Exhibit 4.4

 

Consolidated Balance Sheets

(condensed and unaudited)

 

	
As at ($ millions)
    	
 
    	
March 31,
   2018
    	
 
    	
December 31,
   2017
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
ASSETS
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Current   assets
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Cash and cash   equivalents (note 17)
    	
 
    	
$
    	
100.1
    	
 
    	
$
    	
27.3
    	
 
    
	
Accounts   receivable, net of allowances
    	
 
    	
354.7
    	
 
    	
382.9
    	
 
    
	
Inventory (note 5)
    	
 
    	
138.7
    	
 
    	
201.1
    	
 
    
	
Restricted cash   holdings from customers (note 17)
    	
 
    	
5.2
    	
 
    	
8.9
    	
 
    
	
Regulatory   assets
    	
 
    	
1.7
    	
 
    	
1.1
    	
 
    
	
Risk management   assets (note 11)
    	
 
    	
27.7
    	
 
    	
38.6
    	
 
    
	
Prepaid expenses   and other current assets
    	
 
    	
37.1
    	
 
    	
36.0
    	
 
    
	
Assets held for   sale (note 4)
    	
 
    	
—
    	
 
    	
6.0
    	
 
    
	
 
    	
 
    	
665.2
    	
 
    	
701.9
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Property,   plant and equipment
    	
 
    	
6,767.4
    	
 
    	
6,689.8
    	
 
    
	
Intangible   assets
    	
 
    	
587.3
    	
 
    	
588.8
    	
 
    
	
Goodwill   (note 6)
    	
 
    	
832.5
    	
 
    	
817.3
    	
 
    
	
Regulatory   assets
    	
 
    	
326.5
    	
 
    	
328.6
    	
 
    
	
Risk   management assets (note 11)
    	
 
    	
15.3
    	
 
    	
15.9
    	
 
    
	
Deferred   income taxes
    	
 
    	
2.8
    	
 
    	
2.8
    	
 
    
	
Restricted   cash holdings from customers (note 17)
    	
 
    	
5.8
    	
 
    	
7.5
    	
 
    
	
Long-term   investments and other assets   (note 7)
    	
 
    	
310.4
    	
 
    	
312.6
    	
 
    
	
Investments   accounted for by the equity method
    	
 
    	
593.1
    	
 
    	
567.0
    	
 
    
	
 
    	
 
    	
$
    	
10,106.3
    	
 
    	
$
    	
10,032.2
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
LIABILITIES   AND SHAREHOLDERS’ EQUITY
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Current   liabilities
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Accounts payable   and accrued liabilities
    	
 
    	
$
    	
377.1
    	
 
    	
$
    	
415.3
    	
 
    
	
Dividends   payable
    	
 
    	
32.5
    	
 
    	
32.0
    	
 
    
	
Short-term debt
    	
 
    	
4.9
    	
 
    	
46.8
    	
 
    
	
Current portion   of long-term debt (notes 8 and 11)
    	
 
    	
213.9
    	
 
    	
188.9
    	
 
    
	
Customer   deposits
    	
 
    	
20.7
    	
 
    	
30.8
    	
 
    
	
Regulatory   liabilities
    	
 
    	
8.3
    	
 
    	
10.9
    	
 
    
	
Risk management   liabilities (note 11)
    	
 
    	
48.7
    	
 
    	
57.6
    	
 
    
	
Other current   liabilities
    	
 
    	
21.6
    	
 
    	
32.6
    	
 
    
	
Liabilities   associated with assets held for sale (note 4)
    	
 
    	
—
    	
 
    	
0.3
    	
 
    
	
 
    	
 
    	
727.7
    	
 
    	
815.2
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Long-term   debt (notes 8 and 11)
    	
 
    	
3,468.6
    	
 
    	
3,436.5
    	
 
    
	
Asset   retirement obligations
    	
 
    	
89.0
    	
 
    	
88.3
    	
 
    
	
Deferred   income taxes
    	
 
    	
448.2
    	
 
    	
444.2
    	
 
    
	
Regulatory   liabilities
    	
 
    	
278.5
    	
 
    	
268.6
    	
 
    
	
Risk   management liabilities (note 11)
    	
 
    	
13.6
    	
 
    	
13.8
    	
 
    
	
Other   long-term liabilities
    	
 
    	
206.4
    	
 
    	
201.9
    	
 
    
	
Future   employee obligations
    	
 
    	
126.4
    	
 
    	
124.5
    	
 
    
	
 
    	
 
    	
$
    	
5,358.4
    	
 
    	
$
    	
5,393.0
    	
 
    


 

AltaGas Ltd. – Q1 2018

 

1











 

	
As at ($ millions)
    	
 
    	
March 31,
   2018
    	
 
    	
December 31,
   2017
    	
 
    
	
Shareholders’   equity
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Common shares,   no par values, unlimited shares authorized; 2018 - 177.9 million and 2017 -   175.3 million issued and outstanding (note 12)
    	
 
    	
$
    	
4,074.4
    	
 
    	
$
    	
4,007.9
    	
 
    
	
Preferred shares   (note 12)
    	
 
    	
1,277.7
    	
 
    	
1,277.7
    	
 
    
	
Contributed   surplus
    	
 
    	
22.5
    	
 
    	
22.3
    	
 
    
	
Accumulated deficit
    	
 
    	
(988.7
    	
)
    	
(933.6
    	
)
    
	
Accumulated   other comprehensive income (AOCI) (note 9)
    	
 
    	
280.9
    	
 
    	
199.1
    	
 
    
	
Total   shareholders’ equity
    	
 
    	
4,666.8
    	
 
    	
4,573.4
    	
 
    
	
Non-controlling   interests
    	
 
    	
81.1
    	
 
    	
65.8
    	
 
    
	
Total   equity
    	
 
    	
4,747.9
    	
 
    	
4,639.2
    	
 
    
	
 
    	
 
    	
$
    	
10,106.3
    	
 
    	
$
    	
10,032.2
    	
 
    


 

Commitments, contingencies and guarantees (note 14).

Subsequent events (note 20).

 

See accompanying notes to the Consolidated Financial Statements.

 

2











 

Consolidated Statements of Income

(condensed and unaudited)

 

	
Three months ended March 31 ($ millions except per share amounts)
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
REVENUE (note 10)
    	
 
    	
$
    	
878.4
    	
 
    	
$
    	
771.2
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
EXPENSES
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Cost of sales,   exclusive of items shown separately
    	
 
    	
538.0
    	
 
    	
434.1
    	
 
    
	
Operating and administrative
    	
 
    	
140.8
    	
 
    	
159.7
    	
 
    
	
Accretion   expenses
    	
 
    	
2.7
    	
 
    	
2.8
    	
 
    
	
Depreciation and   amortization
    	
 
    	
72.6
    	
 
    	
71.5
    	
 
    
	
 
    	
 
    	
754.1
    	
 
    	
668.1
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Income   from equity investments
    	
 
    	
10.1
    	
 
    	
14.1
    	
 
    
	
Other   loss
    	
 
    	
(5.3
    	
)
    	
(2.5
    	
)
    
	
Foreign   exchange gains
    	
 
    	
—
    	
 
    	
0.3
    	
 
    
	
Interest   expense
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Short-term debt
    	
 
    	
(0.8
    	
)
    	
(0.8
    	
)
    
	
Long-term debt
    	
 
    	
(42.3
    	
)
    	
(45.2
    	
)
    
	
Income   before income taxes
    	
 
    	
86.0
    	
 
    	
69.0
    	
 
    
	
Income   tax expense (note 16)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Current
    	
 
    	
12.8
    	
 
    	
11.4
    	
 
    
	
Deferred
    	
 
    	
5.7
    	
 
    	
9.9
    	
 
    
	
Net   income after taxes
    	
 
    	
67.5
    	
 
    	
47.7
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Net   income applicable to non-controlling interests
    	
 
    	
2.3
    	
 
    	
2.3
    	
 
    
	
Net   income applicable to controlling interests
    	
 
    	
65.2
    	
 
    	
45.4
    	
 
    
	
Preferred   share dividends
    	
 
    	
(16.4
    	
)
    	
(13.6
    	
)
    
	
Net   income applicable to common shares
    	
 
    	
$
    	
48.8
    	
 
    	
$
    	
31.8
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Net   income per common share (note 13)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Basic
    	
 
    	
$
    	
0.28
    	
 
    	
$
    	
0.19
    	
 
    
	
Diluted
    	
 
    	
$
    	
0.28
    	
 
    	
$
    	
0.19
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Weighted   average number of common shares outstanding (millions) (note 13)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Basic
    	
 
    	
176.5
    	
 
    	
167.9
    	
 
    
	
Diluted
    	
 
    	
176.6
    	
 
    	
168.3
    	
 
    


 

See accompanying notes to the Consolidated Financial Statements.

 

3











 

Consolidated Statements of Comprehensive Income (Loss)

(condensed and unaudited)

 

	
Three months ended March 31 ($ millions)
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Net   income after taxes
    	
 
    	
$
    	
67.5
    	
 
    	
$
    	
47.7
    	
 
    
	
Other comprehensive   income (loss), net of taxes
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Gain (loss) on   foreign currency translation
    	
 
    	
73.2
    	
 
    	
(24.2
    	
)
    
	
Unrealized gain   on net investment hedge (note 11)
    	
 
    	
—
    	
 
    	
1.4
    	
 
    
	
Reclassification   of actuarial gains and prior service costs on defined benefit and   post-retirement benefit plans (PRB) to net income (note 15)
    	
 
    	
0.2
    	
 
    	
0.1
    	
 
    
	
Unrealized loss   on available-for-sale assets
    	
 
    	
—
    	
 
    	
(17.4
    	
)
    
	
Adoption of ASU   2016-01 (note 2)
    	
 
    	
7.1
    	
 
    	
—
    	
 
    
	
Other   comprehensive income (loss) from equity investees
    	
 
    	
1.3
    	
 
    	
(1.2
    	
)
    
	
Total   other comprehensive income (loss) (OCI), net of taxes (note 9)
    	
 
    	
81.8
    	
 
    	
(41.3
    	
)
    
	
Comprehensive   income attributable to controlling interests and non-controlling interests,   net of taxes
    	
 
    	
$
    	
149.3
    	
 
    	
$
    	
6.4
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Comprehensive   income attributable to:
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Non-controlling   interests
    	
 
    	
$
    	
2.3
    	
 
    	
$
    	
2.3
    	
 
    
	
Controlling   interests
    	
 
    	
147.0
    	
 
    	
4.1
    	
 
    
	
 
    	
 
    	
$
    	
149.3
    	
 
    	
$
    	
6.4
    	
 
    


 

See accompanying notes to the Consolidated Financial Statements.

 

4











 

Consolidated Statements of Equity

(condensed and unaudited)

 

	
Three months ended March 31 ($ millions)
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Balance,   beginning of period
    	
 
    	
$
    	
4,007.9
    	
 
    	
$
    	
3,773.4
    	
 
    
	
Shares issued   for cash on exercise of options
    	
 
    	
0.6
    	
 
    	
3.6
    	
 
    
	
Shares issued   under DRIP (1)
    	
 
    	
65.9
    	
 
    	
58.3
    	
 
    
	
Balance, end of   period
    	
 
    	
$
    	
4,074.4
    	
 
    	
$
    	
3,835.3
    	
 
    
	
Preferred   shares (note 12)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Balance,   beginning of period
    	
 
    	
$
    	
1,277.7
    	
 
    	
$
    	
985.1
    	
 
    
	
Series K   Issued
    	
 
    	
—
    	
 
    	
293.6
    	
 
    
	
Deferred taxes   on share issuance costs
    	
 
    	
—
    	
 
    	
1.8
    	
 
    
	
Balance, end of   period
    	
 
    	
$
    	
1,277.7
    	
 
    	
$
    	
1,280.5
    	
 
    
	
Contributed   surplus
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Balance,   beginning of period
    	
 
    	
$
    	
22.3
    	
 
    	
$
    	
17.4
    	
 
    
	
Share options   expense
    	
 
    	
0.2
    	
 
    	
0.3
    	
 
    
	
Exercise of   share options
    	
 
    	
—
    	
 
    	
(0.3
    	
)
    
	
Adoption of ASU   No. 2016-09
    	
 
    	
—
    	
 
    	
1.1
    	
 
    
	
Balance, end of   period
    	
 
    	
$
    	
22.5
    	
 
    	
$
    	
18.5
    	
 
    
	
Accumulated   deficit
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Balance,   beginning of period
    	
 
    	
$
    	
(933.6
    	
)
    	
$
    	
(600.4
    	
)
    
	
Net income   applicable to controlling interests
    	
 
    	
65.2
    	
 
    	
45.4
    	
 
    
	
Common share   dividends
    	
 
    	
(96.8
    	
)
    	
(88.3
    	
)
    
	
Preferred share   dividends
    	
 
    	
(16.4
    	
)
    	
(13.6
    	
)
    
	
Adoption of ASU   No. 2016-09
    	
 
    	
—
    	
 
    	
(1.1
    	
)
    
	
Adoption of ASU   No. 2016-01 (note 2)
    	
 
    	
(7.1
    	
)
    	
—
    	
 
    
	
Balance, end of   period
    	
 
    	
$
    	
(988.7
    	
)
    	
$
    	
(658.0
    	
)
    
	
AOCI (note 9)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Balance,   beginning of period
    	
 
    	
$
    	
199.1
    	
 
    	
$
    	
405.1
    	
 
    
	
Other comprehensive   income (loss)
    	
 
    	
81.8
    	
 
    	
(41.3
    	
)
    
	
Balance, end of   period
    	
 
    	
$
    	
280.9
    	
 
    	
$
    	
363.8
    	
 
    
	
Total   shareholders’ equity
    	
 
    	
$
    	
4,666.8
    	
 
    	
$
    	
4,840.1
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Non-controlling   interests
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Balance,   beginning of period
    	
 
    	
$
    	
65.8
    	
 
    	
$
    	
34.8
    	
 
    
	
Net income   applicable to non-controlling interests
    	
 
    	
2.3
    	
 
    	
2.3
    	
 
    
	
Contributions   from non-controlling interests to subsidiaries
    	
 
    	
13.0
    	
 
    	
—
    	
 
    
	
Distributions by   subsidiaries to non-controlling interests
    	
 
    	
—
    	
 
    	
(1.4
    	
)
    
	
Balance, end of   period
    	
 
    	
81.1
    	
 
    	
35.7
    	
 
    
	
Total   equity
    	
 
    	
$
    	
4,747.9
    	
 
    	
$
    	
4,875.8
    	
 
    


 




(1)         Premium DividendTM, Dividend Reinvestment and Optional Cash Purchase Plan.

 

See accompanying notes to the Consolidated Financial Statements.

 

5











 

Consolidated Statements of Cash Flows

(condensed and unaudited)

 

	
Three months ended March 31 ($ millions)
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Cash   from operations
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Net income after   taxes
    	
 
    	
$
    	
67.5
    	
 
    	
$
    	
47.7
    	
 
    
	
Items not   involving cash:
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Depreciation and   amortization
    	
 
    	
72.6
    	
 
    	
71.5
    	
 
    
	
Accretion   expenses
    	
 
    	
2.7
    	
 
    	
2.8
    	
 
    
	
Share-based   compensation
    	
 
    	
0.2
    	
 
    	
0.3
    	
 
    
	
Deferred income   tax expense (note 16)
    	
 
    	
5.7
    	
 
    	
9.9
    	
 
    
	
Losses (gains)   on sale of assets (note 4)
    	
 
    	
(1.3
    	
)
    	
3.4
    	
 
    
	
Income from   equity investments
    	
 
    	
(10.1
    	
)
    	
(14.1
    	
)
    
	
Unrealized gains   on risk management contracts (note 11)
    	
 
    	
(0.6
    	
)
    	
(0.9
    	
)
    
	
Losses on   investments
    	
 
    	
9.5
    	
 
    	
0.4
    	
 
    
	
Amortization of   deferred financing costs
    	
 
    	
3.1
    	
 
    	
6.8
    	
 
    
	
Other
    	
 
    	
0.3
    	
 
    	
0.7
    	
 
    
	
Asset retirement   obligations settled
    	
 
    	
(0.7
    	
)
    	
(1.2
    	
)
    
	
Distributions   from equity investments
    	
 
    	
6.3
    	
 
    	
6.6
    	
 
    
	
Changes in   operating assets and liabilities (note 17)
    	
 
    	
33.8
    	
 
    	
66.4
    	
 
    
	
 
    	
 
    	
$
    	
189.0
    	
 
    	
$
    	
200.3
    	
 
    
	
Investing   activities
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Acquisition of   property, plant and equipment
    	
 
    	
(82.3
    	
)
    	
(86.3
    	
)
    
	
Acquisition of   intangible assets
    	
 
    	
(1.7
    	
)
    	
(2.2
    	
)
    
	
Contributions to   equity investments
    	
 
    	
(19.0
    	
)
    	
(14.3
    	
)
    
	
Loan to   affiliate, net of repayment
    	
 
    	
—
    	
 
    	
7.5
    	
 
    
	
Proceeds from   disposition of investment
    	
 
    	
5.2
    	
 
    	
—
    	
 
    
	
Payment for   derivative contracts
    	
 
    	
—
    	
 
    	
(21.0
    	
)
    
	
Proceeds from   disposition of assets, net of transaction costs (note 4)
    	
 
    	
9.1
    	
 
    	
69.0
    	
 
    
	
 
    	
 
    	
$
    	
(88.7
    	
)
    	
$
    	
(47.3
    	
)
    
	
Financing   activities
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Net repayment of   short-term debt
    	
 
    	
(42.9
    	
)
    	
(122.6
    	
)
    
	
Issuance of   long-term debt, net of debt issuance costs
    	
 
    	
247.8
    	
 
    	
13.5
    	
 
    
	
Repayment of   long-term debt
    	
 
    	
(205.1
    	
)
    	
(287.1
    	
)
    
	
Dividends -   common shares
    	
 
    	
(96.3
    	
)
    	
(88.0
    	
)
    
	
Dividends -   preferred shares
    	
 
    	
(16.4
    	
)
    	
(12.1
    	
)
    
	
Distributions to   non-controlling interest
    	
 
    	
—
    	
 
    	
(1.4
    	
)
    
	
Contributions   from non-controlling interests
    	
 
    	
13.0
    	
 
    	
—
    	
 
    
	
Net proceeds   from shares issued on exercise of options
    	
 
    	
0.6
    	
 
    	
3.3
    	
 
    
	
Net proceeds   from issuance of common shares
    	
 
    	
65.9
    	
 
    	
58.3
    	
 
    
	
Net proceeds   from issuance of preferred shares
    	
 
    	
—
    	
 
    	
293.6
    	
 
    
	
Other
    	
 
    	
(0.2
    	
)
    	
(0.4
    	
)
    
	
 
    	
 
    	
$
    	
(33.6
    	
)
    	
$
    	
(142.9
    	
)
    
	
Change   in cash, cash equivalents and restricted cash
    	
 
    	
66.7
    	
 
    	
10.1
    	
 
    
	
Effect   of exchange rate changes on cash, cash equivalents and restricted cash
    	
 
    	
0.7
    	
 
    	
0.2
    	
 
    
	
Cash,   cash equivalents, and restricted cash beginning of period
    	
 
    	
43.7
    	
 
    	
34.1
    	
 
    
	
Cash,   cash equivalents, and restricted cash end of period (note 17)
    	
 
    	
$
    	
111.1
    	
 
    	
$
    	
44.4
    	
 
    


 

See accompanying notes to the Consolidated Financial Statements.

 

6









 

Notes to the Condensed Interim Consolidated Financial Statements (unaudited)

 

(Tabular amounts and amounts in footnotes to tables are in millions of Canadian dollars unless otherwise indicated.)

 

1.   ORGANIZATION AND OVERVIEW OF THE BUSINESS

 

The businesses of AltaGas Ltd. (AltaGas or the Corporation) are operated by AltaGas and a number of its subsidiaries including, without limitation, AltaGas Services (U.S.) Inc.; in regards to the gas business, AltaGas Extraction and Transmission Limited Partnership, AltaGas Pipeline Partnership, AltaGas Processing Partnership, AltaGas Northwest Processing Limited Partnership and Harmattan Gas Processing Limited Partnership; in regards to the power business, Coast Mountain Hydro Limited Partnership, Blythe Energy Inc. (Blythe), and AltaGas San Joaquin Energy Inc.; and, in regards to the utility business, AltaGas Utilities Inc. (AUI), Heritage Gas Limited (Heritage Gas), Pacific Northern Gas Ltd. (PNG), and SEMCO Energy, Inc. (SEMCO). SEMCO conducts its Michigan natural gas distribution business under the name SEMCO Energy Gas Company (SEMCO Gas) and its Alaska natural gas distribution business under the name ENSTAR Natural Gas Company (ENSTAR).

 

AltaGas, a Canadian corporation, is a North American diversified energy infrastructure business with a focus on owning and operating assets to provide clean and affordable energy to its customers. AltaGas has three business segments: Gas, Power and Utilities.

 

AltaGas’ Gas segment serves producers in the Western Canada Sedimentary Basin (WCSB) and includes natural gas gathering and processing, natural gas liquids (NGL) extraction and fractionation, gas transmission, gas storage, natural gas and NGL marketing, and the one-third ownership investment, through AltaGas Idemitsu Joint Venture Limited Partnership (AIJVLP), in Petrogas Energy Corp. (Petrogas).

 

The Power segment includes 1,708 MW of gross capacity from natural gas-fired, hydro, wind, and biomass generation facilities, and energy storage assets in Canada and the United States (U.S.).

 

The Utilities segment is predominantly comprised of natural gas distribution rate regulated utilities in Canada and the United States. The utilities are generally allowed the opportunity to earn regulated returns that provide for recovery of costs and a return on, and of, capital from the regulator-approved capital investment base.

 

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

BASIS OF PRESENTATION

 

These unaudited condensed interim Consolidated Financial Statements have been prepared by management in accordance with United States Generally Accepted Accounting Principles (U.S. GAAP). As a result, these unaudited condensed interim Consolidated Financial Statements do not include all of the information and disclosures required in the annual Consolidated Financial Statements and should be read in conjunction with the Corporation’s 2017 annual audited Consolidated Financial Statements prepared in accordance with U.S. GAAP. In management’s opinion, these unaudited condensed interim Consolidated Financial Statements include all adjustments that are of a recurring nature and necessary to present fairly the financial position of the Corporation.

 

Pursuant to National Instrument 52-107, “Acceptable Accounting Principles and Auditing Standards” (NI 52-107), U.S. GAAP reporting is generally permitted by Canadian securities laws for companies subject to reporting obligations under U.S. securities laws. However, given that AltaGas is not subject to such reporting obligations and could not therefore rely on the provisions of NI 52-107 to that effect, AltaGas sought and obtained exemptive relief by the securities regulators in Alberta and Ontario to permit it to prepare its financial statements in accordance with U.S. GAAP. The Alberta Securities Commission exemption will terminate on or after the earlier of January 1, 2024, the date to which AltaGas ceases to have activities subject to rate regulation, or the

 

7











 

effective date prescribed by the International Accounting Standards Board for the mandatory application of a standard within the International Financial Reporting Standard for entities with activities subject to rate-regulated accounting.

 

PRINCIPLES OF CONSOLIDATION

 

These unaudited condensed interim Consolidated Financial Statements of AltaGas include the accounts of the Corporation, its subsidiaries, variable interest entities (VIEs) for which the Corporation is the primary beneficiary, and its interest in various partnerships and joint ventures where AltaGas has an undivided interest in the assets and liabilities. Investments in unconsolidated companies that AltaGas has significant influence over, but not control, are accounted for using the equity method.

 

All intercompany balances and transactions are eliminated on consolidation. Where there is a party with a non-controlling interest in a subsidiary that AltaGas controls, that non-controlling interest is reflected as “Non-controlling interests” in the Consolidated Financial Statements. The non-controlling interests in net income (or loss) of consolidated subsidiaries are shown as an allocation of the consolidated net income and are presented separately in “Net income applicable to non-controlling interests”.

 

USE OF ESTIMATES AND MEASUREMENT UNCERTAINTY

 

The preparation of Consolidated Financial Statements in accordance with U.S. GAAP requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenue and expenses during the period. Key areas where Management has made complex or subjective judgments, when matters are inherently uncertain, include but are not limited to: determining the nature and timing of satisfaction of performance obligations and determining the transaction price and amounts allocated to performance obligations for revenue recognition; depreciation and amortization rates, fair value of asset retirement obligations, fair value of property, plant and equipment and goodwill for impairment assessments, fair value of financial instruments, provisions for income taxes, assumptions used to measure employee future benefits, provisions for contingencies, and carrying value of regulatory assets and liabilities. Certain estimates are necessary for the regulatory environment in which AltaGas’ subsidiaries or affiliates operate, which often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. By their nature, these estimates are subject to measurement uncertainty and may impact the Consolidated Financial Statements of future periods.

 

SIGNIFICANT ACCOUNTING POLICIES

 

Except as noted below, these unaudited condensed interim Consolidated Financial Statements have been prepared following the same accounting policies and methods as those used in preparing the Corporation’s 2017 annual audited Consolidated Financial Statements.

 

ADOPTION OF NEW ACCOUNTING STANDARDS

 

Effective January 1, 2018, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU):

 

·                  ASU No. 2014-09 “Revenue from Contracts with Customers” and all related amendments (collectively “ASC 606”).  AltaGas adopted ASC 606 using the modified retrospective method to contracts that have not been completed as at January 1, 2018. Under the modified retrospective method, the comparative information is not adjusted. The adoption of ASC 606 impacted the timing of revenue recognition in relation to contracts with take-or-pay or minimum volume commitments whereby the customers have make up rights for deficiency quantities. However, on adoption, no cumulative adjustments to opening retained earnings were required for this change in revenue recognition pattern as none of the customers had material deficiency quantities. Please also refer to Note 10 for further details. AltaGas does not expect the application of ASC 606 to have a material impact on its consolidated financial statements in 2018;

 

8











 

·                  ASU No. 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” which revised an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. It also amended certain disclosure requirements associated with the fair value of financial instruments. Upon adoption, AltaGas reclassified its equity securities with readily determinable fair values from available-for-sale to held for trading. Changes in fair value for equity securities with readily determinable fair values are now recognized through earnings instead of other comprehensive income. As a result, a cumulative-effect adjustment to retained earnings of approximately $7 million was recognized as at January 1, 2018. The remaining provisions of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

 

·                  ASU No. 2016-15 “Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments”. The amendments in this ASU clarified the classification of certain cash flow transactions on the statement of cash flow. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

 

·                  ASU No. 2016-16 “Income Taxes: Intra-Entity Transfers of Assets Other Than Inventory”. The amendments in this ASU revised the accounting for income tax consequences on intra-entity transfers of assets by requiring an entity to recognize current and deferred tax on intra-entity transfers of assets other than inventory when the transfer occurs. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

 

·                  ASU No. 2016-18 “Statement of Cash Flows: Restricted Cash”. The amendments in this ASU required those amounts deemed to be restricted cash and restricted cash equivalents to be included in the cash and cash equivalents balance on the statement of cash flows. The change in presentation of the restricted cash balance on the statement of cash flows was applied on a retrospective basis;

 

·                  ASU No. 2017-01 “Business Combinations: Clarifying the Definition of a Business”. The amendments in this ASU changed the definition of a business to assist entities with evaluating when a set of transferred assets and activities is a business. AltaGas will apply the amendments to this ASU prospectively;

 

·                  ASU No. 2017-04 “Intangibles — Goodwill and Other: Simplifying the Test for Goodwill Impairment”. The amendments in this ASU removed Step 2 of the goodwill impairment test, eliminating the requirement to determine the fair value of individual assets and liabilities of a reporting unit to measure the goodwill impairment. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

 

·                  ASU No. 2017-05 “Other Income — Gains and Losses from the De-recognition of Nonfinancial Assets: Clarifying the Scope of Asset De-recognition Guidance and Accounting for Partial Sales of Nonfinancial Assets”. The amendments in this ASU clarified the scope of ASC 610-20 as well as the accounting for partial sales of nonfinancial assets. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

 

·                  ASU No. 2017-07 “Compensation — Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”. The amendments in this ASU revised the presentation of net periodic pension cost and net periodic postretirement benefit cost on the income statement and limited the components that are eligible for capitalization in assets to only the service cost component. AltaGas applied the change in presentation of the current service cost and other components of net benefit cost on the income statement retrospectively. As a result, $0.4 million of net benefit cost associated with other components was reclassified from the line item “Operating and administrative” to “Other loss” on the Consolidated Statement of Income for the three months ended March 31, 2017. AltaGas applied the change related to the capitalization of the service cost prospectively. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

 

·                  ASU No. 2017-09 “Compensation — Stock Compensation: Scope of Modifications Accounting”. The amendments in this ASU provided guidance on the types of changes to the terms or conditions of share-based payment arrangements to

 

9











 

which an entity would be required to apply modification accounting. The guidance was applied prospectively and did not have a material impact on AltaGas’ consolidated financial statements;

 

·                  ASU No. 2017-12 “Derivatives and Hedging — Targeted Improvements to Accounting for Hedging Activities”. The amendments in this ASU improved the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and made certain targeted improvements to simplify the application of hedge accounting. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and

 

·                  ASU No. 2018-03 “Technical Corrections and Improvements to Financial Instruments — Overall”. The amendments in this ASU clarified certain aspects of the guidance issued in ASU No. 2016-01. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements.

 

FUTURE CHANGES IN ACCOUNTING PRINCIPLES

 

In February 2016, FASB issued ASU No. 2016-02 “Leases”, which requires lessees to recognize on the balance sheet a right-of-use asset and a lease liability for all leases with lease terms greater than 12 months. Lessor accounting remains substantially unchanged, however, the ASU modifies what qualifies as a sales-type and direct financing lease and eliminates the real estate-specific provisions included in ASC 840. The ASU also requires additional disclosures regarding leasing arrangements. In January 2018, FASB issued ASU No. 2018-01 “Land Easement Practical Expedient for Transition to Topic 842” providing entities with an optional election not to evaluate existing and expired land easements not previously accounted for as leases under ASC 840 using the provisions of ASC 842. The amendments to the new leases standard are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. AltaGas is currently performing a scoping exercise by gathering a complete inventory of lease contracts in order to evaluate the impact of adopting ASC 842 on its consolidated financial statements, but expects that the new standard will have an impact on the Corporation’s balance sheet as all operating leases will need to be reflected on the balance sheet upon adoption. In addition, AltaGas currently expects to utilize the transition practical expedients which allow entities to not have to reassess whether an arrangement contains a lease under the provisions of ASC 842.

 

In June 2016, FASB issued ASU No. 2016-13 “Financial Instruments — Credit Losses: Measurement of Credit Losses on Financial Instruments”. The amendments in this ASU replace the current “incurred loss” impairment methodology with an “expected loss” model for financial assets measured at amortized cost. The amendments in this ASU are effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted. AltaGas is currently assessing the impact of this ASU on its consolidated financial statements.

 

In February 2018, FASB issued ASU No. 2018-02 “Income Statement — Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”. The amendments in this ASU allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

 

10











 

3.   DEVELOPMENTS RELATING TO THE PENDING WGL ACQUISITION

 

Pending Acquisition of WGL Holdings, Inc. (WGL)

 

On January 25, 2017, the Corporation entered into a merger agreement (the Merger Agreement) to indirectly acquire WGL Holdings, Inc. (the WGL Acquisition). Pursuant to the Merger Agreement, following the consummation of the WGL Acquisition, WGL common shareholders will receive US$88.25 per common share in cash, which represents a total enterprise value of approximately US$7.2 billion, including the assumption of approximately US$2.7 billion of debt as at December 31, 2017.

 

WGL is a diversified energy infrastructure company and the sole common shareholder of Washington Gas, a regulated natural gas utility headquartered in Washington, D.C., serving approximately 1.2 million customers in Maryland, Virginia, and the District of Columbia. WGL has a growing midstream business with investments in natural gas gathering infrastructure and regulated gas pipelines in the Marcellus/Utica gas formation located in the northeast United States, with capabilities for connections to marine-based energy export opportunities via the North American Atlantic coast through the Cove Point LNG Terminal in Maryland which was developed by a third party and recently began exporting LNG. WGL also owns contracted clean power assets, with a focus on distributed generation and energy efficiency assets throughout the United States. In addition, WGL has a retail gas and power marketing business with approximately 222,000 customers in Maryland, Virginia, Delaware, Pennsylvania and the District of Columbia. Upon completion of the WGL Acquisition, AltaGas expects that it will have over $22 billion of assets and approximately 1.8 million rate regulated gas customers.

 

Consummation of the WGL Acquisition is subject to certain closing conditions, including certain regulatory and government approvals, including approval by the Public Service Commission of the District of Columbia (PSC of DC), the Maryland Public Service Commission (PSC of MD), the Commonwealth of Virginia State Corporation Commission (SCC of VA), the United States Federal Energy Regulatory Commission (FERC), and the Committee on Foreign Investment in the United States (CFIUS), as well as expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (HSR Act).

 

Regulatory applications were filed with the PSC of DC, the PSC of MD, and the SCC of VA on April 24, 2017. On the same date, AltaGas and WGL also filed their voluntary Joint Notice to the CFIUS, and an application with FERC. On May 10, 2017, WGL common shareholders voted in favor of the Merger Agreement governing the proposed WGL Acquisition. On July 6, 2017, FERC approved the transaction, finding it to be consistent with the public interest. Also as of July 17, 2017, when the waiting period required by Section 7A(b)(1) of the HSR Act expired, the merger was deemed approved by the Federal Trade Commission and the Department of Justice, such approval being valid for one year. On July 28, 2017, CFIUS provided its approval for the WGL Acquisition. On October 20, 2017, the SCC of VA approved the WGL Acquisition. On April 4, 2018, the PSC of MD approved the WGL Acquisition. The hearing before the PSC of DC concluded on December 13, 2017, and a decision is expected to follow in the first half of 2018. On January 11, 2018, pursuant to the terms of the Merger Agreement, AltaGas elected to extend the Outside Date (as defined in the Merger Agreement) to July 23, 2018.

 

Closing of the WGL Acquisition continues to be on track for mid-2018. AltaGas plans to fund the WGL Acquisition with the proceeds from its aggregate $2.6 billion bought deal and private placement of subscription receipts, which closed in the first quarter of 2017 (see Subscription Receipts section below). In addition, AltaGas has US$3 billion available under its fully committed bridge facility, which can be drawn at the time of closing and could remain in place for up to 12 to 18 months thereafter. With all financing in place to close the WGL Acquisition, AltaGas continues to evaluate and advance an asset monetization strategy in a prudent and timely fashion in step with the regulatory process and consistent with AltaGas’ long term strategic vision. Management expects the repayment of the bridge facility to result from the monetization of over $2 billion from its asset sales process, including the potential sale of appropriate minority interest(s) in the Northwest B.C. Hydro Facilities, and from offerings of senior debt and hybrid securities, subject to prevailing market conditions.

 

11











 

Subscription Receipts

 

On February 3, 2017, the Corporation issued approximately 80.7 million subscription receipts pursuant to a private placement and public offering to partially fund the WGL Acquisition at a price of $31 each for total gross proceeds of approximately $2.5 billion. On March 3, 2017, the over-allotment option was partially exercised for an additional 3.8 million subscription receipts for gross proceeds of approximately $118 million. The sale of the additional subscription receipts pursuant to the over-allotment option brings the aggregate gross proceeds to approximately $2.6 billion. Each subscription receipt entitles the holder to automatically receive one common share upon closing of the WGL Acquisition. While the subscription receipts remain outstanding, holders will be entitled to receive cash payments (Dividend Equivalent Payments) per subscription receipt that are equal to dividends declared on each common share. Such Dividend Equivalent Payments will have the same record date as the related common share dividend and will be paid to holders of the subscription receipts concurrently with the payment date of each such common share dividend. The Dividend Equivalent Payments will be paid first out of any interest on the escrowed funds and then out of the escrowed funds. If the Merger Agreement is terminated after the common share dividend declaration date, but before the common share dividend record date, subscription receipt holders of record on the termination date shall receive a pro-rata payment of the dividend as the Dividend Equivalent Payment. If the Merger Agreement is terminated on a record date or following a record date but on or prior to the dividend payment date, holders will be entitled to receive the full Dividend Equivalent Payment.

 

The net proceeds from the sale of the subscription receipts are held by an escrow agent pending, among other things, receipt of all regulatory and government approvals required to finalize the WGL Acquisition and confirmation that the parties to the Merger Agreement are able to complete the WGL Acquisition in all material respects in accordance with the terms of the Merger Agreement, but for the payment of the purchase price, and AltaGas has available to it all other funds required to complete the WGL Acquisition. If the escrow release notice and direction is not delivered on or prior to 5:00 pm (Calgary time) on September 4, 2018, the Corporation will be required to make a termination payment equal to the aggregate issue price of such holder’s subscription receipts plus any unpaid Dividend Equivalent Payments owing to such holders of subscription receipts.

 

4.   ASSETS HELD FOR SALE

 

In March 2018, AltaGas completed the disposition of certain non-core facilities in the Gas segment for gross proceeds of approximately $7.0 million. As a result, AltaGas recognized a pre-tax gain on disposition of approximately $1.3 million in the Consolidated Statement of Income under the line item “Other loss” for the three months ended March 31, 2018.

 

5.   INVENTORY

 

	
 
    	
 
    	
March 31,
    	
 
    	
December 31,
    	
 
    
	
As at
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Natural gas held   in storage
    	
 
    	
$
    	
68.8
    	
 
    	
$
    	
133.9
    	
 
    
	
Other inventory
    	
 
    	
69.9
    	
 
    	
67.2
    	
 
    
	
 
    	
 
    	
$
    	
138.7
    	
 
    	
$
    	
201.1
    	
 
    


 

6.   GOODWILL

 

	
 
    	
 
    	
March 31,
    	
 
    	
December 31,
    	
 
    
	
As at
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Balance,   beginning of period
    	
 
    	
$
    	
817.3
    	
 
    	
$
    	
856.0
    	
 
    
	
Foreign exchange   translation
    	
 
    	
15.2
    	
 
    	
(38.4
    	
)
    
	
Reclassified to   assets held for sale (note 4)
    	
 
    	
—
    	
 
    	
(0.3
    	
)
    
	
Balance, end of   period
    	
 
    	
$
    	
832.5
    	
 
    	
$
    	
817.3
    	
 
    


 

12











 

7.   LONG-TERM INVESTMENTS AND OTHER ASSETS

 

	
As at
    	
 
    	
March 31,
   2018
    	
 
    	
December 31,
   2017
    	
 
    
	
Investments in   publicly-traded entities
    	
 
    	
$
    	
72.8
    	
 
    	
$
    	
95.0
    	
 
    
	
Loan to   affiliate
    	
 
    	
75.0
    	
 
    	
75.0
    	
 
    
	
Deferred lease   receivable
    	
 
    	
46.6
    	
 
    	
29.0
    	
 
    
	
Debt issuance   costs associated with credit facilities
    	
 
    	
17.8
    	
 
    	
20.3
    	
 
    
	
Refundable   deposits
    	
 
    	
15.3
    	
 
    	
14.9
    	
 
    
	
Prepayment on long-term   service agreements
    	
 
    	
71.5
    	
 
    	
68.1
    	
 
    
	
Subscription   receipts issuance costs
    	
 
    	
1.8
    	
 
    	
1.7
    	
 
    
	
Other
    	
 
    	
9.6
    	
 
    	
8.6
    	
 
    
	
 
    	
 
    	
$
    	
310.4
    	
 
    	
$
    	
312.6
    	
 
    


 

8.   LONG-TERM DEBT

 

	
 
    	
 
    	
 
    	
 
    	
March 31,
    	
 
    	
December 31,
    	
 
    
	
As at
    	
 
    	
Maturity date
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Credit   facilities
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
$1,400 million   unsecured extendible revolving(a)
    	
 
    	
15-Dec-2020
    	
 
    	
$
    	
441.4
    	
 
    	
$
    	
219.1
    	
 
    
	
US$300 million   unsecured extendible revolving(b)
    	
 
    	
8-Dec-2019
    	
 
    	
—
    	
 
    	
—
    	
 
    
	
Medium-term   notes (MTNs)
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
$175 million   Senior unsecured - 4.60 percent
    	
 
    	
15-Jan-2018
    	
 
    	
—
    	
 
    	
175.0
    	
 
    
	
$200 million   Senior unsecured - 4.55 percent
    	
 
    	
17-Jan-2019
    	
 
    	
200.0
    	
 
    	
200.0
    	
 
    
	
$200 million   Senior unsecured - 4.07 percent
    	
 
    	
1-Jun-2020
    	
 
    	
200.0
    	
 
    	
200.0
    	
 
    
	
$350 million   Senior unsecured - 3.72 percent
    	
 
    	
28-Sep-2021
    	
 
    	
350.0
    	
 
    	
350.0
    	
 
    
	
$300 million   Senior unsecured - 3.57 percent
    	
 
    	
12-Jun-2023
    	
 
    	
300.0
    	
 
    	
300.0
    	
 
    
	
$200 million   Senior unsecured - 4.40 percent
    	
 
    	
15-Mar-2024
    	
 
    	
200.0
    	
 
    	
200.0
    	
 
    
	
$300 million   Senior unsecured - 3.84 percent
    	
 
    	
15-Jan-2025
    	
 
    	
299.9
    	
 
    	
299.9
    	
 
    
	
$100 million   Senior unsecured - 5.16 percent
    	
 
    	
13-Jan-2044
    	
 
    	
100.0
    	
 
    	
100.0
    	
 
    
	
$300 million   Senior unsecured - 4.50 percent
    	
 
    	
15-Aug-2044
    	
 
    	
299.8
    	
 
    	
299.8
    	
 
    
	
$350 million   Senior unsecured - 4.12 percent
    	
 
    	
7-Apr-2026
    	
 
    	
349.8
    	
 
    	
349.8
    	
 
    
	
$200 million   Senior unsecured - 3.98 percent
    	
 
    	
4-Oct-2027
    	
 
    	
199.9
    	
 
    	
199.9
    	
 
    
	
$250 million   Senior unsecured - 4.99 percent
    	
 
    	
4-Oct-2047
    	
 
    	
250.0
    	
 
    	
250.0
    	
 
    
	
SEMCO long-term   debt
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
US$300 million   SEMCO Senior secured - 5.15 percent(c)
    	
 
    	
21-Apr-2020
    	
 
    	
386.8
    	
 
    	
376.4
    	
 
    
	
US$82 million   CINGSA Senior secured - 4.48 percent(d)
    	
 
    	
2-Mar-2032
    	
 
    	
84.6
    	
 
    	
85.2
    	
 
    
	
Debenture notes
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
PNG 2018   Series Debenture - 8.75 percent(e)
    	
 
    	
15-Nov-2018
    	
 
    	
7.0
    	
 
    	
7.0
    	
 
    
	
PNG 2025   Series Debenture - 9.30 percent(e)
    	
 
    	
18-Jul-2025
    	
 
    	
13.0
    	
 
    	
13.0
    	
 
    
	
PNG 2027   Series Debenture - 6.90 percent(e)
    	
 
    	
2-Dec-2027
    	
 
    	
14.0
    	
 
    	
14.0
    	
 
    
	
CINGSA capital   lease - 3.50 percent
    	
 
    	
1-May-2040
    	
 
    	
0.5
    	
 
    	
0.5
    	
 
    
	
CINGSA capital   lease - 4.48 percent
    	
 
    	
4-Jun-2068
    	
 
    	
0.2
    	
 
    	
0.2
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
$
    	
3,696.9
    	
 
    	
$
    	
3,639.8
    	
 
    
	
Less debt   issuance costs
    	
 
    	
 
    	
 
    	
(14.4
    	
)
    	
(14.4
    	
)
    
	
 
    	
 
    	
 
    	
 
    	
3,682.5
    	
 
    	
3,625.4
    	
 
    
	
Less current   portion
    	
 
    	
 
    	
 
    	
(213.9
    	
)
    	
(188.9
    	
)
    
	
 
    	
 
    	
 
    	
 
    	
$
    	
3,468.6
    	
 
    	
$
    	
3,436.5
    	
 
    


 




(a)         Borrowings on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers’ acceptances or letters of credit. Borrowings on the facility have fees and interest at rates relevant to the nature of the draw made.

(b)         Borrowings on the facility can be by way of U.S. base-rate loans, U.S. prime loans, LIBOR loans or letters of credit.

(c)          Collateral for the US$ MTNs is certain SEMCO assets.

(d)         Collateral for the CINGSA Senior secured loan is certain CINGSA assets. Alaska Storage Holding Company, LLC, a subsidiary in which AltaGas has a controlling interest, is the non-recourse guarantor of this loan.

(e)          Collateral for the Secured Debentures consisted of a specific first mortgage on substantially all of PNG’s property, plant and equipment, and gas purchase and gas sales contracts, and a first floating charge on other property, assets and undertakings.

 

13









 

9.   ACCUMULATED OTHER COMPREHENSIVE INCOME

 

	
($ millions)
    	
 
    	
Available-
   for-sale
    	
 
    	
Defined
   benefit
   pension
   and PRB
   plans
    	
 
    	
Hedge net
   investments
    	
 
    	
Translation
   foreign
   operations
    	
 
    	
Equity
   investee
    	
 
    	
Total
    	
 
    
	
Opening   balance, January 1, 2018
    	
 
    	
$
    	
(7.1
    	
)
    	
$
    	
(11.4
    	
)
    	
$
    	
(129.0
    	
)
    	
$
    	
342.9
    	
 
    	
$
    	
3.7
    	
 
    	
$
    	
199.1
    	
 
    
	
OCI before   reclassification
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
73.2
    	
 
    	
1.3
    	
 
    	
74.5
    	
 
    
	
Amounts   reclassified from OCI
    	
 
    	
—
    	
 
    	
0.3
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
0.3
    	
 
    
	
Adoption of ASU   No. 2016-01 (note 2)
    	
 
    	
7.1
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
7.1
    	
 
    
	
Current period   OCI (pre-tax)
    	
 
    	
7.1
    	
 
    	
0.3
    	
 
    	
—
    	
 
    	
73.2
    	
 
    	
1.3
    	
 
    	
81.9
    	
 
    
	
Income tax on   amounts reclassified to earnings
    	
 
    	
—
    	
 
    	
(0.1
    	
)
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(0.1
    	
)
    
	
Net current   period OCI
    	
 
    	
7.1
    	
 
    	
0.2
    	
 
    	
—
    	
 
    	
73.2
    	
 
    	
1.3
    	
 
    	
81.8
    	
 
    
	
Ending   balance, March 31, 2018
    	
 
    	
$
    	
—
    	
 
    	
$
    	
(11.2
    	
)
    	
$
    	
(129.0
    	
)
    	
$
    	
416.1
    	
 
    	
$
    	
5.0
    	
 
    	
$
    	
280.9
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Opening balance,   January 1, 2017
    	
 
    	
$
    	
19.8
    	
 
    	
$
    	
(11.3
    	
)
    	
$
    	
(135.6
    	
)
    	
$
    	
526.3
    	
 
    	
$
    	
5.9
    	
 
    	
$
    	
405.1
    	
 
    
	
OCI before   reclassification
    	
 
    	
(17.4
    	
)
    	
—
    	
 
    	
3.0
    	
 
    	
(24.2
    	
)
    	
(1.2
    	
)
    	
(39.8
    	
)
    
	
Amounts   reclassified from OCI
    	
 
    	
—
    	
 
    	
0.2
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
0.2
    	
 
    
	
Current period   OCI (pre-tax)
    	
 
    	
(17.4
    	
)
    	
0.2
    	
 
    	
3.0
    	
 
    	
(24.2
    	
)
    	
(1.2
    	
)
    	
(39.6
    	
)
    
	
Income tax on   amounts retained in AOCI
    	
—
    	
 
    	
—
    	
 
    	
(1.6
    	
)
    	
—
    	
 
    	
—
    	
 
    	
(1.6
    	
)
    
	
Income tax on   amounts reclassified to earnings
    	
 
    	
—
    	
 
    	
(0.1
    	
)
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(0.1
    	
)
    
	
Net current   period OCI
    	
 
    	
(17.4
    	
)
    	
0.1
    	
 
    	
1.4
    	
 
    	
(24.2
    	
)
    	
(1.2
    	
)
    	
(41.3
    	
)
    
	
Ending balance,   March 31, 2017
    	
 
    	
$
    	
2.4
    	
 
    	
$
    	
(11.2
    	
)
    	
$
    	
(134.2
    	
)
    	
$
    	
502.1
    	
 
    	
$
    	
4.7
    	
 
    	
$
    	
363.8
    	
 
    


 

Reclassification From Accumulated Other Comprehensive Income

 

	
 
    	
 
    	
 
    	
 
    	
Three months ended March 31
    	
 
    
	
AOCI components reclassified
    	
 
    	
Income statement line item
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Defined benefit   pension and PRB plans
    	
 
    	
Operating and administrative expense
    	
 
    	
$
    	
0.3
    	
 
    	
$
    	
0.2
    	
 
    
	
Deferred income   taxes
    	
 
    	
Income tax expenses — deferred
    	
 
    	
(0.1
    	
)
    	
(0.1
    	
)
    
	
 
    	
 
    	
 
    	
 
    	
$
    	
0.2
    	
 
    	
$
    	
0.1
    	
 
    


 

14











 

10.   REVENUE

 

The following table disaggregates revenue by major sources for the period ended March 31, 2018:

 

	
 
    	
 
    	
Three months ended March 31, 2018
    	
 
    
	
 
    	
 
    	
Gas
    	
 
    	
Power
    	
 
    	
Utilities
    	
 
    	
Corporate
    	
 
    	
Total
    	
 
    
	
Revenue   from contracts with customers
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Commodity sales   contracts
    	
 
    	
$
    	
107.3
    	
 
    	
$
    	
—
    	
 
    	
$
    	
—
    	
 
    	
$
    	
—
    	
 
    	
$
    	
107.3
    	
 
    
	
Midstream   service contracts
    	
 
    	
49.5
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
49.5
    	
 
    
	
Gas sales and   transportation services
    	
 
    	
—
    	
 
    	
—
    	
 
    	
410.3
    	
 
    	
—
    	
 
    	
410.3
    	
 
    
	
Storage services
    	
 
    	
—
    	
 
    	
—
    	
 
    	
9.1
    	
 
    	
—
    	
 
    	
9.1
    	
 
    
	
Other
    	
 
    	
0.6
    	
 
    	
—
    	
 
    	
2.9
    	
 
    	
—
    	
 
    	
3.5
    	
 
    
	
Total   revenue from contracts with customers
    	
 
    	
$
    	
157.4
    	
 
    	
$
    	
—
    	
 
    	
$
    	
422.3
    	
 
    	
$
    	
—
    	
 
    	
$
    	
579.7
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Other   sources of revenue
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Revenue from   alternative revenue programs (a)
    	
 
    	
$
    	
—
    	
 
    	
$
    	
—
    	
 
    	
$
    	
(5.1
    	
)
    	
$
    	
—
    	
 
    	
$
    	
(5.1
    	
)
    
	
Leasing revenue (b)
    	
 
    	
24.0
    	
 
    	
67.2
    	
 
    	
—
    	
 
    	
—
    	
 
    	
91.2
    	
 
    
	
Risk management   contracts gains (losses)
    	
 
    	
130.5
    	
 
    	
75.8
    	
 
    	
1.2
    	
 
    	
(0.6
    	
)
    	
206.9
    	
 
    
	
Other
    	
 
    	
(0.1
    	
)
    	
2.8
    	
 
    	
3.0
    	
 
    	
—
    	
 
    	
5.7
    	
 
    
	
Total   revenue from other sources
    	
 
    	
$
    	
154.4
    	
 
    	
$
    	
145.8
    	
 
    	
$
    	
(0.9
    	
)
    	
$
    	
(0.6
    	
)
    	
$
    	
298.7
    	
 
    
	
Total   revenue
    	
 
    	
$
    	
311.8
    	
 
    	
$
    	
145.8
    	
 
    	
$
    	
421.4
    	
 
    	
$
    	
(0.6
    	
)
    	
$
    	
878.4
    	
 
    


 




(a)         A large portion of revenue generated from the Utilities segment is subject to rate regulation and accordingly there are circumstances where the revenue recognized is mandated by the applicable regulators in accordance with ASC 980.

(b)         Revenue generated from certain of AltaGas’ gas facilities are accounted for as operating leases. For the Power segment, the majority of revenue earned is through power purchase agreements which are accounted for as operating leases.

 

Revenue Recognition

 

The following is a description of the Corporation’s revenue recognition policy by major sources of revenue from contracts with customers and segment.

 

Gas segment

 

Commodity sales

 

A portion of the NGL production from AltaGas’ extraction facilities is subject to frac spread between NGLs extracted and the natural gas purchased to make up the heating value of the NGLs extracted. For commodity sales contracts that do not meet the definition of a derivative or for contracts whereby AltaGas has elected to apply the normal purchase normal sales scope exception, the sales contract is accounted for under ASC 606. These commodity sales contracts have varying terms but the majority of the contracts have a one-year term which coincides with the NGL year. AltaGas recognizes revenue for commodity sales contracts at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount.

 

Midstream service contracts

 

AltaGas earns revenue from its field gathering and processing facilities, extraction facilities, and transmission systems through a variety of contractual arrangements. For arrangements that do not contain a lease, the revenue is accounted for under ASC 606 as follows:

 

Fee-for-service — The customer is charged a fee for the service provided on a per unit volume basis. Contract terms generally range from one month to up to the life of the reserves. Revenue under this type of arrangement is recognized over time as the service is provided, which corresponds to the customer’s monthly invoice amount.

 

Take-or-pay — The customer has agreed to a minimum volume commitment whereby the customer must have AltaGas process or deliver a specified volume at a rate per unit that is specified in the contract. Quantities that the customer is unable to deliver are considered deficiency quantities. Certain of AltaGas’ take-or-pay contracts contain provisions whereby the customer can make

 

15











 

up deficiency quantities in subsequent periods. Under this type of arrangement, any consideration received relating to the deficiency quantities that will be made up in a future period will be deferred until either: (i) the customer makes up the volumes or (ii) the likelihood that the customer will make up the volumes before the make up period expires become remote. If AltaGas does not expect the customer to make up the deficiency quantities (also referred to as breakage amount), AltaGas may recognize the expected breakage amount as revenue before the make up period expires. Significant judgment is required in estimating the breakage amount. For contracts where the customer has no make up rights, revenue is recognized on a monthly basis based on the higher of (i) the actual quantity delivered times the per unit rate or (ii) the contracted minimum amount. As at March 31, 2018, AltaGas did not recognize any contract liabilities or assets related to its take-or-pay contracts.

 

Power segment

 

For the Power segment, the majority of revenue earned is through power purchase agreements which are accounted for as operating leases. In instances where power generation is not sold under a power purchase agreement, the commodity is sold via a merchant market, or via commodity sales agreements which are accounted for as financial instruments.

 

Utilities segment

 

Gas sales and transportation services

 

Customers are billed monthly based on regular meter readings. Customer billings are based on two main components: (i) a fixed service fee and (ii) a variable fee based on usage. Revenue is recognized over time when the gas has been delivered or as the service has been performed. As meter readings are performed on a cycle basis, AltaGas recognizes accrued revenue for any services rendered to its customers but not billed at month-end. The vast majority of these contracts have a term of one-month, however, there are certain contracts that have terms of one year or longer. For these long-term contracts, there is generally a contract demand specified in the contract whereby the customer has to pay regardless of whether or not gas has been delivered. These contracts generally do not contain any make up rights and revenue is recognized on a monthly basis as service has been performed.

 

Gas storage services

 

Gas storage customers are billed monthly for services provided. Customer billings are based on four components: (i) reservation charges; (ii) capacity charges; (iii) injection/withdrawal charges; and (iv) excess charges. Reservation charges are based on the customer’s contract withdrawal quantity, capacity charges are based on the customer’s total contract quantity, and injection/withdrawal charges are based on the volume of gas delivered to or from the customer. Excess charges are applied to each day that the storage quantity exceeds 100 percent of the customer’s maximum storage quantity. Revenue is recognized as the service has been performed over time on a monthly basis, which corresponds to the invoice amount. The majority of these contracts have terms extending beyond one-year.

 

Transaction price allocated to the remaining obligations

 

The following table includes estimated revenue expected to be recognized in the future related to performance obligations that are unsatisfied as of March 31, 2018:

 

	
 
    	
 
    	
Remainder
   of 2018
    	
 
    	
2019
    	
 
    	
2020
    	
 
    	
2021
    	
 
    	
2022
    	
 
    	
> 2022
    	
 
    	
Total
    	
 
    
	
Midstream   service contracts
    	
 
    	
$
    	
36.0
    	
 
    	
$
    	
46.1
    	
 
    	
$
    	
43.1
    	
 
    	
$
    	
3.4
    	
 
    	
$
    	
3.0
    	
 
    	
$
    	
—
    	
 
    	
$
    	
131.6
    	
 
    
	
Gas sales and   transportation services
    	
 
    	
14.5
    	
 
    	
18.9
    	
 
    	
17.1
    	
 
    	
16.2
    	
 
    	
15.7
    	
 
    	
29.8
    	
 
    	
112.2
    	
 
    
	
Storage services
    	
 
    	
20.7
    	
 
    	
26.9
    	
 
    	
26.6
    	
 
    	
26.6
    	
 
    	
26.6
    	
 
    	
246.4
    	
 
    	
373.8
    	
 
    
	
Other
    	
 
    	
0.8
    	
 
    	
1.1
    	
 
    	
1.1
    	
 
    	
1.1
    	
 
    	
1.1
    	
 
    	
3.0
    	
 
    	
8.2
    	
 
    
	
 
    	
 
    	
$
    	
72.0
    	
 
    	
$
    	
93.0
    	
 
    	
$
    	
87.9
    	
 
    	
$
    	
47.3
    	
 
    	
$
    	
46.4
    	
 
    	
$
    	
279.2
    	
 
    	
$
    	
625.8
    	
 
    


 

16











 

AltaGas applies the practical expedient available under ASC 606 and does not disclose information about the remaining performance obligations for (i) contracts with an original expected length of one year or less, (ii) contracts for which revenue is recognized at the amount to which AltaGas has the right to invoice for performance completed, and (iii) contracts with variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation. In addition, the table above does not include any estimated amounts of variable consideration that are constrained. The majority of midstream service contracts, gas sales and transportation service contracts, and storage service contracts contain variable consideration whereby uncertainty related to the associated variable consideration will be resolved (usually on a daily basis) as volumes are processed, gas is delivered or as service is provided.

 

11.   FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT

 

The Corporation’s financial instruments consist of cash and cash equivalents, accounts receivable, risk management contracts, certain long-term investments and other assets, accounts payable and accrued liabilities, dividends payable, short-term and long-term debt and certain other current and long-term liabilities.

 

Fair Value Hierarchy

 

AltaGas categorizes its financial assets and financial liabilities into one of three levels based on fair value measurements and inputs used to determine the fair value.

 

Level 1 - fair values are based on unadjusted quoted prices in active markets for identical assets or liabilities. Fair values are based on direct observations of transactions involving the same assets or liabilities and no assumptions are used. Included in this category are publicly traded shares valued at the closing price as at the balance sheet date.

 

Level 2 - fair values are determined based on valuation models and techniques where inputs other than quoted prices included within level 1 are observable for the asset or liability either directly or indirectly. AltaGas uses over-the-counter derivative instruments to manage fluctuations in commodity prices and foreign exchange rates. The fair values of power, natural gas and NGL derivative contracts were calculated using forward prices from published sources for the relevant period, adjusted for factors specific to the asset or liability, including basis and location differentials, discount rates, and currency exchange. The fair value of foreign exchange derivative contracts was calculated using quoted market rates. The fair value of foreign exchange option contracts was calculated using a variation of the Black-Scholes pricing model.

 

Level 3 - fair values are based on inputs for the asset or liability that are not based on observable market data. AltaGas uses valuation techniques when observable market data is not available.

 

17











 

	
 
    	
 
    	
March 31, 2018
    	
 
    
	
 
    	
 
    	
Carrying
   Amount
    	
 
    	
Level 1
    	
 
    	
Level 2
    	
 
    	
Level 3
    	
 
    	
Total
   Fair Value
    	
 
    
	
Financial assets
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Fair value   through net income
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Risk management   assets - current
    	
 
    	
$
    	
27.7
    	
 
    	
$
    	
—
    	
 
    	
$
    	
27.7
    	
 
    	
$
    	
—
    	
 
    	
$
    	
27.7
    	
 
    
	
Risk management   assets - non-current
    	
 
    	
15.3
    	
 
    	
—
    	
 
    	
15.3
    	
 
    	
—
    	
 
    	
15.3
    	
 
    
	
Equity   securities(a)
    	
 
    	
80.4
    	
 
    	
80.4
    	
 
    	
—
    	
 
    	
—
    	
 
    	
80.4
    	
 
    
	
Amortized cost
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Loans and   receivables (a)
    	
 
    	
75.0
    	
 
    	
—
    	
 
    	
76.8
    	
 
    	
—
    	
 
    	
76.8
    	
 
    
	
 
    	
 
    	
$
    	
198.4
    	
 
    	
$
    	
80.4
    	
 
    	
$
    	
119.8
    	
 
    	
$
    	
—
    	
 
    	
$
    	
200.2
    	
 
    
	
Financial   liabilities
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Fair value   through net income
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Risk management   liabilities - current
    	
 
    	
$
    	
48.7
    	
 
    	
$
    	
—
    	
 
    	
$
    	
48.7
    	
 
    	
$
    	
—
    	
 
    	
$
    	
48.7
    	
 
    
	
Risk management   liabilities - non-current
    	
 
    	
13.6
    	
 
    	
—
    	
 
    	
13.6
    	
 
    	
—
    	
 
    	
13.6
    	
 
    
	
Amortized cost
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Current portion   of long-term debt
    	
 
    	
213.9
    	
 
    	
—
    	
 
    	
217.8
    	
 
    	
—
    	
 
    	
217.8
    	
 
    
	
Long-term debt
    	
 
    	
3,468.6
    	
 
    	
—
    	
 
    	
3,534.1
    	
 
    	
—
    	
 
    	
3,534.1
    	
 
    
	
Other current liabilities (b)
    	
 
    	
13.8
    	
 
    	
—
    	
 
    	
14.0
    	
 
    	
—
    	
 
    	
14.0
    	
 
    
	
Other long-term   liabilities (b) 
    	
 
    	
147.8
    	
 
    	
—
    	
 
    	
146.7
    	
 
    	
—
    	
 
    	
146.7
    	
 
    
	
 
    	
 
    	
$
    	
3,906.4
    	
 
    	
$
    	
—
    	
 
    	
$
    	
3,974.9
    	
 
    	
$
    	
—
    	
 
    	
$
    	
3,974.9
    	
 
    


 




(a)         Included under the line items “Prepaid expenses and other current assets” and “Long-term investments and other assets” on the Consolidated Balance Sheet.

(b)         Excludes non-financial liabilities.

 

	
 
    	
 
    	
December 31, 2017
    	
 
    
	
 
    	
 
    	
Carrying
   Amount
    	
 
    	
Level 1
    	
 
    	
Level 2
    	
 
    	
Level 3
    	
 
    	
Total
   Fair Value
    	
 
    
	
Financial assets
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Fair value   through net income
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Risk management   assets - current
    	
 
    	
$
    	
38.6
    	
 
    	
$
    	
—
    	
 
    	
$
    	
38.6
    	
 
    	
$
    	
—
    	
 
    	
$
    	
38.6
    	
 
    
	
Risk management   assets - non-current
    	
 
    	
15.9
    	
 
    	
—
    	
 
    	
15.9
    	
 
    	
—
    	
 
    	
15.9
    	
 
    
	
Equity   securities(a)
    	
 
    	
95.0
    	
 
    	
95.0
    	
 
    	
—
    	
 
    	
—
    	
 
    	
95.0
    	
 
    
	
Amortized cost
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Loans and   receivables (a)
    	
 
    	
75.0
    	
 
    	
—
    	
 
    	
85.6
    	
 
    	
—
    	
 
    	
85.6
    	
 
    
	
 
    	
 
    	
$
    	
224.5
    	
 
    	
$
    	
95.0
    	
 
    	
$
    	
140.1
    	
 
    	
$
    	
—
    	
 
    	
$
    	
235.1
    	
 
    
	
Financial   liabilities
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Fair value   through net income
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Risk management   liabilities - current
    	
 
    	
$
    	
57.6
    	
 
    	
$
    	
—
    	
 
    	
$
    	
57.6
    	
 
    	
$
    	
—
    	
 
    	
$
    	
57.6
    	
 
    
	
Risk management   liabilities - non-current
    	
 
    	
13.8
    	
 
    	
—
    	
 
    	
13.8
    	
 
    	
—
    	
 
    	
13.8
    	
 
    
	
Amortized cost
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Current portion   of long-term debt
    	
 
    	
188.9
    	
 
    	
—
    	
 
    	
189.6
    	
 
    	
—
    	
 
    	
189.6
    	
 
    
	
Long-term debt
    	
 
    	
3,436.5
    	
 
    	
—
    	
 
    	
3,568.3
    	
 
    	
—
    	
 
    	
3,568.3
    	
 
    
	
Other current   liabilities   (b)
    	
 
    	
22.4
    	
 
    	
—
    	
 
    	
22.4
    	
 
    	
—
    	
 
    	
22.4
    	
 
    
	
Other long-term   liabilities (b) 
    	
 
    	
146.0
    	
 
    	
—
    	
 
    	
147.7
    	
 
    	
—
    	
 
    	
147.7
    	
 
    
	
 
    	
 
    	
$
    	
3,865.2
    	
 
    	
$
    	
—
    	
 
    	
$
    	
3,999.4
    	
 
    	
$
    	
—
    	
 
    	
$
    	
3,999.4
    	
 
    


 




(a)         Included under the line item “Long-term investments and other assets” on the Consolidated Balance Sheet.

(b)         Excludes non-financial liabilities.

 

18











 

Summary of Unrealized Gains (Losses) on Risk Management Contracts Recognized in Net Income

 

	
Three months ended March 31
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Natural gas
    	
 
    	
$
    	
(5.8
    	
)
    	
$
    	
(1.8
    	
)
    
	
Storage optimization
    	
 
    	
—
    	
 
    	
2.4
    	
 
    
	
NGL frac spread
    	
 
    	
11.0
    	
 
    	
7.5
    	
 
    
	
Power
    	
 
    	
(3.4
    	
)
    	
(0.4
    	
)
    
	
Foreign exchange
    	
 
    	
(1.2
    	
)
    	
(6.8
    	
)
    
	
 
    	
 
    	
$
    	
0.6
    	
 
    	
$
    	
0.9
    	
 
    


 

Offsetting of Derivative Assets and Derivative Liabilities

 

Certain AltaGas risk management contracts are subject to master netting arrangements that create a legally enforceable right to offset by counterparty. The following is a summary of AltaGas’ financial assets and financial liabilities that were subject to offsetting:

 

	
 
    	
 
    	
March 31, 2018
    	
 
    
	
Risk management assets (a)
    	
 
    	
Gross amounts of
   recognized
   assets/liabilities
    	
 
    	
Gross amounts
   offset in
   balance sheet
    	
 
    	
Net amounts
   presented in
   balance sheet
    	
 
    
	
Natural gas
    	
 
    	
$
    	
23.4
    	
 
    	
$
    	
(2.1
    	
)
    	
$
    	
21.3
    	
 
    
	
NGL frac spread
    	
 
    	
2.9
    	
 
    	
(0.6
    	
)
    	
2.3
    	
 
    
	
Power
    	
 
    	
19.3
    	
 
    	
(0.4
    	
)
    	
18.9
    	
 
    
	
Foreign exchange
    	
 
    	
0.5
    	
 
    	
—
    	
 
    	
0.5
    	
 
    
	
 
    	
 
    	
$
    	
46.1
    	
 
    	
$
    	
(3.1
    	
)
    	
$
    	
43.0
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Risk management   liabilities (b)
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Natural gas
    	
 
    	
$
    	
23.5
    	
 
    	
$
    	
(2.2
    	
)
    	
$
    	
21.3
    	
 
    
	
NGL frac spread
    	
 
    	
15.9
    	
 
    	
(0.5
    	
)
    	
15.4
    	
 
    
	
Power
    	
 
    	
26.0
    	
 
    	
(0.4
    	
)
    	
25.6
    	
 
    
	
 
    	
 
    	
$
    	
65.4
    	
 
    	
$
    	
(3.1
    	
)
    	
$
    	
62.3
    	
 
    


 




(a)         Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $27.7 million and risk management assets (non-current) balance of $15.3 million.

(b)         Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $48.7 million and risk management liabilities (non-current) balance of $13.6 million.

 

	
 
    	
 
    	
December 31, 2017
    	
 
    
	
Risk management assets (a)
    	
 
    	
Gross amounts of
   recognized
   assets/liabilities
    	
 
    	
Gross amounts
   offset in
   balance sheet
    	
 
    	
Net amounts
   presented in
   balance sheet
    	
 
    
	
Natural gas
    	
 
    	
$
    	
41.0
    	
 
    	
$
    	
(6.2
    	
)
    	
$
    	
34.8
    	
 
    
	
NGL frac spread
    	
 
    	
1.3
    	
 
    	
(0.3
    	
)
    	
1.0
    	
 
    
	
Power
    	
 
    	
17.7
    	
 
    	
(0.7
    	
)
    	
17.0
    	
 
    
	
Foreign exchange
    	
 
    	
1.7
    	
 
    	
—
    	
 
    	
1.7
    	
 
    
	
 
    	
 
    	
$
    	
61.7
    	
 
    	
$
    	
(7.2
    	
)
    	
$
    	
54.5
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Risk management   liabilities (b)
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Natural gas
    	
 
    	
$
    	
35.1
    	
 
    	
$
    	
(6.2
    	
)
    	
$
    	
28.9
    	
 
    
	
NGL frac spread
    	
 
    	
25.3
    	
 
    	
(0.3
    	
)
    	
25.0
    	
 
    
	
Power
    	
 
    	
18.2
    	
 
    	
(0.7
    	
)
    	
17.5
    	
 
    
	
 
    	
 
    	
$
    	
78.6
    	
 
    	
$
    	
(7.2
    	
)
    	
$
    	
71.4
    	
 
    


 




(a)         Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $38.6 million and risk management assets (non-current) balance of $15.9 million.

(b)         Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $57.6 million and risk management liabilities (non-current) balance of $13.8 million.

 

19









 

Notional Summary

 

The following table presents the notional quantity outstanding related to the Corporation’s commodity contracts:

 

	
 
    	
 
    	
March 31, 2018
    	
 
    	
December 31, 2017
    	
 
    
	
Natural   Gas
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Sales
    	
 
    	
110,807,671 GJ
    	
 
    	
94,804,039 GJ
    	
 
    
	
Purchases
    	
 
    	
44,077,028 GJ
    	
 
    	
61,980,315 GJ
    	
 
    
	
Swaps
    	
 
    	
1,181,710 GJ
    	
 
    	
6,039,642 GJ
    	
 
    
	
NGL   Frac Spread
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Propane swaps
    	
 
    	
1,748,430 Bbl
    	
 
    	
1,992,927 Bbl
    	
 
    
	
Butane swaps
    	
 
    	
56,101 Bbl
    	
 
    	
130,088 Bbl
    	
 
    
	
Crude oil swaps
    	
 
    	
390,775 Bbl
    	
 
    	
518,665 Bbl
    	
 
    
	
Natural gas   swaps
    	
 
    	
8,610,525 GJ
    	
 
    	
11,428,515 GJ
    	
 
    
	
Power
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Sales
    	
 
    	
2,193,944 MWh
    	
 
    	
2,169,321 MWh
    	
 
    
	
Purchases
    	
 
    	
320,452 MWh
    	
 
    	
17,520 MWh
    	
 
    
	
Swaps
    	
 
    	
1,334,221 MWh
    	
 
    	
1,563,160 MWh
    	
 
    


 

Foreign Exchange

 

AltaGas may designate its U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. As at March 31, 2018, AltaGas has not designated any outstanding debt as a net investment hedge. For the three months ended March 31, 2018, AltaGas incurred an after-tax unrealized gain of $nil arising from the translation of debt in OCI (2017 - after-tax unrealized gain of $1.4 million).

 

In addition, to mitigate the foreign exchange risks associated with the cash purchase price of WGL, AltaGas has entered into foreign currency option contracts with an aggregate notional value of US$1.2 billion. These foreign currency option contracts do not qualify for hedge accounting. Therefore, all changes in fair value are recognized in net income. For the three months ended March 31, 2018, an unrealized loss of $1.2 million was recognized in revenue in relation to these contracts (2017 — unrealized loss of $6.4 million).

 

12.   SHAREHOLDERS’ EQUITY

 

Authorization

 

AltaGas is authorized to issue an unlimited number of voting common shares. AltaGas is also authorized to issue preferred shares not to exceed 50 percent of the voting rights attached to the issued and outstanding common shares.

 

Premium DividendTM, Dividend Reinvestment and Optional Cash Purchase Plan (DRIP or the Plan)

 

The Plan consists of three components: a Premium DividendTM component, a Dividend Reinvestment component and an Optional Cash Purchase component.

 

The Plan provides eligible holders of common shares with the opportunity to, at their election, either: (1) reinvest the cash dividends paid by AltaGas on their common shares towards the purchase of new common shares at a 3 percent discount to the average market price (as defined below) of the common shares on the applicable dividend payment date (the Dividend Reinvestment component of the Plan); or (2) reinvest the cash dividends paid by AltaGas on their common shares towards the purchase of new common shares at a 3 percent discount to the average market price (as defined below) on the applicable dividend payment date and have these additional common shares of AltaGas exchanged for a cash payment equal to 101 percent of the reinvested amount (the Premium DividendTM component of the Plan).

 

In addition, the Plan provides shareholders who are enrolled in the Dividend Reinvestment component of the Plan with the opportunity to purchase new common shares at the average market price (with no discount) on the applicable dividend payment date (the Optional Cash Purchase component of the Plan).

 




TM Denotes trademark of Canaccord Genuity Corp.

 

20











 

Each of the components of the Plan are subject to prorating and other limitations on availability of new common shares in certain events. The “average market price”, in respect of a particular dividend payment date, refers to the arithmetic average (calculated to four decimal places) of the daily volume weighted average trading prices of common shares on the Toronto Stock Exchange for the trading days on which at least one board lot of common shares is traded during the 10 business days immediately preceding the applicable dividend payment date. Such trading prices will be appropriately adjusted for certain capital changes (including common share subdivisions, common share consolidations, certain rights offerings and certain dividends). Shareholders resident outside of Canada are not entitled to participate in the Premium DividendTM component of the Plan. Shareholders resident outside of Canada (other than the U.S.) may participate in the Dividend Reinvestment component or the Optional Cash Purchase component of the Plan only if their participation is permitted by the laws of the jurisdiction in which they reside and provided that AltaGas is satisfied in its sole discretion, that such laws do not subject the Plan or AltaGas to additional legal or regulatory requirements.

 

	
Common Shares Issued and Outstanding
    	
 
    	
Number of
   shares
    	
 
    	
Amount
    	
 
    
	
January 1,   2017
    	
 
    	
166,906,833
    	
 
    	
$
    	
3,773.4
    	
 
    
	
Shares issued   for cash on exercise of options
    	
 
    	
240,125
    	
 
    	
6.5
    	
 
    
	
Deferred taxes   on share issuance cost
    	
 
    	
—
    	
 
    	
(8.3
    	
)
    
	
Shares issued   under DRIP
    	
 
    	
8,132,258
    	
 
    	
236.3
    	
 
    
	
December 31,   2017
    	
 
    	
175,279,216
    	
 
    	
4,007.9
    	
 
    
	
Shares issued   for cash on exercise of options
    	
 
    	
24,875
    	
 
    	
0.6
    	
 
    
	
Shares issued   under DRIP
    	
 
    	
2,577,178
    	
 
    	
65.9
    	
 
    
	
Issued   and outstanding at March 31, 2018
    	
 
    	
177,881,269
    	
 
    	
$
    	
4,074.4
    	
 
    


 

Preferred Shares

 

	
As at
    	
 
    	
March 31, 2018
    	
 
    	
December 31, 2017
    	
 
    
	
Issued and Outstanding
    	
 
    	
Number of shares
    	
 
    	
Amount
    	
 
    	
Number of shares
    	
 
    	
Amount
    	
 
    
	
Series A
    	
 
    	
5,511,220
    	
 
    	
$
    	
137.8
    	
 
    	
5,511,220
    	
 
    	
$
    	
137.8
    	
 
    
	
Series B
    	
 
    	
2,488,780
    	
 
    	
62.2
    	
 
    	
2,488,780
    	
 
    	
62.2
    	
 
    
	
Series C
    	
 
    	
8,000,000
    	
 
    	
205.6
    	
 
    	
8,000,000
    	
 
    	
205.6
    	
 
    
	
Series E
    	
 
    	
8,000,000
    	
 
    	
200.0
    	
 
    	
8,000,000
    	
 
    	
200.0
    	
 
    
	
Series G
    	
 
    	
8,000,000
    	
 
    	
200.0
    	
 
    	
8,000,000
    	
 
    	
200.0
    	
 
    
	
Series I
    	
 
    	
8,000,000
    	
 
    	
200.0
    	
 
    	
8,000,000
    	
 
    	
200.0
    	
 
    
	
Series K
    	
 
    	
12,000,000
    	
 
    	
300.0
    	
 
    	
12,000,000
    	
 
    	
300.0
    	
 
    
	
Share issuance   costs, net of taxes
    	
 
    	
 
    	
 
    	
(27.9
    	
)
    	
 
    	
 
    	
(27.9
    	
)
    
	
 
    	
 
    	
52,000,000
    	
 
    	
$
    	
1,277.7
    	
 
    	
52,000,000
    	
 
    	
$
    	
1,277.7
    	
 
    


 

Share Option Plan

 

AltaGas has an employee share option plan under which employees and directors are eligible to receive grants. As at March 31, 2018, 13,285,741 shares were reserved for issuance under the plan. As at March 31, 2018, share options granted under the plan have a term between six and ten years until expiry and vest no longer than over a four-year period.

 

As at March 31, 2018, unexpensed fair value of share option compensation cost associated with future periods was $1.0 million (December 31, 2017 - $1.3 million).

 




TM Denotes trademark of Canaccord Genuity Corp.

 

21











 

The following table summarizes information about the Corporation’s share options:

 

	
 
    	
 
    	
March 31, 2018
    	
 
    	
December 31, 2017
    	
 
    
	
 
    	
 
    	
Options outstanding
    	
 
    	
Options outstanding
    	
 
    
	
As at
    	
 
    	
Number of
   options
    	
 
    	
Exercise
   price(a)
    	
 
    	
Number of
   options
    	
 
    	
Exercise
   price(a)
    	
 
    
	
Share options   outstanding, beginning of period
    	
 
    	
4,533,761
    	
 
    	
$
    	
32.35
    	
 
    	
4,119,386
    	
 
    	
$
    	
32.39
    	
 
    
	
Granted
    	
 
    	
—
    	
 
    	
—
    	
 
    	
848,000
    	
 
    	
30.80
    	
 
    
	
Exercised
    	
 
    	
(24,875
    	
)
    	
23.26
    	
 
    	
(240,125
    	
)
    	
24.63
    	
 
    
	
Forfeited
    	
 
    	
(6,500
    	
)
    	
30.14
    	
 
    	
(193,500
    	
)
    	
36.36
    	
 
    
	
Share   options outstanding, end of period
    	
 
    	
4,502,386
    	
 
    	
$
    	
32.40
    	
 
    	
4,533,761
    	
 
    	
$
    	
32.35
    	
 
    
	
Share   options exercisable, end of period
    	
 
    	
3,509,947
    	
 
    	
$
    	
32.05
    	
 
    	
3,326,197
    	
 
    	
$
    	
31.93
    	
 
    


 




(a)         Weighted average.

 

As at March 31, 2018, the aggregate intrinsic value of the total share options exercisable was $2.7 million (December 31, 2017 - $6.0 million), the total intrinsic value of share options outstanding was $2.7 million (December 31, 2017 - $6.0 million) and the total intrinsic value of share options exercised was $0.1 million (December 31, 2017 - $1.4 million).

 

The following table summarizes the employee share option plan as at March 31, 2018:

 

	
 
    	
 
    	
Options outstanding
    	
 
    	
Options exercisable
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
Weighted
    	
 
    	
Weighted average
    	
 
    	
 
    	
 
    	
Weighted
    	
 
    	
Weighted average
    	
 
    
	
 
    	
 
    	
Number
    	
 
    	
average
    	
 
    	
remaining
    	
 
    	
Number
    	
 
    	
average
    	
 
    	
remaining
    	
 
    
	
 
    	
 
    	
outstanding
    	
 
    	
exercise price
    	
 
    	
contractual life
    	
 
    	
exercisable
    	
 
    	
exercise price
    	
 
    	
contractual life
    	
 
    
	
$14.24 to $18.00
    	
 
    	
157,750
    	
 
    	
$
    	
15.22
    	
 
    	
1.05
    	
 
    	
157,750
    	
 
    	
$
    	
15.22
    	
 
    	
1.05
    	
 
    
	
$18.01 to $25.08
    	
 
    	
454,600
    	
 
    	
20.75
    	
 
    	
2.58
    	
 
    	
454,600
    	
 
    	
20.75
    	
 
    	
2.58
    	
 
    
	
$25.09 to $50.89
    	
 
    	
3,890,036
    	
 
    	
34.46
    	
 
    	
3.79
    	
 
    	
2,897,597
    	
 
    	
34.74
    	
 
    	
3.58
    	
 
    
	
 
    	
 
    	
4,502,386
    	
 
    	
$
    	
32.40
    	
 
    	
3.57
    	
 
    	
3,509,947
    	
 
    	
$
    	
32.05
    	
 
    	
3.34
    	
 
    


 

Medium Term Incentive Plan (MTIP) and Deferred Share Unit Plan (DSUP)

 

AltaGas has a MTIP for employees and executive officers, which includes restricted units (RUs) and performance units (PUs) with vesting periods between 36 to 44 months from the grant date. In addition, AltaGas has a DSUP, which allows granting of deferred share units (DSUs) to directors. DSUs granted under the DSUP vest immediately but settlement of the DSUs occur when the individual ceases to be a director.

 

	
PUs, RUs, and DSUs
    	
 
    	
March 31, 2018
    	
 
    	
December 31, 2017
    	
 
    
	
(number of units)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Balance,   beginning of period
    	
 
    	
564,549
    	
 
    	
364,839
    	
 
    
	
Granted
    	
 
    	
9,922
    	
 
    	
386,126
    	
 
    
	
Additional units   added by performance factor
    	
 
    	
—
    	
 
    	
24,301
    	
 
    
	
Vested and paid   out
    	
 
    	
(26,018
    	
)
    	
(221,775
    	
)
    
	
Forfeited
    	
 
    	
(1,149
    	
)
    	
(27,279
    	
)
    
	
Units in lieu of   dividends
    	
 
    	
11,552
    	
 
    	
38,337
    	
 
    
	
Outstanding, end   of period
    	
 
    	
558,856
    	
 
    	
564,549
    	
 
    


 

For the three months ended March 31, 2018, the compensation expense recorded for the MTIP and DSUP was $0.2 million (2017 — $1.4 million). As at March 31, 2018, the unrecognized compensation expense relating to the remaining vesting period for the MTIP was $7.7 million (December 31, 2017 - $8.4 million) and is expected to be recognized over the vesting period.

 

22











 

13.   NET INCOME PER COMMON SHARE

 

The following table summarizes the computation of net income per common share:

 

	
Three months ended March 31
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Numerator:
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Net income   applicable to controlling interests
    	
 
    	
$
    	
65.2
    	
 
    	
$
    	
45.4
    	
 
    
	
Less: Preferred   share dividends
    	
 
    	
(16.4
    	
)
    	
(13.6
    	
)
    
	
Net income   applicable to common shares
    	
 
    	
$
    	
48.8
    	
 
    	
$
    	
31.8
    	
 
    
	
Denominator:
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
(millions)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Weighted average   number of common shares outstanding
    	
 
    	
176.5
    	
 
    	
167.9
    	
 
    
	
Dilutive equity   instruments(a)
    	
 
    	
0.1
    	
 
    	
0.4
    	
 
    
	
Weighted average   number of common shares outstanding - diluted
    	
 
    	
176.6
    	
 
    	
168.3
    	
 
    
	
Basic net income   per common share
    	
 
    	
$
    	
0.28
    	
 
    	
$
    	
0.19
    	
 
    
	
Diluted net   income per common share
    	
 
    	
$
    	
0.28
    	
 
    	
$
    	
0.19
    	
 
    


 




(a)         Includes all options that have a strike price lower than the average share price of AltaGas’ common shares during the periods noted.

 

For the three months ended March 31, 2018, 1.3 million of share options (2017 — 2.1 million) were excluded from the diluted net income per share calculation as their effects were anti-dilutive.

 

14.   COMMITMENTS, CONTINGENCIES AND GUARANTEES

 

Commitments

 

AltaGas has long-term natural gas purchase and transportation arrangements, service agreements, storage contracts and operating leases for office space, office equipment, rail cars, and automobile equipment, all of which are transacted at market prices and in the normal course of business.

 

AltaGas enters into contracts to purchase natural gas and natural gas transportation and storage services from various suppliers for its utilities. These contracts, which have expiration dates that range from 2018 to 2033, are used to ensure that there is an adequate supply of natural gas to meet the needs of customers and to minimize exposure to market price fluctuations.

 

In 2017, AltaGas entered into a 12-year service agreement for tug services to support the marine operations of RIPET. AltaGas is obligated to pay fixed and variable fees of approximately $60.1 million over the term of the contract.

 

In 2014, AltaGas’ Blythe facility entered into a Long-Term Service Agreement with Siemens to complete various upgrade and maintenance services on the Combustion Turbines (CT) at Blythe. The term of the agreement is over 124,000 equivalent operating hours per CT, or 25 years, whichever comes first. As at March 31, 2018, approximately $202.0 million is expected to be paid over the next 19 years, of which $56.7 million is expected to be paid over the next five years.

 

In 2009, AltaGas entered into a 20-year storage agreement at the Dawn Hub in southwestern Ontario. AltaGas is obligated to pay approximately $3.5 million per annum over the term of the contract for storage services.

 

In 2007, AltaGas entered into a service and maintenance agreement with Enercon GmbH for the wind turbines for Bear Mountain. AltaGas has an obligation to pay a minimum of $8.1 million over the next four years.

 

Guarantees

 

In October 2014, Heritage Gas Limited, a wholly-owned subsidiary of AltaGas, entered into a throughput service contract with Enbridge Inc. (formerly Spectra Energy Corp.) for the use of the expansion of its Algonquin Gas Transmission and Maritimes & Northeast Pipeline systems (the Atlantic Bridge Project). The contract will commence upon completion of the construction of the

 

23











 

pipelines and it will expire 15 years thereafter. AltaGas has two guarantees outstanding that total US$91.7 million to stand by all payment obligations under the transportation agreement.

 

Contingencies

 

AltaGas and its subsidiaries are subject to various legal claims and actions arising in the normal course of business. While the final outcome of such legal claims and actions cannot be predicted with certainty, the Corporation does not believe that the resolution of such claims and actions will have a material impact on the Corporation’s consolidated financial position or results of operations.

 

15.   PENSION PLANS AND RETIREE BENEFITS

 

The costs of the defined benefit and post-retirement benefit plans are based on management’s estimate of the future rate of return on the fair value of pension plan assets, salary escalations, mortality rates and other factors affecting the payment of future benefits.

 

The net pension expense by plan for the period was as follows:

 

	
 
    	
 
    	
Three months ended March 31, 2018
    	
 
    
	
 
    	
 
    	
Canada
    	
 
    	
United States
    	
 
    	
Total
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
Post-
    	
 
    	
 
    	
 
    	
Post-
    	
 
    	
 
    	
 
    	
Post-
    	
 
    
	
 
    	
 
    	
Defined
    	
 
    	
retirement
    	
 
    	
Defined
    	
 
    	
retirement
    	
 
    	
Defined
    	
 
    	
retirement
    	
 
    
	
 
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    
	
Current service   cost (a)
    	
 
    	
$
    	
2.6
    	
 
    	
$
    	
0.2
    	
 
    	
$
    	
2.5
    	
 
    	
$
    	
0.7
    	
 
    	
$
    	
5.1
    	
 
    	
$
    	
0.9
    	
 
    
	
Interest cost (b)
    	
 
    	
1.4
    	
 
    	
0.1
    	
 
    	
3.5
    	
 
    	
1.0
    	
 
    	
4.9
    	
 
    	
1.1
    	
 
    
	
Expected return   on plan assets (b)
    	
 
    	
(1.7
    	
)
    	
(0.1
    	
)
    	
(5.9
    	
)
    	
(1.7
    	
)
    	
(7.6
    	
)
    	
(1.8
    	
)
    
	
Amortization of   net actuarial loss (b)
    	
 
    	
0.3
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
0.3
    	
 
    	
—
    	
 
    
	
Amortization of   regulatory asset (b)
    	
 
    	
0.4
    	
 
    	
—
    	
 
    	
1.8
    	
 
    	
—
    	
 
    	
2.2
    	
 
    	
—
    	
 
    
	
Net benefit cost   recognized
    	
 
    	
$
    	
3.0
    	
 
    	
$
    	
0.2
    	
 
    	
$
    	
1.9
    	
 
    	
$
    	
—
    	
 
    	
$
    	
4.9
    	
 
    	
$
    	
0.2
    	
 
    


 




(a)         Recorded under the line item “Operating and administrative” expenses on the Consolidated Statement of Income.

(b)         Recorded under the line item “Other loss” on the Consolidated Statement of Income.

 

	
 
    	
 
    	
Three months ended March 31, 2017
    	
 
    
	
 
    	
 
    	
Canada
    	
 
    	
United States
    	
 
    	
Total
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
Post-
    	
 
    	
 
    	
 
    	
Post-
    	
 
    	
 
    	
 
    	
Post-
    	
 
    
	
 
    	
 
    	
Defined
    	
 
    	
retirement
    	
 
    	
Defined
    	
 
    	
retirement
    	
 
    	
Defined
    	
 
    	
retirement
    	
 
    
	
 
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    
	
Current service   cost (a)
    	
 
    	
$
    	
2.0
    	
 
    	
$
    	
0.2
    	
 
    	
$
    	
1.8
    	
 
    	
$
    	
0.4
    	
 
    	
$
    	
3.8
    	
 
    	
$
    	
0.6
    	
 
    
	
Interest cost (b)
    	
 
    	
1.4
    	
 
    	
0.2
    	
 
    	
3.0
    	
 
    	
0.7
    	
 
    	
4.4
    	
 
    	
0.9
    	
 
    
	
Expected return   on plan assets (b)
    	
 
    	
(1.5
    	
)
    	
(0.1
    	
)
    	
(4.1
    	
)
    	
(1.2
    	
)
    	
(5.6
    	
)
    	
(1.3
    	
)
    
	
Amortization of   net actuarial loss (b)
    	
 
    	
0.2
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
0.2
    	
 
    	
—
    	
 
    
	
Amortization of   regulatory asset/liability (b)
    	
 
    	
0.3
    	
 
    	
—
    	
 
    	
1.6
    	
 
    	
(0.1
    	
)
    	
1.9
    	
 
    	
(0.1
    	
)
    
	
Net benefit cost   (income) recognized
    	
 
    	
$
    	
2.4
    	
 
    	
$
    	
0.3
    	
 
    	
$
    	
2.3
    	
 
    	
$
    	
(0.2
    	
)
    	
$
    	
4.7
    	
 
    	
$
    	
0.1
    	
 
    


 




(a)         Recorded under the line item “Operating and administrative” expenses on the Consolidated Statement of Income.

(b)         Recorded under the line item “Other loss” on the Consolidated Statement of Income.

 

16.   INCOME TAXES

 

The effective income tax rate for the three months ended March 31, 2018 was approximately 21.5 percent (2017 — 30.9 percent). The decrease in the effective tax rate for the three months ended March 31, 2018 was primarily due to the decrease in the U.S. Federal tax rate from 35 percent to 21 percent. In addition, a lesser amount of the transaction costs incurred on the pending WGL Acquisition in the first quarter of 2018 were non-deductible than in the first quarter of 2017. This was partially offset by an increase to the uncertain tax provision in the first quarter of 2018.

 

24











 

17.   SUPPLEMENTAL CASH FLOW INFORMATION

 

The following table details the changes in operating assets and liabilities from operating activities:

 

	
Three months ended March 31
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Source (use) of   cash:
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Accounts   receivable
    	
 
    	
$
    	
34.1
    	
 
    	
$
    	
17.1
    	
 
    
	
Inventory
    	
 
    	
69.0
    	
 
    	
90.3
    	
 
    
	
Other current   assets
    	
 
    	
7.2
    	
 
    	
6.7
    	
 
    
	
Regulatory   assets (current)
    	
 
    	
(0.6
    	
)
    	
(1.0
    	
)
    
	
Accounts payable   and accrued liabilities
    	
 
    	
(43.7
    	
)
    	
(4.9
    	
)
    
	
Customer   deposits
    	
 
    	
(10.7
    	
)
    	
(12.8
    	
)
    
	
Regulatory   liabilities (current)
    	
 
    	
(2.8
    	
)
    	
(7.2
    	
)
    
	
Other current   liabilities
    	
 
    	
(7.8
    	
)
    	
(3.6
    	
)
    
	
Other operating   assets and liabilities
    	
 
    	
(10.9
    	
)
    	
(18.2
    	
)
    
	
Changes in   operating assets and liabilities
    	
 
    	
$
    	
33.8
    	
 
    	
$
    	
66.4
    	
 
    


 

The following cash payments have been included in the determination of earnings:

 

	
Three months ended March 31
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Interest paid   (net of capitalized interest)
    	
 
    	
$
    	
40.7
    	
 
    	
$
    	
52.4
    	
 
    
	
Income taxes   paid
    	
 
    	
$
    	
11.7
    	
 
    	
$
    	
11.3
    	
 
    


 

The following table is a reconciliation of cash and restricted cash balances:

 

	
As at March 31
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Cash and cash   equivalents
    	
 
    	
$
    	
100.1
    	
 
    	
$
    	
32.4
    	
 
    
	
Restricted cash   holdings from customers - current
    	
 
    	
5.2
    	
 
    	
4.0
    	
 
    
	
Restricted cash   holdings from customers - non-current
    	
 
    	
5.8
    	
 
    	
8.0
    	
 
    
	
Cash, cash   equivalents and restricted cash per consolidated statement of cash flow
    	
 
    	
$
    	
111.1
    	
 
    	
$
    	
44.4
    	
 
    


 

25









 

18.   SEASONALITY

 

The utility business is highly seasonal with the majority of natural gas deliveries occurring during the winter heating season. Gas sales increase during the winter resulting in stronger first and fourth quarter results and weaker second and third quarter results.

 

The power generation at the run-of-river hydro-facilities Forrest Kerr, Volcano Creek, and McLymont Creek occurs substantially from mid second quarter through early fourth quarter, resulting in weaker results in the first and fourth quarters.

 

19.   SEGMENTED INFORMATION

 

AltaGas owns and operates a portfolio of assets and services used to move energy from the source to the end-user. The following describes the Corporation’s four reporting segments:

 

	
Gas
    	
 
    	
·
    	
 
    	
NGL processing and extraction plants;
    
	
 
    	
 
    	
·
    	
 
    	
transmission pipelines to transport natural gas and   NGL;
    
	
 
    	
 
    	
·
    	
 
    	
natural gas gathering lines and field processing   facilities;
    
	
 
    	
 
    	
·
    	
 
    	
purchase and sale of natural gas, including to   commercial and industrial users;
    
	
 
    	
 
    	
·
    	
 
    	
natural gas storage facilities;
    
	
 
    	
 
    	
·
    	
 
    	
liquefied petroleum gas (LPG) terminal currently   under construction;
    
	
 
    	
 
    	
·
    	
 
    	
natural gas and NGL marketing; and
    
	
 
    	
 
    	
·
    	
 
    	
equity investment in Petrogas, a North American   entity engaged in the marketing, storage and distribution of NGL, drilling   fluids, crude oil and condensate diluents.
    
	
 
    	
 
    	
 
    	
 
    	
 
    
	
Power
    	
 
    	
·
    	
 
    	
natural gas-fired, wind, biomass and hydro power   generation assets, whereby outputs are generally sold under long-term power   purchase agreements, both operational and under development;
    
	
 
    	
 
    	
·
    	
 
    	
energy storage; and
    
	
 
    	
 
    	
·
    	
 
    	
sale of power to commercial and industrial users in   Alberta.
    
	
 
    	
 
    	
 
    	
 
    	
 
    
	
Utilities
    	
 
    	
·
    	
 
    	
rate-regulated natural gas distribution assets in   Michigan, Alaska, Alberta, British Columbia and Nova Scotia; and
    
	
 
    	
 
    	
·
    	
 
    	
rate-regulated natural gas storage in Michigan and   Alaska.
    
	
 
    	
 
    	
 
    	
 
    	
 
    
	
Corporate
    	
 
    	
·
    	
 
    	
the cost of providing corporate services, financing   and general corporate overhead, investments in certain public and private   entities, corporate assets, financing other segments and the effects of   changes in the fair value of risk management contracts.
    


 

The following table provides a reconciliation of segment revenue to the disaggregated revenue table as disclosed under Note 10 of these unaudited condensed interim Consolidated Financial Statements:

 

	
 
    	
 
    	
Three months ended March 31, 2018
    	
 
    
	
 
    	
 
    	
Gas
    	
 
    	
Power
    	
 
    	
Utilities
    	
 
    	
Corporate
    	
 
    	
Total
    	
 
    
	
External revenue   (note 10)
    	
 
    	
$
    	
311.8
    	
 
    	
$
    	
145.8
    	
 
    	
$
    	
421.4
    	
 
    	
$
    	
(0.6
    	
)
    	
$
    	
878.4
    	
 
    
	
Intersegment revenue
    	
 
    	
59.3
    	
 
    	
1.9
    	
 
    	
0.9
    	
 
    	
0.1
    	
 
    	
62.2
    	
 
    
	
Segment revenue
    	
 
    	
$
    	
371.1
    	
 
    	
$
    	
147.7
    	
 
    	
$
    	
422.3
    	
 
    	
$
    	
(0.5
    	
)
    	
$
    	
940.6
    	
 
    


 

26











 

The following tables show the composition by segment:

 

	
 
    	
 
    	
Three months ended March 31, 2018
    	
 
    
	
 
    	
 
    	
Gas
    	
 
    	
Power
    	
 
    	
Utilities
    	
 
    	
Corporate
    	
 
    	
Intersegment
   Elimination(a)
    	
 
    	
Total
    	
 
    
	
Segment revenue
    	
 
    	
$
    	
371.1
    	
 
    	
$
    	
147.7
    	
 
    	
$
    	
422.3
    	
 
    	
$
    	
(0.5
    	
)
    	
$
    	
(62.2
    	
)
    	
$
    	
878.4
    	
 
    
	
Cost of sales
    	
 
    	
(266.5
    	
)
    	
(78.5
    	
)
    	
(253.1
    	
)
    	
—
    	
 
    	
60.1
    	
 
    	
(538.0
    	
)
    
	
Operating and   administrative
    	
 
    	
(43.2
    	
)
    	
(29.4
    	
)
    	
(57.8
    	
)
    	
(12.6
    	
)
    	
2.2
    	
 
    	
(140.8
    	
)
    
	
Accretion   expenses
    	
 
    	
(1.0
    	
)
    	
(1.7
    	
)
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(2.7
    	
)
    
	
Depreciation and   amortization
    	
 
    	
(18.8
    	
)
    	
(29.6
    	
)
    	
(20.5
    	
)
    	
(3.7
    	
)
    	
—
    	
 
    	
(72.6
    	
)
    
	
Income from   equity investments
    	
 
    	
9.2
    	
 
    	
0.6
    	
 
    	
0.3
    	
 
    	
—
    	
 
    	
—
    	
 
    	
10.1
    	
 
    
	
Other income   (loss)
    	
 
    	
(4.0
    	
)
    	
—
    	
 
    	
1.4
    	
 
    	
(2.6
    	
)
    	
(0.1
    	
)
    	
(5.3
    	
)
    
	
Foreign exchange   gains (losses)
    	
 
    	
(0.1
    	
)
    	
—
    	
 
    	
—
    	
 
    	
0.1
    	
 
    	
—
    	
 
    	
—
    	
 
    
	
Interest expense
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(43.1
    	
)
    	
—
    	
 
    	
(43.1
    	
)
    
	
Income (loss) before   income taxes
    	
 
    	
$
    	
46.7
    	
 
    	
$
    	
9.1
    	
 
    	
$
    	
92.6
    	
 
    	
$
    	
(62.4
    	
)
    	
$
    	
—
    	
 
    	
$
    	
86.0
    	
 
    
	
Net additions   (reductions) to:
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Property, plant   and equipment(b)
    	
 
    	
$
    	
46.6
    	
 
    	
$
    	
1.7
    	
 
    	
$
    	
17.4
    	
 
    	
$
    	
0.4
    	
 
    	
$
    	
—
    	
 
    	
$
    	
66.1
    	
 
    
	
Intangible   assets
    	
 
    	
$
    	
0.9
    	
 
    	
$
    	
—
    	
 
    	
$
    	
0.4
    	
 
    	
$
    	
0.9
    	
 
    	
$
    	
—
    	
 
    	
$
    	
2.2
    	
 
    


 




(a)         Intersegment transactions are recorded at market value.

(b)         Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statement of Cash flow due to classification of business acquisition and foreign exchange changes on U.S. assets.

 

	
 
    	
 
    	
Three months ended March 31, 2017
    	
 
    
	
 
    	
 
    	
Gas
    	
 
    	
Power
    	
 
    	
Utilities
    	
 
    	
Corporate
    	
 
    	
Intersegment
   Elimination(a)
    	
 
    	
Total
    	
 
    
	
Segment revenue
    	
 
    	
$
    	
301.5
    	
 
    	
$
    	
132.2
    	
 
    	
$
    	
414.5
    	
 
    	
$
    	
2.1
    	
 
    	
$
    	
(79.1
    	
)
    	
$
    	
771.2
    	
 
    
	
Cost of sales
    	
 
    	
(204.1
    	
)
    	
(61.8
    	
)
    	
(244.9
    	
)
    	
—
    	
 
    	
76.7
    	
 
    	
(434.1
    	
)
    
	
Operating and   administrative
    	
 
    	
(41.8
    	
)
    	
(23.2
    	
)
    	
(56.2
    	
)
    	
(41.0
    	
)
    	
2.5
    	
 
    	
(159.7
    	
)
    
	
Accretion   expenses
    	
 
    	
(1.0
    	
)
    	
(1.8
    	
)
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(2.8
    	
)
    
	
Depreciation and   amortization
    	
 
    	
(16.5
    	
)
    	
(30.8
    	
)
    	
(20.8
    	
)
    	
(3.4
    	
)
    	
—
    	
 
    	
(71.5
    	
)
    
	
Income from   equity investments
    	
 
    	
11.2
    	
 
    	
2.3
    	
 
    	
0.6
    	
 
    	
—
    	
 
    	
—
    	
 
    	
14.1
    	
 
    
	
Other income   (loss)
    	
 
    	
(3.4
    	
)
    	
—
    	
 
    	
0.6
    	
 
    	
0.4
    	
 
    	
(0.1
    	
)
    	
(2.5
    	
)
    
	
Foreign exchange   gains
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
0.3
    	
 
    	
—
    	
 
    	
0.3
    	
 
    
	
Interest expense
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(46.0
    	
)
    	
—
    	
 
    	
(46.0
    	
)
    
	
Income (loss)   before income taxes
    	
 
    	
$
    	
45.9
    	
 
    	
$
    	
16.9
    	
 
    	
$
    	
93.8
    	
 
    	
$
    	
(87.6
    	
)
    	
$
    	
—
    	
 
    	
$
    	
69.0
    	
 
    
	
Net additions   (reductions) to:
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Property, plant   and equipment(b)
    	
 
    	
$
    	
(21.6
    	
)
    	
$
    	
7.0
    	
 
    	
$
    	
16.4
    	
 
    	
$
    	
0.2
    	
 
    	
$
    	
—
    	
 
    	
$
    	
2.0
    	
 
    
	
Intangible   assets
    	
 
    	
$
    	
0.5
    	
 
    	
$
    	
0.2
    	
 
    	
$
    	
0.4
    	
 
    	
$
    	
0.9
    	
 
    	
$
    	
—
    	
 
    	
$
    	
2.0
    	
 
    


 




(a)         Intersegment transactions are recorded at market value.

(b)         Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statement of Cash flow due to classification of business acquisition and foreign exchange changes on U.S. assets.

 

The following table shows goodwill and total assets by segment:

 

	
 
    	
 
    	
Gas
    	
 
    	
Power
    	
 
    	
Utilities
    	
 
    	
Corporate
    	
 
    	
Total
    	
 
    
	
As at   March 31, 2018
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Goodwill
    	
 
    	
$
    	
152.6
    	
 
    	
$
    	
—
    	
 
    	
$
    	
679.9
    	
 
    	
$
    	
—
    	
 
    	
$
    	
832.5
    	
 
    
	
Segmented assets
    	
 
    	
$
    	
3,127.4
    	
 
    	
$
    	
3,211.7
    	
 
    	
$
    	
3,438.6
    	
 
    	
$
    	
328.6
    	
 
    	
$
    	
10,106.3
    	
 
    
	
As at   December 31, 2017
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Goodwill
    	
 
    	
$
    	
152.6
    	
 
    	
$
    	
—
    	
 
    	
$
    	
664.7
    	
 
    	
$
    	
—
    	
 
    	
$
    	
817.3
    	
 
    
	
Segmented assets
    	
 
    	
$
    	
3,096.8
    	
 
    	
$
    	
3,192.5
    	
 
    	
$
    	
3,460.2
    	
 
    	
$
    	
282.7
    	
 
    	
$
    	
10,032.2
    	
 
    


 

27











 

20.   SUBSEQUENT EVENTS

 

Subsequent events have been reviewed through April 25, 2018, the date on which these unaudited condensed interim Consolidated Financial Statements were issued.

 

Subsequent to quarter-end, AltaGas entered into a long-term natural gas processing arrangement (the Processing Arrangement) with Birchcliff Energy Ltd. (Birchcliff) at AltaGas’ deep-cut sour gas processing facility located in Gordondale, Alberta (the Gordondale Facility). Under the Processing Arrangement, Birchcliff is provided with up to 120 MMcf/d of natural gas processing on a firm-service basis, and Birchcliff’s take-or-pay obligation is 100 MMcf/d. The new Processing Arrangement is effective as of January 1, 2018 and replaces the parties’ existing Gordondale processing arrangement.

 

28











 

Supplementary Quarterly Operating Information

(unaudited)

 

	
 
    	
 
    	
Q1-18
    	
 
    	
Q4-17
    	
 
    	
Q3-17
    	
 
    	
Q2-17
    	
 
    	
Q1-17
    	
 
    
	
OPERATING   HIGHLIGHTS
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
GAS
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Total inlet gas   processed (Mmcf/d)(1)
    	
 
    	
1,553
    	
 
    	
1,424
    	
 
    	
1,322
    	
 
    	
1,300
    	
 
    	
1,404
    	
 
    
	
Extraction   volumes (Bbls/d)(1)(2)
    	
 
    	
74,786
    	
 
    	
68,306
    	
 
    	
64,026
    	
 
    	
58,885
    	
 
    	
71,958
    	
 
    
	
Frac spread -   realized ($/Bbl)(1)(3)
    	
 
    	
19.01
    	
 
    	
18.02
    	
 
    	
14.96
    	
 
    	
9.06
    	
 
    	
10.56
    	
 
    
	
Frac spread -   average spot price ($/Bbl)(1)(4)
    	
 
    	
22.25
    	
 
    	
30.66
    	
 
    	
21.28
    	
 
    	
10.98
    	
 
    	
17.26
    	
 
    
	
POWER
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Renewable power   sold (GWh)
    	
 
    	
126
    	
 
    	
301
    	
 
    	
681
    	
 
    	
499
    	
 
    	
148
    	
 
    
	
Conventional   power sold (GWh)
    	
 
    	
842
    	
 
    	
1,059
    	
 
    	
992
    	
 
    	
409
    	
 
    	
385
    	
 
    
	
Renewable   capacity factor (%)
    	
 
    	
8.1
    	
 
    	
27.5
    	
 
    	
70.3
    	
 
    	
50.7
    	
 
    	
9.5
    	
 
    
	
Contracted   conventional availability factor (%)(5)
    	
 
    	
94.5
    	
 
    	
96.3
    	
 
    	
99.6
    	
 
    	
99.9
    	
 
    	
96.0
    	
 
    
	
UTILITIES
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Canadian   utilities
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Natural gas   deliveries - end-use (PJ)(6)
    	
 
    	
14.1
    	
 
    	
11.2
    	
 
    	
3.7
    	
 
    	
4.8
    	
 
    	
13.5
    	
 
    
	
Natural gas   deliveries - transportation (PJ)(6)
    	
 
    	
1.8
    	
 
    	
1.6
    	
 
    	
1.3
    	
 
    	
1.5
    	
 
    	
1.9
    	
 
    
	
U.S. utilities
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Natural gas   deliveries end use (Bcf) (6)
    	
 
    	
31.0
    	
 
    	
24.3
    	
 
    	
5.9
    	
 
    	
10.3
    	
 
    	
30.2
    	
 
    
	
Natural gas   deliveries transportation (Bcf)(6)
    	
 
    	
13.4
    	
 
    	
14.2
    	
 
    	
10.9
    	
 
    	
11.5
    	
 
    	
15.4
    	
 
    
	
Service sites(7)
    	
 
    	
582,871
    	
 
    	
581,518
    	
 
    	
575,602
    	
 
    	
575,084
    	
 
    	
576,829
    	
 
    
	
Degree day   variance from normal - AUI (%)(8)
    	
 
    	
10.2
    	
 
    	
4.0
    	
 
    	
(16.9
    	
)
    	
(7.4
    	
)
    	
(2.2
    	
)
    
	
Degree day   variance from normal - Heritage Gas (%)(8)
    	
 
    	
(8.1
    	
)
    	
(4.6
    	
)
    	
(20.4
    	
)
    	
(4.3
    	
)
    	
(1.9
    	
)
    
	
Degree day   variance from normal - SEMCO Gas (%)(9)
    	
 
    	
3.0
    	
 
    	
4.8
    	
 
    	
5.7
    	
 
    	
(8.4
    	
)
    	
(11.8
    	
)
    
	
Degree day   variance from normal - ENSTAR (%)(9) 
    	
 
    	
(1.7
    	
)
    	
(8.3
    	
)
    	
(16.6
    	
)
    	
(5.4
    	
)
    	
9.6
    	
 
    


 




(1)    Average for the period.

(2)    Includes Harmattan NGL processed on behalf of customers.

(3)    Realized frac spread or NGL margin, expressed in dollars per barrel of NGL, is derived from sales recorded by the segment during the period for frac exposed volumes plus the settlement value of frac hedges settled in the period less extraction premiums, divided by the total frac exposed volumes produced during the period.

(4)    Average spot frac spread or NGL margin, expressed in dollars per barrel of NGL, is indicative of the average sales price that AltaGas receives for propane, butane and condensate less extraction premiums, before accounting for hedges, divided by the respective frac exposed volumes for the period.

(5)    Calculated as the availability factor contracted under long-term tolling arrangements adjusted for occasions where partial or excess capacity payments have been added or deducted.

(6)    Petajoule (PJ) is one million gigajoules (GJ). Bcf is one billion cubic feet.

(7)    Service sites reflect all of the service sites of AUI, PNG, Heritage Gas, and U.S. Utilities, including transportation and non-regulated business lines.

(8)    A degree day for AUI and Heritage Gas is the cumulative extent to which the daily mean temperature falls below 15 degrees Celsius at AUI and 18 degrees Celsius at Heritage Gas. Normal degree days are based on a 20-year rolling average. Positive variances from normal lead to increased delivery volumes from normal expectations. Degree day variances do not materially affect the results of PNG as the British Columbia Utilities Commission (BCUC) has approved a rate stabilization mechanism for its residential and small commercial customers.

(9)    A degree day for U.S. Utilities is a measure of coldness, determined daily as the number of degrees the average temperature during the day in question is below 65 degrees Fahrenheit. Degree days for a particular period are determined by adding the degree days incurred during each day of the period. Normal degree days for a particular period are the average of degree days during the prior 15 years for SEMCO Energy Gas Company and during the prior 10 years for ENSTAR.

 

29











 

Other Information

 

DEFINITIONS

 

	
Bbls/d
    	
barrels   per day
    
	
Bcf
    	
billion   cubic feet
    
	
GJ
    	
gigajoule
    
	
GWh
    	
gigawatt-hour
    
	
Mcf
    	
thousand   cubic feet
    
	
Mmcf/d
    	
million   cubic feet per day
    
	
MW
    	
megawatt
    
	
MWh
    	
megawatt-hour
    
	
MMBTU
    	
million   British thermal unit
    
	
PJ
    	
petajoule
    
	
US$
    	
United   States dollar
    


 

ABOUT ALTAGAS

 

AltaGas is an energy infrastructure company with a focus on natural gas, power and regulated utilities. The Corporation creates value by acquiring, growing and optimizing its energy infrastructure, including a focus on clean energy sources. For more information visit: www.altagas.ca.

 

For further information contact:

 

Investment Community

1-877-691-7199

investor.relations@altagas.ca

 

30