other long-term liabilities and deferred credits
Other long-term liabilities consist of the following: 
 
September 30, 2017
 
December 31, 2016
Advances in aid of construction
$
76,789

 
$
105,191

Environmental remediation obligations
61,366

 
63,378

Asset retirement obligations
55,317

 
24,822

Customer deposits
34,336

 
14,881

Unamortized investment tax credits
22,350

 
—

Hook up fees
7,554

 
12,039

Deferred income
1,442

 
—

Deferred credits
26,436

 
44,544

Other
30,444

 
10,751

 
316,034

 
275,606

Less current portion
(44,842
)
 
(43,157
)
 
$
271,192

 
$
232,449


9.
Other long-term liabilities and deferred credits (continued)
In connection with the acquisition of Empire, the Company assumed certain asset retirement obligations. Asset retirement obligations mainly relate to legal requirements to: (i) remove certain river water intake structures and equipment; (ii) disposal of coal combustion residuals and Polychlorinated Biphenyls (PCB) contaminants; and (iii) remove asbestos upon major renovation or demolition of structures and facilities.
As the cost of retirement of asset are expected to be recovered through rates, a corresponding regulatory asset is recorded, as well as the on-going liability accretion and asset depreciation expense.
In connection with the acquisition of Empire, the Company assumed investment tax credits based on the investment made in a generating station, which, if unused, will expire in 2030. Management expects to use these credits to offset future income tax liabilities. The tax credits will have no significant income statement impact because they will flow to customers as the tax credits are amortized over the life of the plant.
10.
Convertible Unsecured Subordinated Debentures
    
Maturity date
March 31, 2026

Interest rate
5.00
%
Conversion price per share
$
10.60

Carrying value at December 31, 2016
$
358,619

Receipt of Final instalment, net of deferred financing costs
743,881

Amortization of deferred financing costs
1,139

Conversion to common shares
$
(1,101,036
)
Carrying value at September 30, 2017
$
2,603

Face value at September 30, 2017
$
2,717

In March 2016, the Company completed the sale of $1,150,000 aggregate principal amount of 5.0% convertible debentures.
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”) was received on February 2, 2017 (“Final Instalment Date”) following satisfaction of conditions precedent to the closing of the acquisition of Empire (note 3(c)). The proceeds received from the initial and final instalments, net of financing costs were $357,694 and $743,881, respectively. 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. The interest expense recorded for the three and nine months ended September 30, 2017 is $nil and $9,373 (2016 - $14,335 and $19,219 ).
The debentures are convertible into up to 108,490,566 common shares. As at September 30, 2017, a total of 108,234,197 common shares of the Company were issued (note 11), representing conversion into common shares of more than 99.76% of the convertible debentures.
The remaining convertible debentures mature on March 31, 2026 and bear interest at an annual rate of 0% per $1,000 principal amount of 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.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

11.
Shareholders’ capital
(a)
Common shares
Number of common shares: 
 
 
2017
Common shares, beginning of year
 
274,087,018

Issuance of common shares upon conversion of convertible debentures (note 10)
 
108,234,197

Issuance of common shares upon exercise of share options, net of withholding taxes
 
1,469,362

Issuance of shares under the dividend reinvestment and employee share compensation plans
 
3,245,606

Common shares, end of period
 
387,036,183


(b)
Share-based compensation
During the nine months ended September 30, 2017, the Board of Directors of APUC (the "Board") approved the grant of 2,328,343 options to executives of the Company. The options allow for the purchase of common shares at a weighted average price of $12.82, the market price of the underlying common share at the date of grant. One-third of the options vest on each of January 1, 2018, 2019, and 2020. Options may be exercised up to eight years following the date of grant.
The following assumptions were used in determining the fair value of share options granted: 
Risk-free interest rate
1.42
%
Expected volatility
25
%
Expected dividend yield
4.25
%
Expected life
5.5

Weighted average grant date fair value per option
$
1.45

During the first quarter, executives of the Company exercised 1,469,362 stock options at a weighted average exercise price of $7.81 in exchange for common shares issued from treasury and 165,139 options were settled at their cash value as payment for tax withholdings related to the exercise of the options.
During the first quarter, 253,809 Performance Share Units ("PSU") were granted to executives of the Company. The PSUs vest on January 1, 2020. During the second quarter, 358,307 PSU were granted to employees of the Company. The PSUs vest on January 1, 2020. During the first quarter, the Company settled 173,499 PSU in exchange for common shares issued from treasury and 182,463 PSUs were settled at their cash value as payment for tax withholdings related to the settlement of the PSUs.
During the nine months ended September 30, 2017, 43,493 Deferred Share Units (“DSU”) were issued pursuant to the election of the Directors to defer a percentage of their Directors' fee in the form of DSUs.
For the three and nine months ended September 30, 2017, APUC recorded $2,675 and $7,192 (2016 - $1,581 and $4,073) in total share-based compensation expense. The compensation expense is recorded as part of administrative expenses in the unaudited interim consolidated statements of operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.
As of September 30, 2017, total unrecognized compensation costs related to non-vested options and PSUs were $3,632 and $8,185, respectively, and are expected to be recognized over a period of 1.55 and 2.03 years, respectively.

Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

12.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, 2016
$
261,357

 
$
39,329

 
$
(72
)
 
$
(13,877
)
 
$
286,737

OCI (loss) 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

OCI (loss) before reclassifications
(217,334
)
 
14,403

 
(26
)
 
1,921

 
(201,036
)
Amounts reclassified
—

 
(5,922
)
 
—

 
56

 
(5,866
)
Net current period OCI
$
(217,334
)
 
$
8,481

 
$
(26
)
 
$
1,977

 
$
(206,902
)
Balance, September 30, 2017
$
(17,006
)
 
$
74,564

 
$
115

 
$
(9,648
)
 
$
48,025

Amounts reclassified from AOCI for unrealized gain (loss) on cash flow hedges affected revenue from non-regulated energy sales and interest expense while those for pension and post-employment actuarial changes affected administrative expenses.
13.
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 common shares in U.S. dollars. Dividends declared in Canadian equivalent dollars during the three and nine months ended September 30, 2017 and 2016 were as follows:
 
Three Months Ended September 30
 
2017
 
2016
 
Dividend
 
Dividend per share
 
Dividend
 
Dividend per share
Common shares
$
57,517

 
$
0.1480

 
$
37,735

 
$
0.1377

Series A preferred shares
$
1,350

 
$
0.2813

 
$
1,350

 
$
0.2813

Series D preferred shares
$
1,250

 
$
0.3125

 
$
1,250

 
$
0.3125

 
Nine Months Ended September 30
 
2017
 
2016
 
Dividend
 
Dividend per share
 
Dividend
 
Dividend per share
Common shares
$
178,485

 
$
0.4606

 
$
109,937

 
$
0.4025

Series A preferred shares
$
4,050

 
$
0.8438

 
$
4,050

 
$
0.8438

Series D preferred shares
$
3,750

 
$
0.9375

 
$
3,750

 
$
0.9375








Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

14.
Related party transactions
Emera Inc.
An executive at Emera was a member of the Board of APUC until June 8, 2017. The Energy Services Business sold electricity to Maine Public Service Company and Bangor Hydro, both of which are subsidiaries of Emera. The portion considered related party transactions during the three and nine months ended September 30, 2017, amounts to U.S. $nil and $4,397 (2016 - U.S. $3,095 and $7,951). The Liberty Utilities Group purchased natural gas from Emera for its gas utility customers. The portion considered related party transactions during the three and nine months ended September 30, 2017, amounts to U.S. $nil and $1,006 (2016 - U.S. $534 and $2,762). 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. In 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 transmission upgrade was placed in service in Q2 2017 with final completion of the contract work expected in the fourth quarter.  The total cost of the contract is estimated at  $9,500. The contract followed a market based request for proposal process.
There was U.S. $1,711 included in accruals for the nine months ended September 30, 2017 (2016 - U.S. $64) related to these transactions.
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 $704 and $1,512 (2016 - $893 and $2,510) during the three and nine months ended September 30, 2017.
Trafalgar
In 2016, the Company received U.S. $10,083 in proceeds from the settlement of the Trafalgar matter, and paid U.S.$2,900 to an entity partially and indirectly owned by Senior Executives as its proportionate share. The gain to APUC, net of legal and other liabilities, of approximately U.S. $6,600 was recorded in 2016.
Long Sault Hydro Facility
Effective December 31, 2013, APUC acquired the shares of Algonquin Power Corporation Inc. (“APC”) which was partially owned by Senior Executives.  APC owns the partnership interest in the 18MW Long Sault Hydro Facility.  A final post-closing adjustment related to the transaction remains outstanding.
The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.
15.
Non-controlling interests and Redeemable non-controlling interest
Net loss attributable to non-controlling interests for the three and nine months ended September 30, 2017 and 2016 consists of the following:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
HLBV and other adjustments attributable to:
 
 
 
 
 
 
 
Non-controlling interest -Class A partnership units
$
(7,823
)
 
$
(3,811
)
 
$
(41,266
)
 
$
(23,254
)
Non-controlling interest -redeemable Class A partnership units
(3,308
)
 
(1,378
)
 
(10,379
)
 
(4,127
)
Other net earnings attributable to non-controlling interests
585

 
2,165

 
2,366

 
4,258

Net effect of non-controlling interests
$
(10,546
)
 
$
(3,024
)
 
$
(49,279
)
 
$
(23,123
)
Contributions from new Class A partnership investors of U.S. $12,500 was received for the Great Bay Solar Facility on September 18, 2017 (note 3(a)); U.S. $9,800 was received for the Bakersfield II Solar Facility on February 28, 2017 (note 3(e)); and, U.S. $166,595 was received for the Deerfield Wind Project on May 10, 2017 (note 6(a)).



Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

16.
Income taxes
For the nine months ended September 30, 2017, the Company’s overall effective tax rate was different from the statutory Canadian income tax rate of 26.50% (2016 - 26.50%) primarily due to transaction costs related to the acquisition of Empire, basis differences related to the Mountain Water condemnation, and higher tax rates on U.S. earnings.
17.
Basic and diluted net earnings per share
Basic and diluted earnings per share have been calculated on the basis of net earnings attributable to the common shareholders of the Company and the weighted average number of common shares and subscription receipts outstanding. Diluted net earnings per share is computed using the weighted-average number of common shares, subscription receipts outstanding in 2016, additional shares issued subsequent to quarter-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 convertible debentures (note 10) are convertible into common shares at any time after the Final Instalment Date, but prior to maturity or redemption by the Company. The Final Instalment Date occurred on February 2, 2017, and as such, the shares issuable upon conversion of the convertible debentures are included in diluted earnings per share beginning on that date.
The reconciliation of the net earnings and the weighted average shares used in the computation of basic and diluted earnings per share for the three and nine months ended September 30, 2017 and 2016 are as follows:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Net earnings attributable to shareholders of APUC
$
59,440

 
$
17,745

 
$
133,114

 
$
84,578

Series A Preferred shares dividend
1,350

 
1,350

 
4,050

 
4,050

Series D Preferred shares dividend
1,250

 
1,250

 
3,750

 
3,750

Net earnings attributable to common shareholders of APUC – Basic and Diluted
$
56,840

 
$
15,145

 
$
125,314


$
76,778

Weighted average number of shares
 
 
 
 
 
 
 
Basic
386,816,307

 
273,202,368

 
372,109,455

 
271,120,426

Effect of dilutive securities
3,438,243

 
2,376,823

 
3,696,938

 
2,433,527

Diluted
390,254,550

 
275,579,191

 
375,806,393


273,553,953

The shares potentially issuable, for the three and nine months ended September 30, 2017, as a result of 2,328,343 and 1,897,266 share options (2016 - 108,424 and 1,417,500) are excluded from this calculation as they are anti-dilutive.
18.
Segmented information
In connection with the acquisition of Empire on January 1, 2017, the Company aligned its management reporting under two primary North American business units consisting of the Liberty Power Group and the Liberty Utilities Group. The two business units are the two segments of the Company.
The Liberty Power Group owns and operates a diversified portfolio of non-regulated renewable and thermal electric generation utility assets; the Liberty Utilities Group owns and operates a portfolio of regulated electric, natural gas, water distribution and wastewater collection utility systems and transmission operations.
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. The results of operations and assets for these new segments are reflected in the tables below. The comparative information for 2016 has been reclassified to conform with the composition of the reporting segments presented in the current year.

Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

18.
Segmented information (continued)
 
Three Months Ended September 30, 2017
 
Liberty Power Group
 
Liberty Utilities Group
 
Corporate
 
Total
Revenue
$
59,997

 
$
383,319

 
$
—

 
$
443,316

Fuel, power and water purchased
5,379

 
98,483

 
—

 
103,862

Net revenue
54,618

 
284,836

 
—

 
339,454

Operating expenses
22,490

 
119,789

 
—

 
142,279

Administrative expenses
4,817

 
9,401

 
220

 
14,438

Depreciation and amortization
20,249

 
50,824

 
334

 
71,407

Gain on foreign exchange
—

 
—

 
2,643

 
2,643

Operating income
7,062

 
104,822

 
(3,197
)
 
108,687

Interest expense
12,114

 
32,716

 
783

 
45,613

Interest, dividend, equity and other income
(699
)
 
(1,189
)
 
(567
)
 
(2,455
)
Other expenses (gain)
(16
)
 
818

 
1,050

 
1,852

Earnings (loss) before income taxes
$
(4,337
)
 
$
72,477

 
$
(4,463
)
 
$
63,677

Capital expenditures
61,434

 
104,000

 
—

 
165,434


 
Three Months Ended September 30, 2016
 
Liberty Power Group
 
Liberty Utilities Group
 
Corporate
 
Total
Revenue
$
60,730

 
$
160,547

 
$
—

 
$
221,277

Fuel and power purchased
6,018

 
41,147

 
—

 
47,165

Net revenue
54,712

 
119,400

 
—

 
174,112

Operating expenses
17,386

 
62,948

 
15

 
80,349

Administrative expenses
4,863

 
6,902

 
306

 
12,071

Depreciation and amortization
15,385

 
24,008

 
340

 
39,733

Loss on foreign exchange
—

 
—

 
(3,355
)
 
(3,355
)
Operating income (loss)
17,078

 
25,542

 
2,694

 
45,314

Interest expense
5,123

 
12,335

 
17,309

 
34,767

Interest, dividend and other income
561

 
(1,351
)
 
(715
)
 
(1,505
)
Other expense (gain)
(1,684
)
 
(4,926
)
 
2,146

 
(4,464
)
Earnings (loss) before income taxes
$
13,078

 
$
19,484

 
$
(16,046
)
 
$
16,516

Capital expenditures
25,074

 
67,183

 
—

 
92,257












Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

18.
Segmented information (continued)
 
Nine Months Ended September 30, 2017
 
Liberty Power Group
 
Liberty Utilities Group
 
Corporate
 
Total
Revenue
$
213,363

 
$
1,241,093

 
$
—

 
$
1,454,456

Fuel, power and water purchased
17,679

 
348,625

 
—

 
366,304

Net revenue
195,684

 
892,468

 
—

 
1,088,152

Operating expenses
64,731

 
388,908

 
—

 
453,639

Administrative expenses
15,524

 
29,571

 
651

 
45,746

Depreciation and amortization
73,766

 
163,655

 
1,001

 
238,422

Gain on foreign exchange
—

 
—

 
(1,193
)
 
(1,193
)
Operating income
41,663

 
310,334

 
(459
)
 
351,538

Interest expense
35,940

 
96,841

 
27,437

 
160,218

Interest, dividend, equity and other income
(2,614
)
 
(3,678
)
 
(2,222
)
 
(8,514
)
Other expenses (gain)
2,285

 
(4,988
)
 
61,501

 
58,798

Earnings (loss) before income taxes
$
6,052

 
$
222,159

 
$
(87,175
)
 
$
141,036

Property, plant and equipment
$
2,812,547

 
$
4,934,213

 
$
43,661

 
$
7,790,421

Equity-method investees
26,420

 
997

 
2,235

 
29,652

Total assets
3,113,811

 
7,066,260

 
126,666

 
10,306,737

Capital expenditures
179,873

 
389,984

 
—

 
569,857


 
Nine Months Ended September 30, 2016
 
Liberty Power Group
 
Liberty Utilities Group
 
Corporate
 
Total
Revenue
$
192,049

 
$
593,735

 
$
—

 
$
785,784

Fuel and power purchased
15,042

 
190,392

 
—

 
205,434

Net revenue
177,007

 
403,343

 
—

 
580,350

Operating expenses
52,167

 
192,519

 
45

 
244,731

Administrative expenses
13,911

 
18,380

 
1,573

 
33,864

Depreciation and amortization
55,770

 
77,478

 
1,019

 
134,267

Gain on foreign exchange
—

 
—

 
(1,782
)
 
(1,782
)
Operating income (loss)
55,159

 
114,966

 
(855
)
 
169,270

Interest expense
14,878

 
37,470

 
40,549

 
92,897

Interest, dividend and other income
(160
)
 
(4,006
)
 
(2,269
)
 
(6,435
)
Other expense (gain)
(14,519
)
 
1,875

 
8,366

 
(4,278
)
Earnings (loss) before income taxes
$
54,960

 
$
79,627

 
$
(47,501
)
 
$
87,086

Capital expenditures
86,313

 
147,646

 
—

 
233,959

 
December 31, 2016
Property, plant and equipment
$
2,455,336

 
$
2,390,047

 
$
44,563

 
$
4,889,946

Equity-method investees
59,021

 
914

 
4,484

 
64,419

Total assets
2,771,651

 
5,388,966

 
88,843

 
8,249,460


Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

19.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 unaudited interim consolidated financial statements at the time it is concluded that its occurrence is probable and the related liability is estimable.
Empire is subject to various federal, state, and local laws and regulations with respect to air and water quality and with respect to hazardous and toxic materials or other wastes, including their identification, transportation, disposal, record-keeping and reporting, as well as remediation of contaminated sites and other environmental matters. Management believes that operations are in material compliance with present environmental laws and regulations. Currently it is not possible to accurately estimate compliance costs for any new requirements, it is expected that these costs might be material, although recoverable in rates.
Condemnation Expropriation Proceedings
Mountain Water was the subject of a condemnation lawsuit filed 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 could proceed with condemnation of Mountain Water’s assets. The fair market value of the condemned property as of May 6, 2014 was assessed by the Commissioners to be U.S. $88,600.  Upon taking possession of Mountain Water’s assets on June 22, 2017, the city of Missoula paid U.S. $83,863 to Mountain Water, net of closing adjustments and amounts required to be paid by the City directly to various developers in satisfaction of obligations under Funded By Other (FBO) contracts relating to the assets.
In connection with Liberty Utilities’ indirect acquisition of Mountain Water in January 2016, Liberty Utilities was permitted and continues to hold-back U.S. $14,400 from the purchase price otherwise payable to Carlyle Infrastructure Partners, L.P. (“Carlyle”) and certain other interest holders.
The condemnation of the Mountain Water assets resulted in a gain on long-lived assets of U.S. $4,370.
(b)
Commitments
In addition to the commitments related to the business acquisition and development projects disclosed in notes 3 and 6, the following significant commitments exist as of September 30, 2017.
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)
$
62,830


$
47,817


$
49,228


$
49,884


$
50,162


$
256,647


$
516,568

Gas supply and service agreements (ii)
97,602


70,487


56,256


34,916


29,585


98,946


387,792

Service agreements
45,380


45,837


47,690


48,398


46,501


444,763


678,569

Capital projects
24,319


—


—


—


—


—


24,319

Operating leases
10,057


9,735


8,754


8,809


8,899


229,185


275,439

Total
$
240,188


$
173,876


$
161,928


$
142,007


$
135,147


$
1,029,541


$
1,882,687




Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

19.Commitments and contingencies (continued)
(b)
Commitments (continued)
(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 which are based on market prices were reflected using the September 30, 2017 prices. 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.
20.
Non-cash operating items
The changes in non-cash operating items consist of the following:
 
Three Months Ended September 30
 
Nine Months Ended September 30
 
2017
 
2016
 
2017
 
2016
Accounts receivable
$
(8,203
)
 
$
5,126

 
$
56,385

 
$
58,345

Fuel and natural gas in storage
(6,840
)
 
(8,033
)
 
(3,277
)
 
5,084

Supplies and consumable inventory
(4,937
)
 
(935
)
 
(4,634
)
 
(430
)
Income taxes receivable
3,026

 
(787
)
 
816

 
910

Prepaid expenses
10,316

 
4,282

 
3,905

 
(1,551
)
Accounts payable
(3,280
)
 
25

 
(84,962
)
 
(40,424
)
Accrued liabilities
1,756

 
(15,356
)
 
(33,990
)
 
(54,877
)
Current income tax liability
(6,663
)
 
929

 
(5,967
)
 
(3,972
)
Net regulatory assets and liabilities
8,070

 
(3,976
)
 
(14,306
)
 
(6,059
)
 
$
(6,755
)
 
$
(18,725
)
 
$
(86,030
)
 
$
(42,974
)

Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

21.
Financial instruments
(a)
Fair value of financial instruments
September 30, 2017
Carrying
amount
 
Fair
Value
 
Level 1
 
Level 2
 
Level 3
Notes receivable
$
82,670

 
$
83,718

 
$
—

 
$
83,718

 
$
—

Derivative instruments:
 
 
 
 
 
 
 
 
 
Energy contracts designated as a cash flow hedge
88,657

 
88,657

 
—

 
—

 
88,657

Currency forward contract not designated as a hedge
497

 
497

 
—

 
497

 
—

Commodity contracts for regulated operations
582

 
582

 
—

 
582

 
—

Transmission congestion rights
8,766

 
8,766

 
—

 
8,766

 
—

Total derivative instruments
98,502

 
98,502

 
—

 
9,845

 
88,657

Total financial assets
$
181,172

 
$
182,220

 
$
—

 
$
93,563

 
$
88,657

Long-term debt
$
4,432,449

 
$
4,641,691

 
$
817,475

 
$
3,824,216

 
$
—

Convertible debentures
2,603

 
2,717

 
2,717

 
—

 
—

Preferred shares, Series C
18,459

 
18,320

 
—

 
18,320

 
—

Derivative instruments:
 
 
 
 
 
 
 
 
 
Cross-currency swap designated as a net investment hedge
71,414

 
71,414

 
—

 
71,414

 
—

Interest rate swap designated as a hedge
10,465

 
10,465

 
—

 
10,465

 
—

Commodity contracts for regulated operations
2,080

 
2,080

 
—

 
2,080

 
—

Total derivative instruments
83,959

 
83,959

 
—

 
83,959

 
—

Total financial liabilities
$
4,537,470

 
$
4,746,687

 
$
820,192

 
$
3,926,495

 
$
—




Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

21.
Financial instruments (continued)
(a)Fair value of financial instruments (continued)
December 31, 2016
Carrying
amount
 
Fair
Value
 
Level 1
 
Level 2
 
Level 3
Notes receivable
$
38,183

 
$
47,933

 
$
—

 
$
47,933

 
$
—

Derivative instruments:
 
 
 
 
 
 
 
 
 
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 regulatory 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:
 
 
 
 
 
 
 
 
 
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

 
$
—












Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

21.
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 September 30, 2017 and December 31, 2016 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, rights 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. Transmission congestion rights ("TCR") positions are fair valued using the most recent monthly auction clearing prices.
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 $21.53 to $111.33 with a weighted average of $31.81 as of September 30, 2017.  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 21(b)(ii) and 21(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 three or nine months ended September 30, 2017 and 2016.
(b)
Derivative instruments
Derivative instruments are recognized on the unaudited interim 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 and electric 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:
 
2017
Financial contracts: Swaps
2,687,886

        Options
858,077

Forward contracts
13,420,000

 
16,965,963

At September 30, 2017, TCR of 6,328 monthly MW-hrs have been obtained from TCR auctions to hedge 2017 congestion costs in the Southwest Power Pool ("SPP") Integrated Marketplace.



Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

21.
Financial instruments (continued)
(b)
Derivative instruments (continued)
(i)
Commodity derivatives – regulated accounting (continued)
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 5). 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.
The following table presents the impact of the change in the fair value of the Company’s natural gas derivative contracts had on the unaudited interim consolidated balance sheets: 
 
 
September 30, 2017
 
 
December 31, 2016
Regulatory assets:
 
 
 
 
 
Swap contracts
U.S.
$
83

 
U.S.
$
—

Option contracts
U.S.
$
311

 
U.S.
$
27

Forward contracts
U.S.
$
4,621

 
U.S.
$
—

Regulatory liabilities:
 
 
 
 
 
Swap contracts
U.S.
$
23

 
U.S.
$
175

Option contracts
U.S.
$
—

 
U.S.
$
92

Forward contracts
U.S.
$
15,111

 
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)
604,108

 
 December 2022
 
U.S. $
 
42.81

 
PJM Western HUB
2,587,441

 
 December 2022
 
U.S. $
 
30.25

 
NI HUB
3,430,217

 
 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% which settled on February 13, 2017 in order to reduce the interest rate risk related to the issuance of U.S. $500,000 bonds in relation to the acquisition of Empire (note 7(e)). The change in fair value to February 13, 2017 resulted in a gain of U.S. $36,677. The effective portion of the hedge of U.S. $nil and U.S. $36,533 for the three and nine months ended September 30, 2017 was recorded in OCI while the ineffective portion was recorded in the unaudited interim statement of operations.
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 gain of $2,656 and $2,919 for the three and nine months ended September 30, 2017 (2016 - loss of $1,758 and $13,174), which was recorded in OCI.







Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

21.
Financial instruments (continued)
(b)
Derivative instruments (continued)
(ii)
Cash flow hedges (continued)
The following table summarizes OCI attributable to derivative financial instruments designated as a cash flow hedge: 
 
Three Months Ended September 30
Nine Months Ended September 30
 
2017
 
2016
2017
 
2016
 
 
 
 
 
 
 
Effective portion of cash flow hedge
$
8,440

 
$
(17,052
)
$
14,429

 
$
1,877

Amortization of cash flow hedge
(9
)
 
(14
)
(26
)
 
(30
)
Gain reclassified from AOCI
(1,520
)
 
(2,723
)
(5,922
)
 
(7,995
)
OCI attributable to shareholders of APUC
$
6,911

 
$
(19,789
)
$
8,481

 
$
(6,148
)
The Company expects $12,374 and $2,630 of gains currently in AOCI to be reclassified, net of taxes into non-regulated energy sales and interest expense, respectively, within the next twelve months, as the underlying hedged transactions settle.
(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 Liberty Power 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 Liberty Power 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 gain of $15,287 and $25,890 for the three and nine months ended September 30, 2017 (2016 - $nil and $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 Liberty Power 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. For the three and nine months ended September 30, 2017, a gain of $25,120 and $20,142 (2016 - loss of $5,767 and gain of $9,020) was recorded in OCI.
(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.

Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

21.
Financial instruments (continued)
(b)
Derivative instruments (continued)
(iv)
Other derivatives (continued)
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 21(b)(ii)).
The Company is exposed to foreign exchange fluctuations related to U.S dollar denominated development loans from projects accounted for as equity investments (note 6(b)). 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 September 30, 2017, these instruments had settled. This currency forward contract was not accounted for as a hedge.
The Company was exposed to foreign exchange fluctuations related to the acquisition of the Empire shares denominated in U.S dollar (note 3(c)). This risk was 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 10) and the use of a currency forward contract to buy an amount of U.S. $567,665 for $744,050 on January 31, 2017. This currency forward contract was not accounted for as a hedge. The settlement of the currency forward contract resulted in a total realized gain of $nil and $1,452 and a loss of $nil and $17,864 for three and nine months ended September 30, 2017, which is recorded as loss on foreign exchange in the unaudited interim consolidated statements of operations (2016 - $nil and $nil).
The Company is exposed to foreign exchange fluctuations related to the portion of its dividend declared and payable in U.S. dollars. This risk is mitigated through the use of currency forward contracts. For the three and nine months ended September 30, 2017, a gain on foreign exchange of $1,386 and $497 (2016 - $nil and $nil) was recorded in the unaudited interim consolidated statements of operations. These currency forward contracts are 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.



















Algonquin Power & Utilities Corp.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)

21.
Financial instruments (continued)
(b)
Derivative instruments (continued)
(iv)
Other derivatives (continued)
The effects on the unaudited interim consolidated statements of operations of derivative financial instruments not designated as hedges consist of the following:
 
Three Months Ended September 30
 
Nine Months Ended September 30
 
2017
 
2016
 
2017
 
2016
Change in unrealized gain on derivative financial instruments:
 
 
 
 
 
 
 
Energy derivative contracts
$
—

 
$
—

 
$
—

 
$
(426
)
Currency forward contracts
(1,362
)
 
(7,261
)
 
(497
)
 
(6,843
)
Total change in unrealized gain on derivative financial instruments
$
(1,362
)
 
$
(7,261
)
 
$
(497
)
 
$
(7,269
)
Realized loss (gain) on derivative financial instruments:
 
 
 
 
 
 
 
Interest rate swaps
—

 
—

 
(193
)
 
—

Energy derivative contracts
—

 
—

 
730

 
941

Currency forward contracts
—

 
4,229

 
16,413

 
(1,371
)
Total realized loss (gain) on derivative financial instruments
$
—

 
$
4,229

 
$
16,950

 
$
(430
)
Loss (gain) on derivative financial instruments not accounted for as hedges
(1,362
)
 
(3,032
)
 
16,453

 
(7,699
)
Ineffective portion of derivative financial instruments accounted for as hedges
(14
)
 
507

 
819

 
1,509

 
$
(1,376
)
 
$
(2,525
)
 
$
17,272

 
$
(6,190
)
Amounts recognized in the consolidated statements of operations consist of:
 
 
 
 
 
 
 
Loss (gain) on derivative financial instruments
(14
)
 
(4,419
)
 
1,356

 
(2,902
)
Loss (gain) on foreign exchange
(1,362
)
 
1,893

 
15,916

 
(3,289
)
 
$
(1,376
)
 
$
(2,526
)
 
$
17,272

 
$
(6,191
)
(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.
Notes to the Unaudited Interim Consolidated Financial Statements
September 30, 2017 and 2016
(in thousands of Canadian dollars, except as noted and per share amounts)


22.
Subsequent events
(a)Investment in joint venture with Abengoa and investment in Atlantica
On November 1, 2017, APUC entered into an agreement to create a joint venture ("AAGES") with Seville, Spain-based Abengoa, S.A ("Abengoa") to identify, develop, and construct clean energy and water infrastructure assets with a global focus. Concurrently with the creation of the AAGES joint venture, APUC entered into a definitive agreement to purchase from Abengoa a 25% equity interest in Atlantica Yield plc ("Atlantica") for a total purchase price of approximately U.S. $608,000, based on a price of U.S. $24.25 per ordinary share of Atlantica plus a contingent payment of up to U.S. $0.60 per-share payable two years after closing, subject to certain conditions. The transaction is expected to close in the first quarter of 2018, subject to regulatory approvals and other closing conditions. No shareholder approvals are required.
 
(b)Bought Deal Offering of Common Shares
On November 10, 2017, APUC announced that it closed a bought deal offering announced on November 1, 2017, including the exercise in full of the underwriters' over-allotment option. As a result, a total of 43,470,000 common shares of APUC were sold at a price of $13.25 for gross proceeds of approximately $576,000. Net proceeds of the offering are expected to be used, in part, to finance APUC's acquisition of Abengoa's 25% ownership stake in Atlantica and for general corporate purposes.

(c)Approval to acquire the Perris Water Distribution System
On August 10, 2017 the Company’s board approved the acquisition of two water distribution systems serving approximately 4,095 customers from the City of Perris, California.  The anticipated purchase price of U.S. $11,500 is expected to be established as rate base during the regulatory approval process.  The City of Perris residents voted to approve the sale on November 7, 2017. Liberty Utilities will now file an application to acquire the water utility with the California Public Utility Commission. Approval of the acquisition of the utility is expected in 2018.

23.
Comparative figures
Certain of the comparative figures have been reclassified to conform to the financial statement presentation adopted in the current year.