Management’s Responsibility for Consolidated Financial Statements
The Consolidated Financial Statements and Management’s Discussion and Analysis (MD&A) of AltaGas Ltd. (AltaGas or the Corporation) are the responsibility of Management and have been approved by the Board of Directors of the Corporation. The Consolidated Financial Statements have been prepared by Management in accordance with United States Generally Accepted Accounting Principles (U.S. GAAP) and include amounts that are based on Management’s best estimates and judgments.
Management is responsible for establishing and maintaining adequate internal controls over financial reporting for the Corporation. Management has designed and maintains a system of internal controls over financial reporting, including a program of internal audits to carry out its responsibility. Management believes these controls provide reasonable assurance that financial records are reliable and form a proper basis for the preparation of financial statements. Management undertakes communication to employees of policies that govern ethical business conduct.
The MD&A and Consolidated Financial Statements are approved by the Board of Directors after considering the recommendation of the Audit Committee. The Audit Committee of the Board of Directors is composed of independent non-management directors.
The Audit Committee meets with Management regularly and meets independently with internal and external auditors and as a group to review any significant accounting, internal controls and auditing matters in accordance with the terms of the Charter of the Audit Committee, which is set out in the Annual Information Form. The Audit Committee’s responsibilities include overseeing Management’s performance in carrying out its financial reporting responsibilities and reviewing the Consolidated Financial Statements and MD&A, before these documents are submitted to the Board of Directors for approval. The internal and independent external auditors have access to the Audit Committee without obtaining prior Management approval.
The Audit Committee approves the terms of engagement of the independent external auditors and reviews the annual audit plan, the Auditors’ Report and the results of the audit. It also recommends to the Board of Directors the firm of external auditors to be appointed by the shareholders.
The shareholders have appointed Ernst & Young LLP as independent external auditors to express an opinion as to whether the Consolidated Financial Statements present fairly, in all material respects, the Corporation’s consolidated financial position, results of operations and cash flows in accordance with U.S. GAAP. The report of Ernst & Young LLP outlines the scope of its examination and its opinion on the Consolidated Financial Statements.
(signed) “David Harris” |
| (signed) “Tim Watson” |
|
|
|
DAVID HARRIS |
| TIM WATSON |
President and |
| Executive Vice President and |
Chief Executive Officer of |
| Chief Financial Officer of |
AltaGas Ltd. |
| AltaGas Ltd. |
February 28, 2018
AltaGas Ltd. – 2017
Independent Auditors’ Report
To the Shareholders of AltaGas Ltd.
We have audited the accompanying Consolidated Financial Statements of AltaGas Ltd., which comprise the consolidated balance sheets as at December 31, 2017 and 2016, and the consolidated statements of income, comprehensive income (loss), equity and cash flows for the years then ended, and a summary of significant accounting policies and other explanatory information.
Management’s Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these Consolidated Financial Statements in accordance with United States Generally Accepted Accounting Principles, and for such internal control as management determines is necessary to enable the preparation of Consolidated Financial Statements that are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these Consolidated Financial Statements based on our audits. We conducted our audits in accordance with Canadian Generally Accepted Auditing Standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the Consolidated Financial Statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the Consolidated Financial Statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the Consolidated Financial Statements, whether due to fraud or error. In making those risk assessments, the auditors consider internal control relevant to the entity’s preparation and fair presentation of the Consolidated Financial Statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the Consolidated Financial Statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the Consolidated Financial Statements present fairly, in all material respects, the financial position of AltaGas Ltd. as at December 31, 2017 and 2016 and the results of its operations and its cash flows for the years then ended in accordance with United States Generally Accepted Accounting Principles.
Calgary, Canada |
|
February 28, 2018 |
|
Consolidated Balance Sheets
As at ($ millions) |
| December 31, |
| December 31, |
| ||
|
|
|
|
|
| ||
ASSETS |
|
|
|
|
| ||
Current assets |
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 27.3 |
| $ | 19.0 |
|
Accounts receivable, net of allowances (notes 4 and 20) |
| 382.9 |
| 338.8 |
| ||
Inventory (note 5) |
| 201.1 |
| 221.0 |
| ||
Restricted cash holdings from customers |
| 8.9 |
| 5.0 |
| ||
Regulatory assets (note 18) |
| 1.1 |
| 0.9 |
| ||
Risk management assets (note 20) |
| 38.6 |
| 40.4 |
| ||
Prepaid expenses and other current assets |
| 36.0 |
| 42.8 |
| ||
Assets held for sale (note 4) |
| 6.0 |
| 70.7 |
| ||
|
| 701.9 |
| 738.6 |
| ||
|
|
|
|
|
| ||
Property, plant and equipment (notes 4 and 6) |
| 6,689.8 |
| 6,734.9 |
| ||
Intangible assets (notes 4 and 7) |
| 588.8 |
| 694.3 |
| ||
Goodwill (notes 4 and 8) |
| 817.3 |
| 856.0 |
| ||
Regulatory assets (note 18) |
| 328.6 |
| 329.1 |
| ||
Risk management assets (note 20) |
| 15.9 |
| 24.1 |
| ||
Deferred income taxes (note 17) |
| 2.8 |
| 2.8 |
| ||
Restricted cash holdings from customers |
| 7.5 |
| 10.1 |
| ||
Long-term investments and other assets (note 10) |
| 312.6 |
| 189.3 |
| ||
Investments accounted for by the equity method (note 12) |
| 567.0 |
| 621.4 |
| ||
|
| $ | 10,032.2 |
| $ | 10,200.6 |
|
|
|
|
|
|
| ||
LIABILITIES AND SHAREHOLDERS’ EQUITY |
|
|
|
|
| ||
Current liabilities |
|
|
|
|
| ||
Accounts payable and accrued liabilities (note 20) |
| $ | 415.3 |
| $ | 345.8 |
|
Dividends payable (note 20) |
| 32.0 |
| 29.2 |
| ||
Short-term debt (notes 13 and 20) |
| 46.8 |
| 128.7 |
| ||
Current portion of long-term debt (notes 14 and 20) |
| 188.9 |
| 383.4 |
| ||
Customer deposits |
| 30.8 |
| 35.5 |
| ||
Regulatory liabilities (note 18) |
| 10.9 |
| 16.6 |
| ||
Risk management liabilities (note 20) |
| 57.6 |
| 32.9 |
| ||
Other current liabilities (notes 16 and 20) |
| 32.6 |
| 23.6 |
| ||
Liabilities associated with assets held for sale (note 4) |
| 0.3 |
| 0.4 |
| ||
|
| 815.2 |
| 996.1 |
| ||
|
|
|
|
|
| ||
Long-term debt (notes 14 and 20) |
| 3,436.5 |
| 3,366.9 |
| ||
Asset retirement obligations (notes 4 and 15) |
| 88.3 |
| 81.6 |
| ||
Deferred income taxes (note 17) |
| 444.2 |
| 621.7 |
| ||
Regulatory liabilities (note 18) |
| 268.6 |
| 170.5 |
| ||
Risk management liabilities (note 20) |
| 13.8 |
| 12.6 |
| ||
Other long-term liabilities (notes 16 and 20) |
| 201.9 |
| 206.3 |
| ||
Future employee obligations (note 25) |
| 124.5 |
| 129.5 |
| ||
|
| $ | 5,393.0 |
| $ | 5,585.2 |
|
As at ($ millions) |
| December 31, |
| December 31, |
| ||
Shareholders’ equity |
|
|
|
|
| ||
Common shares, no par values, unlimited shares authorized; 2017 - 175.3 million and 2016 - 166.9 million issued and outstanding (note 21) |
| $ | 4,007.9 |
| $ | 3,773.4 |
|
Preferred shares (note 21) |
| 1,277.7 |
| 985.1 |
| ||
Contributed surplus |
| 22.3 |
| 17.4 |
| ||
Accumulated deficit |
| (933.6 | ) | (600.4 | ) | ||
Accumulated other comprehensive income (AOCI) (note 19) |
| 199.1 |
| 405.1 |
| ||
Total shareholders’ equity |
| 4,573.4 |
| 4,580.6 |
| ||
Non-controlling interests |
| 65.8 |
| 34.8 |
| ||
Total equity |
| 4,639.2 |
| 4,615.4 |
| ||
|
| $ | 10,032.2 |
| $ | 10,200.6 |
|
Variable interest entity (note 11).
Commitments, contingencies and guarantees (note 26).
Subsequent events (note 30).
See accompanying notes to the Consolidated Financial Statements.
Approved by the Board of Directors of AltaGas Ltd.
(signed) “David W. Cornhill” |
| (signed) “Robert B. Hodgins” |
|
|
|
DAVID W. CORNHILL |
| ROBERT B. HODGINS |
Director |
| Director |
Consolidated Statements of Income
For the year ended December 31 ($ millions except per share amounts) |
| 2017 |
| 2016 |
| ||
|
|
|
|
|
| ||
REVENUE |
|
|
|
|
| ||
Regulated operations |
| $ | 1,119.1 |
| $ | 1,049.9 |
|
Services (note 24) |
| 903.3 |
| 828.4 |
| ||
Sales |
| 595.9 |
| 315.6 |
| ||
Other revenue |
| 0.4 |
| 7.2 |
| ||
Unrealized losses on risk management contracts (note 20) |
| (62.5 | ) | (11.4 | ) | ||
|
| 2,556.2 |
| 2,189.7 |
| ||
|
|
|
|
|
| ||
EXPENSES |
|
|
|
|
| ||
Cost of sales, exclusive of items shown separately |
| 1,357.1 |
| 1,016.9 |
| ||
Operating and administrative |
| 573.8 |
| 509.3 |
| ||
Accretion expenses (notes 15 and 16) |
| 10.9 |
| 11.0 |
| ||
Depreciation and amortization (notes 6 and 7) |
| 282.4 |
| 271.5 |
| ||
Provisions on assets (note 9) |
| 139.6 |
| — |
| ||
|
| 2,363.8 |
| 1,808.7 |
| ||
|
|
|
|
|
| ||
Income from equity investments (note 12) |
| 31.4 |
| 3.4 |
| ||
Other income (note 23) |
| 11.2 |
| 8.6 |
| ||
Foreign exchange gains |
| 1.7 |
| 4.0 |
| ||
Interest expense |
|
|
|
|
| ||
Short-term debt |
| (3.7 | ) | (3.1 | ) | ||
Long-term debt |
| (166.6 | ) | (147.7 | ) | ||
Income before income taxes |
| 66.4 |
| 246.2 |
| ||
Income tax expense (recovery) (note 17) |
|
|
|
|
| ||
Current |
| 30.5 |
| 24.4 |
| ||
Deferred |
| (64.0 | ) | 8.4 |
| ||
Net income after taxes |
| 99.9 |
| 213.4 |
| ||
|
|
|
|
|
| ||
Net income applicable to non-controlling interests |
| 8.3 |
| 9.9 |
| ||
Net income applicable to controlling interests |
| 91.6 |
| 203.5 |
| ||
Preferred share dividends |
| (61.3 | ) | (48.1 | ) | ||
Net income applicable to common shares |
| $ | 30.3 |
| $ | 155.4 |
|
|
|
|
|
|
| ||
Net income per common share (note 22) |
|
|
|
|
| ||
Basic |
| $ | 0.18 |
| $ | 0.99 |
|
Diluted |
| $ | 0.18 |
| $ | 0.99 |
|
|
|
|
|
|
| ||
Weighted average number of common shares outstanding (millions) (note 22) |
|
|
|
|
| ||
Basic |
| 171.0 |
| 157.2 |
| ||
Diluted |
| 171.3 |
| 157.6 |
| ||
See accompanying notes to the Consolidated Financial Statements.
Consolidated Statements of Comprehensive Income (Loss)
For the year ended December 31 ($ millions) |
| 2017 |
| 2016 |
| ||
Net income after taxes |
| $ | 99.9 |
| $ | 213.4 |
|
Other comprehensive income (loss), net of taxes |
|
|
|
|
| ||
Loss on foreign currency translation |
| (183.4 | ) | (84.2 | ) | ||
Unrealized gain on net investment hedge (note 20) |
| 6.6 |
| 34.0 |
| ||
Actuarial losses on pension plans and post-retirement benefit (PRB) plans (note 25) |
| (1.0 | ) | (2.4 | ) | ||
Reclassification of actuarial losses and prior service costs on defined benefit and PRB plans to net income (note 25) |
| 0.7 |
| 0.7 |
| ||
Settlement of PRB plan (note 25) |
| 0.2 |
| — |
| ||
Unrealized gain (loss) on available-for-sale assets |
| (26.9 | ) | 22.2 |
| ||
Other comprehensive income (loss) from equity investees |
| (2.2 | ) | 1.3 |
| ||
Total other comprehensive loss (OCI), net of taxes (note 19) |
| (206.0 | ) | (28.4 | ) | ||
Comprehensive income (loss) attributable to controlling interests and non-controlling interests, net of taxes |
| $ | (106.1 | ) | $ | 185.0 |
|
|
|
|
|
|
| ||
Comprehensive income (loss) attributable to: |
|
|
|
|
| ||
Non-controlling interests |
| $ | 8.3 |
| $ | 9.9 |
|
Controlling interests |
| (114.4 | ) | 175.1 |
| ||
|
| $ | (106.1 | ) | $ | 185.0 |
|
See accompanying notes to the Consolidated Financial Statements.
Consolidated Statements of Equity
For the year ended December 31 ($ millions) |
| 2017 |
| 2016 |
| ||
|
|
|
|
|
| ||
Common shares (note 21) |
|
|
|
|
| ||
Balance, beginning of year |
| $ | 3,773.4 |
| $ | 3,168.1 |
|
Shares issued for cash on exercise of options |
| 6.5 |
| 9.3 |
| ||
Shares issued under DRIP (1) |
| 236.3 |
| 173.6 |
| ||
Deferred taxes on share issuance costs |
| (8.3 | ) | 0.2 |
| ||
Shares issued on public offering, net of issuance costs |
| — |
| 422.2 |
| ||
Balance, end of year |
| $ | 4,007.9 |
| $ | 3,773.4 |
|
Preferred shares (note 21) |
|
|
|
|
| ||
Balance, beginning of year |
| $ | 985.1 |
| $ | 985.1 |
|
Series K Issued |
| 293.4 |
| — |
| ||
Deferred taxes on share issuance costs |
| (0.8 | ) | — |
| ||
Balance, end of year |
| $ | 1,277.7 |
| $ | 985.1 |
|
Contributed surplus |
|
|
|
|
| ||
Balance, beginning of year |
| $ | 17.4 |
| $ | 16.7 |
|
Share options expense |
| 1.4 |
| 1.6 |
| ||
Exercise of share options |
| (0.5 | ) | (0.7 | ) | ||
Forfeiture of share options |
| (0.1 | ) | (0.2 | ) | ||
Adoption of ASU No. 2016-09 (note 2) |
| 1.1 |
| — |
| ||
Sale of non-controlling interest (note 11) |
| 3.0 |
| — |
| ||
Balance, end of year |
| $ | 22.3 |
| $ | 17.4 |
|
Accumulated deficit |
|
|
|
|
| ||
Balance, beginning of year |
| $ | (600.4 | ) | $ | (435.4 | ) |
Net income applicable to controlling interests |
| 91.6 |
| 203.5 |
| ||
Common share dividends |
| (362.4 | ) | (320.4 | ) | ||
Preferred share dividends |
| (61.3 | ) | (48.1 | ) | ||
Adoption of ASU No. 2016-09 (note 2) |
| (1.1 | ) | — |
| ||
Balance, end of year |
| $ | (933.6 | ) | $ | (600.4 | ) |
AOCI (note 19) |
|
|
|
|
| ||
Balance, beginning of year |
| $ | 405.1 |
| $ | 433.5 |
|
Other comprehensive loss |
| (206.0 | ) | (28.4 | ) | ||
Balance, end of year |
| $ | 199.1 |
| $ | 405.1 |
|
Total shareholders’ equity |
| $ | 4,573.4 |
| $ | 4,580.6 |
|
|
|
|
|
|
| ||
Non-controlling interests |
|
|
|
|
| ||
Balance, beginning of year |
| $ | 34.8 |
| $ | 34.9 |
|
Net income applicable to non-controlling interests |
| 8.3 |
| 9.9 |
| ||
Sale of non-controlling interest (note 11) |
| 20.0 |
| — |
| ||
Contributions from non-controlling interests to subsidiaries |
| 11.0 |
| — |
| ||
Distributions by subsidiaries to non-controlling interests |
| (8.3 | ) | (10.0 | ) | ||
Balance, end of year |
| 65.8 |
| 34.8 |
| ||
Total equity |
| $ | 4,639.2 |
| $ | 4,615.4 |
|
(1) Premium Dividend™, Dividend Reinvestment and Optional Cash Purchase Plan.
See accompanying notes to the Consolidated Financial Statements.
Consolidated Statements of Cash Flows
For the year ended December 31 ($ millions) |
| 2017 |
| 2016 |
| ||
Cash from operations |
|
|
|
|
| ||
Net income after taxes |
| $ | 99.9 |
| $ | 213.4 |
|
Items not involving cash: |
|
|
|
|
| ||
Depreciation and amortization (notes 6 and 7) |
| 282.4 |
| 271.5 |
| ||
Provisions on assets (note 9) |
| 139.6 |
| — |
| ||
Accretion expenses (notes 15 and 16) |
| 10.9 |
| 11.0 |
| ||
Share-based compensation (note 21) |
| 1.3 |
| 1.4 |
| ||
Deferred income tax expense (recovery) (note 17) |
| (64.0 | ) | 8.4 |
| ||
Losses (gains) on sale of assets (notes 3 and 23) |
| 2.7 |
| (4.2 | ) | ||
Income from equity investments (note 12) |
| (31.4 | ) | (3.4 | ) | ||
Unrealized losses on risk management contracts (note 20) |
| 62.5 |
| 11.4 |
| ||
Unrealized gains on long-term investments (note 23) |
| (3.6 | ) | (0.5 | ) | ||
Amortization of deferred financing costs |
| 16.9 |
| 2.7 |
| ||
Other |
| (4.1 | ) | (0.2 | ) | ||
Asset retirement obligations settled (note 15) |
| (4.0 | ) | (3.8 | ) | ||
Distributions from equity investments |
| 30.2 |
| 26.0 |
| ||
Changes in operating assets and liabilities (note 28) |
| 5.9 |
| (77.5 | ) | ||
|
| $ | 545.2 |
| $ | 456.2 |
|
Investing activities |
|
|
|
|
| ||
Business acquisitions, net of cash acquired (note 3) |
| — |
| (20.0 | ) | ||
Acquisition of property, plant and equipment |
| (473.0 | ) | (507.2 | ) | ||
Acquisition of intangible assets |
| (20.3 | ) | (24.4 | ) | ||
Acquisition of investment in a publicly traded entity |
| (7.0 | ) | — |
| ||
Contributions to equity investments |
| (16.8 | ) | (20.2 | ) | ||
Loan to affiliate, net of repayment (note 27) |
| (12.5 | ) | (62.5 | ) | ||
Change in restricted cash holdings from customers |
| (4.2 | ) | 0.2 |
| ||
Investment in Petrogas preferred shares (note 12) |
| — |
| (150.0 | ) | ||
Payment for derivative contracts |
| (36.0 | ) | — |
| ||
Proceeds from disposition of assets, net of transaction costs (note 3) |
| 70.5 |
| 31.9 |
| ||
|
| $ | (499.3 | ) | $ | (752.2 | ) |
Financing activities |
|
|
|
|
| ||
Net issuance (repayment) of short-term debt |
| (74.2 | ) | 1.4 |
| ||
Issuance of long-term debt, net of debt issuance costs |
| 758.1 |
| 674.5 |
| ||
Repayment of long-term debt |
| (861.6 | ) | (884.3 | ) | ||
Dividends - common shares |
| (359.6 | ) | (315.3 | ) | ||
Dividends - preferred shares |
| (61.3 | ) | (49.2 | ) | ||
Distributions to non-controlling interest |
| (8.3 | ) | (10.0 | ) | ||
Contributions from non-controlling interests |
| 11.0 |
| — |
| ||
Net proceeds from shares issued on exercise of options |
| 6.0 |
| 8.5 |
| ||
Net proceeds from issuance of common shares |
| 236.3 |
| 595.8 |
| ||
Net proceeds from issuance of preferred shares |
| 293.4 |
| — |
| ||
Proceeds from sale of non-controlling interest |
| 24.1 |
| — |
| ||
Other |
| (1.9 | ) | — |
| ||
|
| $ | (38.0 | ) | $ | 21.4 |
|
Change in cash and cash equivalents |
| 7.9 |
| (274.6 | ) | ||
Effect of exchange rate changes on cash and cash equivalents |
| 0.4 |
| 0.2 |
| ||
Cash and cash equivalents, beginning of year |
| 19.0 |
| 293.4 |
| ||
Cash and cash equivalents, end of year |
| $ | 27.3 |
| $ | 19.0 |
|
See accompanying notes to the Consolidated Financial Statements.
Notes to the Consolidated Financial Statements
(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 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 Consolidated Financial Statements have been prepared by Management in accordance with United States Generally Accepted Accounting Principles (U.S. GAAP).
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 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 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: 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
Rate-Regulated Operations
SEMCO Gas, ENSTAR, AUI, PNG, and Heritage Gas (collectively Utilities) engage in the delivery and sale of natural gas and are regulated by the Michigan Public Service Commission (MPSC), Regulatory Commission of Alaska (RCA), Alberta Utilities Commission (AUC), British Columbia Utilities Commission (BCUC), and the Nova Scotia Utility and Review Board (NSUARB), respectively.
The MPSC, RCA, AUC, BCUC, and NSUARB exercise statutory authority over matters such as tariffs, rates, construction, operations, financing, returns, accounting and certain contracts with customers. In order to recognize the economic effects of the actions and decisions of the MPSC, RCA, AUC, BCUC, and NSUARB, the timing of recognition of certain assets, liabilities, revenues and expenses as a result of regulation may differ from that otherwise expected using U.S. GAAP for entities not subject to rate regulation.
Regulatory assets represent future revenues associated with certain costs incurred in the current period or in prior periods that are expected to be recovered from customers in future periods through the rate setting process. Regulatory liabilities represent future reductions or limitations of increases in revenue associated with amounts that are expected to be refunded to customers through the rate setting process.
Cash and Cash Equivalents
Cash and cash equivalents consist of cash on hand, balances with banks, and investments in money market instruments with original maturities of less than three months.
Restricted Cash Holdings from Customers
Cash deposited, which is restricted and is not available for general use by AltaGas, is separately presented as restricted cash holdings in the Consolidated Balance Sheets.
Accounts Receivable
Receivables are recorded net of the allowance for doubtful accounts in the Consolidated Balance Sheets. AltaGas regularly analyzes and evaluates the collectability of the accounts receivable based on a combination of factors. If circumstances related to the collectability change, the allowance for doubtful accounts is further adjusted. Accounts are written off when collection efforts are complete and future recovery is unlikely.
Inventory
Inventory consists of materials, supplies, and natural gas, which are valued at the lower of cost or net realizable value. Cost of inventory is assigned using a weighted average cost formula. In general, commodity costs and variable transportation costs are capitalized as gas in underground storage. Fixed costs, primarily pipeline demand charges and storage charges, are expensed as incurred through the cost of gas.
Property, Plant, and Equipment (PP&E), Depreciation and Amortization
Property, plant, and equipment are carried at cost. The Corporation depreciates the cost of capital assets, net of salvage value, on a straight-line basis over the estimated useful life of the assets, with the exception of rate regulated utilities assets, where depreciation is calculated on a straight-line basis or over the contract term of a specific agreement at rates as approved by the regulatory authorities.
The U.S. utilities include in depreciation expense an amount allowed for regulatory purposes to be collected in current rates for future removal and site restoration costs. The Canadian utilities that collect future removal and site restoration costs in rates defer the revenue until the costs are incurred.
Interest costs are capitalized on major additions to property, plant, and equipment until the asset is ready for its intended use. The interest rate used for calculating the interest costs to be capitalized is based on AltaGas’ prior quarter actual borrowing long-term interest rate.
Utilities capitalize an imputed carrying cost on assets during construction as authorized by regulatory authorities and the amount so capitalized is an allowance for funds used during construction (AFUDC). AFUDC is the amount that a rate regulated enterprise is allowed to recover for its cost of financing assets under construction. Capitalized overhead, administrative expenses and AFUDC are included in the cost of the related assets and are recovered in rates charged to customers through depreciation expense, as allowed by the regulators.
The range of useful lives for AltaGas’ PP&E is as follows:
Gas assets |
| 3 - 45 years |
Power generation assets |
| 2 - 120 years |
Utilities assets |
| 3 - 80 years |
Corporate assets |
| 1-7 years |
As required by the respective regulatory authorities, net additions to utility assets at Heritage Gas and PNG are not depreciated until the year after they are brought into active service. Net additions to SEMCO’s utility assets are amortized for one half year in the year in which they are brought into active service. Net additions to AUI’s utility assets are amortized in the month they are brought into active service.
Generally, when a regulated asset is retired or disposed of, there is no gain or loss recorded in the Consolidated Statement of Income. Any difference between the cost and accumulated depreciation of the asset, net of salvage proceeds, is charged to accumulated depreciation or another regulatory asset or liability account. It is expected that any gain or loss that is charged to accumulated depreciation or another regulatory account will be reflected in future depreciation expense when it is refunded or collected in rates. When a non-regulated asset is retired or disposed of from PP&E, the original cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in the Consolidated Statement of Income.
Leases are classified as either capital or operating. Leases that transfer substantially all the benefits and risks of ownership of property to AltaGas are accounted for as capital leases.
Intangible Assets
Intangible assets are recorded at cost. Intangible assets which have a finite useful life are amortized on a straight-line basis over their term or estimated useful life. The range of useful lives for intangible assets with a finite life is as follows:
Energy services relationships |
| 15 -19 years |
Electricity service agreements |
| 2 - 60 years |
Software |
| 3 - 10 years |
Land rights |
| 5 - 64 years |
Franchises and consents |
| 9 - 25 years |
Extraction and Transmission (E&T) Contracts |
| 15 - 25 years |
Assets Held for Sale
The Corporation classifies assets as held for sale when the carrying amount will be recovered through a sale transaction rather than through continuing use. This condition is met when Management approves and commits to a formal plan to sell the assets, the assets are available for immediate sale in their present condition, and Management expects the sale to close within the next 12 months. Upon classifying an asset as held for sale, an asset is recorded at the lower of its carrying value or the estimated fair value less cost to sell. Assets held for sale are not depreciated or amortized.
Business Acquisitions
Business acquisitions are accounted for using the acquisition method. Under the acquisition method, assets and liabilities of the acquired entity are recorded at fair value at the date of acquisition. Acquisition-related costs are expensed as incurred. Goodwill represents the excess of purchase price over the fair value of the net assets acquired.
Provision on Assets
If facts and circumstances suggest that a long-lived asset or an intangible asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset is not recoverable, as determined by the projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value and an impairment loss is recognized.
Goodwill is not subject to amortization, but assessed at least annually for impairment, or more often when events or changes in circumstances indicate that goodwill may be impaired. The annual assessment of goodwill is performed at the reporting unit level, which is an operating segment or one level below. The Corporation has the option to first assess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill may be impaired. If a quantitative impairment test is performed, the first step of the two-step impairment test is to compare the fair value of the reporting unit to its carrying value (including goodwill). If the carrying value of the reporting unit exceeds the fair value, goodwill is reduced to its implied fair value and an impairment loss would be recorded in the Consolidated Statement of Income.
Development Costs
AltaGas expenses development costs as incurred unless such development costs meet certain criteria related to technical, market, regulatory and financial feasibility for capitalization. Development costs are examined annually to ensure capitalization criteria continue to be met. When the criteria that previously justified the deferral of costs are no longer met, the unamortized balance is taken as a charge to income in the period when this determination is made. Development costs are amortized based on the expected period of benefit, beginning at the commencement of commercial operations.
Investments Accounted for by the Equity Method
The equity method of accounting is used for investments in which AltaGas has the ability to exercise significant influence, but does not have a controlling interest. Equity investments are initially measured at cost and are adjusted for the Corporation’s
proportionate share of earnings or losses. Equity investments are increased for contributions made and decreased for distributions received. To the extent an investee undertakes activities necessary to commence its planned principal operations, the Corporation will capitalize interest costs associated with its investment during such period.
An equity method investment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the investment may not be recoverable. When such condition is deemed other than temporary, the carrying value of the investment is written down to its fair value, and an impairment charge is recorded in the Consolidated Statement of Income.
Financial Instruments
All financial instruments are initially recorded at fair value unless they qualify for, and are designated under, a normal purchase and normal sale (NPNS) exemption. Subsequent measurement of the financial instruments is based on their classification. The financial assets are classified as “held-for-trading”, “held-to-maturity”, “loans and receivables”, or “available-for-sale”. Financial liabilities are classified as “held-for-trading” or other financial liabilities. Subsequent measurement is determined by classification.
A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to AltaGas’ business needs and AltaGas has the ability, and intent, to deliver or take delivery of the underlying item. AltaGas continually assesses the contracts designated under the NPNS exemption and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met.
Held-for-trading financial assets and liabilities may consist of swaps, options, forwards and equity securities. These financial instruments are initially recorded at their fair value, with subsequent changes in fair value recorded in net income under “unrealized gains and losses from risk management contracts” or “other income (loss)”. Held-to-maturity, loans and receivables, and other financial liabilities are recognized at amortized cost using the effective interest method.
The available-for-sale classification includes non-derivative financial assets that are designated as available-for-sale or are not included in the other three classifications. Available-for-sale instruments are initially recorded at fair value, and changes to fair value are recorded through “Other comprehensive income” (OCI). Declines in fair value below the amortized cost basis that are other than temporary are reclassified out of OCI to earnings for the period.
Investments in equity instruments not accounted for under the equity method that do not have a quoted market price in an active market are measured at cost. Income earned from these investments is included in the Consolidated Statement of Income under “Other income (loss)”.
Derivatives embedded in other financial instruments or contracts (the host instrument) are recorded separately and are measured at fair value if the economic characteristics of the embedded derivative are not closely related to the host instrument, the terms of the embedded derivative are the same as those of a standalone derivative and the entire contract is not held-for-trading or accounted for at fair value. Changes in fair value are included in earnings.
The fair values recorded on the Consolidated Balance Sheet reflect netting of the asset and liability positions where counterparty master netting arrangements contain provisions for net settlement.
Transaction costs related to the acquisition of held-for-trading financial assets and liabilities are expensed as incurred.
Transaction costs for obtaining debt financing other than line-of-credit arrangements are recognized as a direct deduction from the related debt liability on the Consolidated Balance Sheet. Transaction costs related to line-of-credit arrangements are capitalized and included under “Long-term investments and other assets” on the Consolidated Balance Sheet. Premiums and discounts are netted against long-term debt on the Consolidated Balance Sheets. The deferred charges are amortized over the life of the related debt on an effective interest basis and included in “Interest expense” on the Consolidated Statement of Income.
Asset Retirement Obligations
AltaGas recognizes asset retirement obligations in the period in which the legal obligation is incurred and a reasonable estimate of fair value can be determined. The associated asset retirement costs are capitalized as part of the carrying amount of the asset and are depreciated over the estimated useful life of the asset. The liability is increased due to the passage of time over the estimated period until the settlement of the obligation, with a corresponding charge to accretion expense for asset retirement obligations.
Certain utility assets will have future legal obligations on retirement, but an asset retirement obligation has not been recorded due to its indeterminate life and corresponding indeterminable timing and scope of these asset retirement obligations. The U.S. Utilities recognize asset retirement obligations for some interim retirements, as expected by their regulators, whereas Canadian Utilities do not.
Revenue Recognition
The Utilities reporting segment recognizes revenue, presented as “revenue from regulated operations” in the Consolidated Statement of Income, when the product or services are delivered on the basis of regular meter readings or estimates of usage and is consistent with the underlying rate setting mechanism mandated by the applicable regulatory authority. The Utilities reporting segment bills gas distribution customers monthly, on a cycle basis and accrues revenue for service rendered to its customers but not billed at month-end. Storage customers are billed monthly for services provided in the preceding month and revenue is accrued for services rendered but not billed at month end.
Revenue from services represents the proceeds from operating leases in the Gas and Power reporting segments where AltaGas is the lessor, and fees from the gathering, transportation, processing, and marketing of natural gas. Revenue from services are recognized at the time the service is rendered.
Revenue from sales represents the proceeds from the commodity sales in the Gas and Power reporting segments and are recognized at the time the product is delivered.
Foreign Currency Translation
Monetary assets and liabilities denominated in a foreign currency are converted to the functional currency using the exchange rate in effect at the balance sheet date. Adjustments resulting from the conversion are recorded in the Consolidated Statement of Income. Non-monetary assets and liabilities are converted at the historical exchange rate in effect at the transaction date. Revenues and expenses are converted at the exchange rate applicable at the transaction date.
For foreign entities with a functional currency other than Canadian dollars, AltaGas’ reporting currency, assets, and liabilities are translated into Canadian dollars at the rate in effect at the reporting date. Revenues and expenses are translated at average exchange rates during the reporting period. All adjustments resulting from the translation of the foreign operations are recorded in OCI.
AltaGas may designate some of its U.S. dollar denominated long-term debt as a foreign currency hedge of its investment in foreign operations. Accordingly, foreign exchange gains and losses, from the dates of designation, on the translation of the U.S. dollar denominated long-term debt are included in OCI.
Share Options and Other Compensation Plans
Share options granted are recorded using fair value. Compensation expense is measured at the date of the grant using the Black-Scholes-Merton model and is recognized over the vesting period of the options. Consideration received by AltaGas on exercise of the share options is credited to shareholders’ equity.
AltaGas has a medium-term incentive plan (MTIP) for employees and executive officers which includes two types of awards: restricted units (RUs) and performance units (PUs). Both RUs and PUs are valued based on the dividends declared during the vesting period and the weighted average share price of AltaGas’ common shares multiplied by the units outstanding at the end of the vesting period. Upon vesting, the RUs and PUs are paid in cash or, at the election of AltaGas, its equivalent in common
shares purchased from the market. The PUs are also subject to a performance multiplier ranging from 0 to 2 dependent on the Corporation’s performance relative to performance targets agreed between the Corporation and the employees. Compensation expense is recognized using the liability method and is recorded as operating and administrative expense over the vesting period. A change in value of the RUs or PUs is recognized in the period the change occurs.
In addition, AltaGas has a deferred share unit plan (DSUP) for directors, officer and employees as an additional form of long-term variable compensation incentive. Although the DSUP is available to directors, officers and employees, AltaGas currently only grants deferred share units (DSUs) under the DSUP as a form of director compensation. The DSUs granted are fully vested upon being credited to a participant’s account, and the participant is entitled to payment at his or her termination date, and payment is not subject to satisfaction of any requirements as to any minimum period of membership or employment or other conditions. DSUs are accounted for at fair value. Compensation expense is determined based on the fair value of the DSUs on the date of the grant and fluctuations in fair value are recognized in the period the change occurs.
Pension Plans and Post-Retirement Benefits
AltaGas maintains defined benefit pension plans, defined contribution plans, and other post-retirement benefit plans for eligible employees. Contributions made by the Corporation to the defined contribution plans are expensed in the period in which the contribution occurs.
The cost of defined benefit pension plans and post-retirement benefits is actuarially determined using the projected benefit method prorated based on service and Management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected health care costs. Pension plan assets are measured at fair value. The expected return on plan assets is based on historical and projected rates of return for each asset class in the plan portfolio. The projected benefit obligation is discounted using the market interest rate on high-quality debt instruments with cash flows matching the timing and amount of benefit payments. Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation and the fair value of plan assets along with any unamortized past service costs are amortized on a straight-line basis over the expected average remaining service life of active employees. The expected average remaining service period of the active members covered by the defined benefit pension plans and post-retirement benefit plans is 12.7 years and 13.5 years, respectively.
AltaGas recognizes the overfunded or underfunded status of its pension and post-retirement benefit plans as either assets or liabilities in the Consolidated Balance Sheet. Unrecognized actuarial gains and losses and past service costs and credits that arise during the period are recognized in OCI.
For certain regulated Utilities, the Corporation expects to recover pension expense in future rates and therefore records actuarial gains and losses as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the expected average remaining service life of active employees.
Income Taxes
Income taxes for the Corporation and its subsidiaries are calculated using the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are determined based on differences between the carrying value and the tax basis of assets and liabilities and are measured using the enacted tax rates and laws that are in effect in the periods in which the differences are expected to be settled or realized. Deferred income tax assets are routinely reviewed and a valuation allowance is recorded to reduce the deferred tax assets if it is more likely than not that deferred tax assets will not be realized. The financial statement effects of an uncertain tax position are recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxing authority. The current and deferred tax impact is equal to the largest amount, considering possible settlement outcomes, that is greater than 50 percent likely of being realized upon settlement with the taxing authorities.
Investment tax credits are deferred and amortized over the estimated service lives of the related properties.
The rate-regulated natural gas distribution subsidiaries recognize a separate regulatory asset or liability for the amount of deferred income taxes expected to be recovered from, or paid to, customers in the future.
Net Income per Share
Basic net income per common share is computed using the weighted average number of common shares outstanding during the period. Dilutive net income per common share is calculated using the weighted average number of common shares outstanding adjusted for dilutive common shares related to the Corporation’s share-based compensation awards.
The potentially dilutive impact of the share-based compensation awards is determined using the treasury stock method. Under the treasury stock method, awards are treated as if they had been exercised with any proceeds used to repurchase common stock at the average market price during the period. Any incremental difference between the assumed number of shares issued and purchased is included in the diluted share computation.
Contingencies
Liabilities for loss contingencies arising from claims, assessments, litigation and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Any such accruals are adjusted thereafter as additional information becomes available or circumstances change.
ADOPTION OF NEW ACCOUNTING STANDARDS
Effective January 1, 2017, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU):
· ASU No. 2015-11 “Inventory: Simplifying the Measurement of Inventory”. The amendments in this ASU require an entity to measure inventory at the lower of cost and net realizable value. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;
· ASU No. 2016-05 “Derivatives and Hedging: Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships”. The amendments in this ASU clarify that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument under Topic 815 does not, in and of itself, require de-designation of that hedging relationship provided that all other hedge accounting criteria continue to be met. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;
· ASU No. 2016-06, “Derivatives and Hedging: Contingent Put and Call Options in Debt Instruments”. The amendments in this ASU clarify the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;
· ASU No. 2016-07 “Investments - Equity Method and Joint Ventures Investments: Simplifying the Transition to the Equity Method of Accounting”. The amendments in this ASU eliminate the requirement to retrospectively apply the equity method as a result of an increase in the level of ownership interest or degree of influence. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and
· ASU No. 2016-09 “Stock Compensation: Improvements to Employee Share-Based Payment Accounting”. The amendments in this ASU focus on simplifying several areas of the accounting for share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory withholding requirements, as well as the classification on the statement of cash flow. Upon adoption of this ASU, AltaGas elected as an accounting policy to account for forfeitures when they occur instead of estimating the number of awards that are expected to vest. The ASU requires this change to be adopted using the modified retrospective approach and as a result, AltaGas recorded a decrease to accumulated retained earnings of approximately $1 million and an increase to contributed surplus of
approximately $1 million. The deferred tax impact was immaterial. The remaining amendments to this ASU did not have a material impact on AltaGas’ consolidated financial statements.
FUTURE CHANGES IN ACCOUNTING PRINCIPLES
In May 2014, FASB issued ASU No. 2014-09 “Revenue from Contracts with Customers”, which will replace numerous requirements in U.S. GAAP, including industry-specific requirements, and provide companies with a single revenue recognition model for recognizing revenue from contracts with customers. The core principle of the amendments in this ASU is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The amendments specify various disclosure requirements that would enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. In March 2016, FASB issued ASU No. 2016-08 “Principal versus Agent Consideration”. The amendments in this ASU clarify the implementation guidance on the principal versus agent considerations in the new revenue recognition standard. In April 2016, FASB issued ASU No. 2016-10 “Identifying Performance Obligation and Licensing”, which reduces the complexity when applying the guidance for identifying performance obligations and improves the operability and understandability of the license implementation guidance. In May 2016, FASB issued ASU No. 2016-12 “Narrow Scope Improvements and Practical Expedients”, clarifying several implementation issues, including collectability, presentation of sales taxes, non-cash consideration, contract modification, completed contracts, and transition. In December 2016, FASB issued ASU No. 2016-20 “Technical Corrections and Improvements”, which makes minor technical corrections and improvements to the new revenue standard. The new revenue standard will be effective for annual and interim periods beginning on or after December 15, 2017. The ASU permits the use of either the full retrospective or modified retrospective transition method and AltaGas has elected the modified retrospective transition method. In 2016, AltaGas established a cross-functional implementation team consisting of representatives from across all the operating segments. A scoping exercise was completed for each of AltaGas’ operating segments and AltaGas selected all material contracts or contract groups for review to identify potential impacts under the new standard. AltaGas has completed the contracts review and have not identified any material changes in how revenues are recognized under the new standard. AltaGas has started a process to compile the information needed to meet the new disclosure requirements and noted that there will be changes to the revenue disclosures based on additional requirements under the new standard regarding the disaggregation of revenue as well as details about performance obligations, and contracts assets and liabilities.
In January 2016, FASB issued ASU No. 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” which revises 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 amends certain disclosure requirements associated with the fair value of financial instruments. The amendments in this ASU are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Upon adoption, entities will be required to make a cumulative-effect adjustment to the statement of financial position as of the beginning of the first reporting period in which the guidance is effective. The guidance on equity securities without readily determinable fair value will be applied prospectively to all equity investments that exist as of the date of adoption of the standard. Upon adoption, AltaGas will no longer be able to classify equity securities with readily determinable fair values as available-for-sale and any changes in fair value will be reported through earnings instead of other comprehensive income. The remaining provisions of this ASU are not expected to have a material impact on AltaGas’ financial statements.
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 periods beginning after December 15, 2020, and interim periods within those fiscal periods. Early adoption is permitted. AltaGas is currently assessing the impact of this ASU on its consolidated financial statements.
In August 2016, FASB issued ASU No. 2016-15 “Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments”. The amendments in this ASU clarify the classification of certain cash flow transactions on the statement of cash flow. The amendments in this ASU are effective for fiscal periods beginning after December 15, 2017, and interim periods within those fiscal periods. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.
In October 2016, FASB issued ASU No. 2016-16 “Income Taxes: Intra-Entity Transfers of Assets Other Than Inventory”. The amendments in this ASU revise 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 amendment in this ASU is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. An entity should apply the amendments in this ASU on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.
In November 2016, FASB issued ASU No. 2016-18 “Statement of Cash Flows: Restricted Cash”. The amendments in this ASU require 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 amendments in this ASU are effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. An entity should apply the amendments in this ASU retrospectively to each period presented. Early adoption is also permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated cash flow statements.
In January 2017, FASB issued ASU No. 2017-01 “Business Combinations: Clarifying the Definition of a Business”. The amendments in this ASU change the definition of a business to assist entities with evaluating when a set of transferred assets and activities is a business. The amendments in this ASU are effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. An entity should apply the amendments in this ASU on a prospective basis on or after the effective date. AltaGas will apply the amendments prospectively.
In January 2017, FASB issued ASU No. 2017-04 “Intangibles — Goodwill and Other: Simplifying the Test for Goodwill Impairment”. The ASU removes 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. An entity should adopt the amendments in this ASU for annual periods beginning after December 15, 2020, and interim periods within those annual periods. An entity should apply the amendments in this ASU on a prospective basis. Early adoption is permitted. AltaGas currently expects to apply the amendments prospectively.
In February 2017, FASB issued 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 clarify the scope of ASC 610-20 as well as the accounting for partial sales of nonfinancial assets. The effective date and transition requirements for the amendments in this ASU are the same as the effective date and transition
requirements for ASU No. 2014-09, which is effective for fiscal years and interim periods beginning on or after December 15, 2017. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.
In March 2017, FASB issued 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 revise the presentation of net periodic pension cost and net periodic postretirement benefit cost on the income statement and limit the components that are eligible for capitalization in assets to only the service cost component. The amendments in this ASU are effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. The amendments in this ASU should be applied retrospectively for the presentation of the service cost component and the other components of net benefit cost in the income statement and prospectively, on and after the effective date, for the capitalization of the service cost component. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.
In May 2017, FASB issued ASU No. 2017-09 “Compensation — Stock Compensation: Scope of Modifications Accounting”. The amendments in this ASU provide guidance on the types of changes to the terms or conditions of share-based payment arrangements to which an entity would be required to apply modification accounting. The amendments in this ASU are effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. An entity should apply the amendments in this ASU on a prospective basis on or after the effective date. Early adoption is permitted. AltaGas will apply the amendments prospectively.
In August 2017, FASB issued ASU No. 2017-12 “Derivatives and Hedging — Targeted Improvements to Accounting for Hedging Activities”. The amendments in this ASU improves the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and make certain targeted improvements to simplify the application of hedge accounting. The amendments in this ASU are effective for annual periods beginning after December 15, 2018, including 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.
3. ACQUISITIONS AND DISPOSITIONS
Pending Acquisition of WGL Holdings, Inc. (WGL)
On January 25, 2017, the Corporation entered into the Merger Agreement to indirectly acquire WGL. 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 being developed by a third party, which is currently in the final stages of commissioning. 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. In Maryland, the hearing before the PSC of MD concluded on October 16, 2017, and on December 4, 2017 AltaGas and WGL announced that they had reached a settlement agreement with several of the intervenors in the Maryland proceeding. As a result, AltaGas and WGL filed a stipulation with the PSC of MD to extend the deadline for issuing its decision. The PSC of MD approved this request moving the date for a decision to on or before April 4, 2018. 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.
AltaGas believes that closing of the WGL Acquisition will occur in 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. With all funding required for the closing of the WGL Acquisition in place, AltaGas can evaluate and pursue its asset sale process in a prudent and timely fashion in step with the regulatory process and consistent with AltaGas’ long term strategic vision. Management has presently identified a total of over $4.0 billion of assets from AltaGas’ Gas, Power and Utilities business segments in respect of which it is evaluating various options for monetization that could include the sale of either minority and/or controlling interests. Management expects to realize over $2 billion from its asset sale process in 2018. With the present optionality available to AltaGas and in light of a number of factors including recent developments in the California Resource Adequacy markets, AltaGas has discontinued the previously announced sale process of its California power assets. AltaGas will instead continue to pursue other structuring and commercial opportunities to unlock the value of the California assets. Additional financing steps could include offerings of senior debt, hybrid securities, and equity-linked securities (including preferred shares), subject to prevailing market conditions.
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.
Edmonton Ethane Extraction Plant (EEEP)
Effective January 1, 2016, AltaGas acquired the remaining 51 percent interest in EEEP for cash consideration of approximately $21.0 million, increasing its ownership interest to 100 percent. AltaGas accounted for the acquisition as a business combination achieved in stages and remeasured the previously held 49 percent interest in EEEP at fair value on the acquisition date using the discounted cash flow approach. The significant inputs included contracted cash flows for the facility, forecasted commodity prices, and projected operating costs based on historical pattern. No gain or loss was recorded as a result of the remeasurement. Upon the acquisition of control, AltaGas began consolidating the results of EEEP. Prior to the acquisition, AltaGas proportionately consolidated the 49 percent interest in EEEP.
Below is the final purchase price allocation:
Fair value of net assets acquired |
|
|
| |
Property, plant and equipment |
| $ | 67.1 |
|
Asset retirement obligations |
| (15.0 | ) | |
Deferred income taxes |
| (3.3 | ) | |
|
| $ | 48.8 |
|
The total estimated fair value of $48.8 million included $21.0 million of cash paid to acquire the remaining 51 percent interest and $27.8 million related to the previously held interest.
Dispositions
In March 2017, AltaGas completed the disposition of the Ethylene Delivery Systems (EDS) and the Joffre Feedstock Pipeline (JFP) transmission assets in the Gas segment to Nova Chemicals Corporation for gross proceeds of approximately $67.0 million. AltaGas recognized a pre-tax loss on disposition of approximately $3.4 million in the consolidated statement of income under the line item “Other income” for the year ended December 31, 2017 related to this disposition.
On February 29, 2016, AltaGas completed the disposition of certain non-core natural gas gathering and processing assets in the Gas segment to Tidewater Midstream and Infrastructure Ltd. (Tidewater) for total gross consideration of $30.0 million in cash and approximately 43.7 million of common shares of Tidewater valued at $1.48 per share (the Tidewater Gas Asset Disposition). The assets were located primarily in central and north central Alberta and totaled approximately 490 Mmcf/d of gross licensed natural gas processing capacity. AltaGas recognized a pre-tax gain on disposition of $4.5 million in the Consolidated Statement of Income under the line item “Other income” for the year ended December 31, 2016. In addition, AltaGas recorded a tax recovery of $10.3 million related to the asset sale for the year ended December 31, 2016.
4. ASSETS HELD FOR SALE
As at |
| December 31, |
| December 31, |
| ||
Assets held for sale |
|
|
|
|
| ||
Accounts receivable |
| $ | 0.3 |
| $ | — |
|
Property, plant and equipment |
| 5.3 |
| 67.3 |
| ||
Intangible assets |
| 0.1 |
| — |
| ||
Goodwill |
| 0.3 |
| 3.4 |
| ||
|
| $ | 6.0 |
| $ | 70.7 |
|
|
|
|
|
|
| ||
Liabilities associated with assets held for sale |
|
|
|
|
| ||
Asset retirement obligations |
| $ | 0.3 |
| $ | 0.4 |
|
|
| $ | 0.3 |
| $ | 0.4 |
|
As at December 31, 2017, AltaGas committed to the sale of certain non-core facilities in the Gas segment in two separate transactions. Accordingly, the carrying value of the assets and liabilities were classified as held for sale. A pre-tax provision of $6.4 million on property, plant and equipment and a pre-tax provision of $0.2 million on allocated goodwill were recognized due to the reduction of the carrying value of the assets to fair value less costs to sell. Both transactions closed in early 2018.
In March 2017, AltaGas completed the sale of the EDS and JFP transmission assets in the Gas segment to Nova Chemicals Corporation that were presented as assets held for sale as at December 31, 2016. Please refer to Note 3 for further details.
5. INVENTORY
As at |
| December 31, |
| December 31, |
| ||
Natural gas held in storage |
| $ | 133.9 |
| $ | 172.6 |
|
Other inventory |
| 67.2 |
| 48.4 |
| ||
|
| $ | 201.1 |
| $ | 221.0 |
|
6. PROPERTY, PLANT AND EQUIPMENT
|
| December 31, 2017 |
| December 31, 2016 |
| ||||||||||||||
As at |
| Cost |
| Accumulated |
| Net book |
| Cost |
| Accumulated |
| Net book |
| ||||||
Gas |
| $ | 2,801.4 |
| $ | (636.3 | ) | $ | 2,165.1 |
| $ | 2,615.8 |
| $ | (630.8 | ) | $ | 1,985.0 |
|
Power |
| 2,874.8 |
| (392.3 | ) | 2,482.5 |
| 2,957.2 |
| (232.1 | ) | 2,725.1 |
| ||||||
Utilities |
| 2,245.4 |
| (226.1 | ) | 2,019.3 |
| 2,250.4 |
| (193.5 | ) | 2,056.9 |
| ||||||
Corporate |
| 65.9 |
| (37.7 | ) | 28.2 |
| 65.3 |
| (30.1 | ) | 35.2 |
| ||||||
Reclassified to assets held for sale (note 4) |
| (16.7 | ) | 11.4 |
| (5.3 | ) | (126.2 | ) | 58.9 |
| (67.3 | ) | ||||||
|
| $ | 7,970.8 |
| $ | (1,281.0 | ) | $ | 6,689.8 |
| $ | 7,762.5 |
| $ | (1,027.6 | ) | $ | 6,734.9 |
|
Interest capitalized on long-term capital construction projects for the year ended December 31, 2017 was $10.8 million (2016 - $10.9 million).
As at December 31, 2017, the Corporation had approximately $269.5 million (December 31, 2016 - $183.4 million) of capital projects under construction that were not yet subject to amortization.
Depreciation expense related to property, plant and equipment (including assets under capital leases) for the year ended December 31, 2017 was $239.7 million (2016 - $229.3 million).
7. INTANGIBLE ASSETS
|
| December 31, 2017 |
| December 31, 2016 |
| ||||||||||||||
As at |
| Cost |
| Accumulated |
| Net book |
| Cost |
| Accumulated |
| Net book |
| ||||||
E&T contracts |
| $ | 26.6 |
| $ | (13.4 | ) | $ | 13.2 |
| $ | 53.7 |
| $ | (39.2 | ) | $ | 14.5 |
|
Electricity service agreements |
| 603.1 |
| (108.5 | ) | 494.6 |
| 628.8 |
| (37.2 | ) | 591.6 |
| ||||||
Energy services relationships |
| 10.2 |
| (8.1 | ) | 2.1 |
| 10.2 |
| (7.4 | ) | 2.8 |
| ||||||
Software |
| 126.8 |
| (61.6 | ) | 65.2 |
| 118.7 |
| (45.6 | ) | 73.1 |
| ||||||
Land rights |
| 11.0 |
| (2.4 | ) | 8.6 |
| 10.9 |
| (2.2 | ) | 8.7 |
| ||||||
Franchises and consents |
| 7.4 |
| (2.2 | ) | 5.2 |
| 5.6 |
| (2.0 | ) | 3.6 |
| ||||||
Reclassified to assets held for sale (note 4) |
| (0.1 | ) | — |
| (0.1 | ) | (27.1 | ) | 27.1 |
| — |
| ||||||
|
| $ | 785.0 |
| $ | (196.2 | ) | $ | 588.8 |
| $ | 800.8 |
| $ | (106.5 | ) | $ | 694.3 |
|
Amortization expense related to intangible assets for the year ended December 31, 2017 was $42.7 million (2016 - $42.2 million).
As at December 31, 2017, the Corporation excluded $11.2 million (December 31, 2016 - $8.0 million) of software assets under development as well as assets with indefinite life from the asset base subject to amortization.
The following table sets forth the estimated amortization expense of intangible assets, excluding any amortization of assets not yet subject to amortization as well as assets with indefinite life, for the years ended December 31:
2018 |
| $ | 40.0 |
|
2019 |
| $ | 38.9 |
|
2020 |
| $ | 34.8 |
|
2021 |
| $ | 32.9 |
|
2022 |
| $ | 30.2 |
|
Thereafter |
| $ | 400.8 |
|
8. GOODWILL
|
| December 31, |
| December 31, |
| ||
As at |
| 2017 |
| 2016 |
| ||
Balance, beginning of year |
| $ | 856.0 |
| $ | 877.3 |
|
Foreign exchange translation |
| (38.4 | ) | (17.9 | ) | ||
Reclassified to assets held for sale (note 4) |
| (0.3 | ) | (3.4 | ) | ||
Balance, end of year |
| $ | 817.3 |
| $ | 856.0 |
|
9. PROVISIONS ON ASSETS
Year ended December 31 |
| 2017 |
| 2016 |
| ||
Power |
| $ | 133.0 |
| $ | — |
|
Gas |
| 6.6 |
| — |
| ||
|
| $ | 139.6 |
| $ | — |
|
Power
In 2017, AltaGas recorded pre-tax provisions on assets related to the Hanford and Henrietta gas-fired peaking plants in California and certain non-core development stage gas-fired peaking projects in California and Alberta for $133.0 million. The
pre-tax provisions of $133.0 million were comprised of $48.5 million on intangible assets and $84.5 million on property, plant and equipment. No provisions on assets were recorded in 2016 for the Power segment.
Gas
In 2017, AltaGas recorded a pre-tax provision on assets of $6.6 million on a non-core gas processing facility that was classified as held for sale (See Note 4). No provisions on assets were recorded in 2016 for the Gas segment.
10. LONG-TERM INVESTMENTS AND OTHER ASSETS
As at |
| December 31, |
| December 31, |
| ||
Investments in publicly-traded entities |
| $ | 95.0 |
| $ | 49.4 |
|
Loan to affiliate (see note 27) |
| 75.0 |
| 62.5 |
| ||
Deferred lease receivable |
| 29.0 |
| 16.3 |
| ||
Debt issuance costs associated with credit facilities |
| 20.3 |
| 5.1 |
| ||
Refundable deposits |
| 14.9 |
| 39.0 |
| ||
Loan to employee (see note 27) |
| — |
| 0.8 |
| ||
Prepayment on long-term service agreements |
| 68.1 |
| 8.7 |
| ||
Post-retirement benefit (see note 25) |
| — |
| 2.8 |
| ||
Subscription receipts issuance costs |
| 1.7 |
| — |
| ||
Other |
| 8.6 |
| 4.7 |
| ||
|
| $ | 312.6 |
| $ | 189.3 |
|
The following table summarizes the Corporation’s available-for-sale investments in equity securities:
As at |
| December 31, |
| December 31, |
| ||
Amortized cost |
| $ | 28.7 |
| $ | 21.7 |
|
Gross unrealized gains |
| 2.5 |
| 23.2 |
| ||
Gross unrealized losses |
| (9.6 | ) | — |
| ||
Fair value |
| $ | 21.6 |
| $ | 44.9 |
|
11. VARIABLE INTEREST ENTITY
On May 5, 2017, AltaGas LPG Limited Partnership (AltaGas LPG), a wholly-owned subsidiary of AltaGas, and Vopak Development Canada Inc. (Vopak), a wholly-owned subsidiary of Koninklijke Vopak N.V. (Royal Vopak), a public company incorporated under the laws of the Netherlands, formed the Ridley Island LPG Export Limited Partnership (RILE LP) to develop, own and operate the Ridley Island Propane Export Terminal (RIPET). AltaGas’ subsidiaries hold a 70 percent interest while Vopak holds a 30 percent interest in RILE LP. The construction cost of RIPET, which is estimated to be $450 to $500 million, will be funded by AltaGas LPG and Vopak in proportion to their respective interests in RILE LP. As part of the arrangements, AltaGas entered into a long-term agreement for the capacity of RIPET with RILE LP, and AltaGas and certain of its subsidiaries will provide construction and operating services to RILE LP.
AltaGas has determined that RILE LP is a VIE in which it holds variable interests and is the primary beneficiary. In the determination that AltaGas is the primary beneficiary of the VIE, AltaGas noted that it has the power to direct the activities that most significantly impact the VIE’s economic performance through the construction, operating and marketing services provided to RILE LP. In addition, AltaGas has the obligation to absorb the losses and the right to receive the benefits that could potentially be significant to RILE LP through the long-term agreement for the capacity of RIPET. As such, AltaGas has consolidated RILE LP and recorded $20.0 million of the $24.1 million proceeds received from Vopak on formation of RILE LP as a non-controlling interest with the remainder of the proceeds less deferred tax recognized as contributed surplus in the amount of $3.0 million.
The following table represents amounts included in the consolidated balance sheets attributable to this VIE:
|
| December 31, |
| December 31, |
| ||
As at |
| 2017 |
| 2016 |
| ||
Accounts receivable |
| $ | 1.4 |
| $ | — |
|
Property, plant and equipment |
| 84.3 |
| — |
| ||
Long-term investments and other assets |
| 48.0 |
| — |
| ||
Net assets |
| $ | 133.7 |
| $ | — |
|
The assets of RILE LP are the property of RILE LP and are not available to AltaGas for any other purpose. RILE LP’s asset balances can only be used to settle its own obligations. The liabilities of RILE LP do not represent additional claims against AltaGas’ general assets. AltaGas’ exposure to loss as a result of its interest as a limited partner is its net investment. AltaGas and Royal Vopak have provided limited guarantees for the obligations of their respective subsidiaries for the construction cost of RIPET. Upon commencement of commercial operations at RIPET, the terms of the long-term capacity agreement between AltaGas LPG and RILE LP provide for a return on and of capital and reimbursement of RIPET operating costs by AltaGas LPG in accordance with the terms set out in the agreement.
12. INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD
|
|
|
|
|
| Carrying value as at |
| Equity income (loss) |
| ||||||||
Description |
| Location |
| Ownership |
| 2017 |
| 2016 |
| 2017 |
| 2016 |
| ||||
AltaGas Idemitsu Joint Venture LP (AIJVLP) |
| Canada |
| 50 |
| $ | 323.3 |
| $ | 307.2 |
| $ | 6.6 |
| $ | (0.4 | ) |
ASTC Power Partnership (ASTC) (a) |
| Canada |
| n/a |
| — |
| — |
| — |
| (11.1 | ) | ||||
Craven County Wood Energy LP |
| United States |
| 50 |
| 20.9 |
| 22.9 |
| 3.3 |
| 0.2 |
| ||||
Eaton Rapids Gas Storage System |
| United States |
| 50 |
| 26.4 |
| 27.9 |
| 2.5 |
| 2.6 |
| ||||
Grayling Generating Station LP |
| United States |
| 50 |
| 27.6 |
| 30.1 |
| 3.5 |
| 4.1 |
| ||||
Inuvik Gas Ltd. |
| Canada |
| 33.333 |
| — |
| — |
| — |
| — |
| ||||
Sarnia Airport Storage Pool LP |
| Canada |
| 50 |
| 18.8 |
| 19.2 |
| 1.0 |
| 0.9 |
| ||||
Petrogas Preferred Shares |
| Canada |
| n/a |
| 150.0 |
| 150.0 |
| 12.8 |
| 5.9 |
| ||||
Tidewater Midstream and Infrastructure Ltd. |
| Canada |
| n/a |
| — |
| 64.1 |
| 1.7 |
| 1.2 |
| ||||
|
|
|
|
|
| $ | 567.0 |
| $ | 621.4 |
| $ | 31.4 |
| $ | 3.4 |
|
(a) ASTC was dissolved in 2016.
Summarized combined financial information, assuming a 100 percent ownership interest in the AltaGas’ equity investments listed above, is as follows:
Year ended December 31 |
| 2017 |
| 2016 |
| ||
Revenues |
| $ | 110.6 |
| $ | 178.6 |
|
Expenses |
| (74.2 | ) | (147.9 | ) | ||
|
| $ | 36.4 |
| $ | 30.7 |
|
As at December 31 |
| 2017 |
| 2016 |
| ||
Current assets |
| $ | 24.8 |
| $ | 67.2 |
|
Property, plant and equipment |
| $ | 82.8 |
| $ | 528.6 |
|
Intangible assets |
| $ | 5.6 |
| $ | 28.3 |
|
Long-term investments and other assets |
| $ | 843.3 |
| $ | 834.1 |
|
Current liabilities |
| $ | (41.7 | ) | $ | (53.5 | ) |
Other long-term liabilities |
| $ | (189.1 | ) | $ | (361.1 | ) |
Petrogas Preferred Shares
AltaGas, indirectly through its investment in AIJVLP holds a one-third equity interest in Petrogas. On June 29, 2016, AltaGas, directly invested $150.0 million to subscribe for 6,000,000 cumulative redeemable convertible preferred shares of Petrogas. These preferred shares form part of AltaGas’ overall investment in Petrogas and entitle AltaGas to a fixed, cumulative, preferential cash dividend at a rate of 8.5 percent per annum payable quarterly. These preferred shares are, in the normal course, redeemable at any time on or after January 1, 2018 and convertible into a specified number of common shares at the option of either holder at any time on or after April 19, 2018. For the year ended December 31, 2017, AltaGas received dividend income of $12.8 million (2016 - $5.9 million) from the Petrogas preferred shares, which has been included in the Consolidated Statement of Income under the line item “Income from equity investments”.
ASTC and the Sundance B PPAs
In the first quarter of 2016, ASTC exercised its right to terminate the Sundance B Power Purchase Arrangements for Sundance B Unit 3 and Unit 4 (collectively, the Sundance B PPAs) effective March 8, 2016 pursuant to the change in law provisions. As a result, AltaGas recognized a pre-tax provision of $4.0 million in the Consolidated Statement of Income under the line item “Income from equity investments” for the year ended December 31, 2016 on its investment in ASTC to settle the working deficiency.
In December 2016, AltaGas Pipeline Partnership and TransCanada Energy Ltd. dissolved ASTC. On December 16, 2016, AltaGas Pipeline Partnership and the Government of Alberta reached a definitive settlement agreement regarding the termination of the Sundance B PPAs. Under the settlement agreement, AltaGas has agreed to contribute 391,879 self-generated carbon offsets and make a total of $6.0 million in cash payments payable in equal installments over three years starting in 2018. AltaGas Pipeline Partnership and ASTC were granted a full release from all past, present and future obligations respecting the Sundance B PPAs by the Government of Alberta. As a result of the settlement, AltaGas recorded an overall pre-tax termination expense of approximately $8.4 million for the year ended December 31, 2016, which included the $6.0 million of future cash payments, the costs of the self-generated carbon offsets and associated revenue (See Note 16).
Tidewater
AltaGas received 43.7 million of common shares of Tidewater valued at $1.48 per share as part of the proceeds from the Tidewater Gas Asset Disposition on February 29, 2016 (see Note 3). AltaGas accounted for its investment in Tidewater common shares using the equity method up until the end of May 2017 when AltaGas concluded that it no longer exercised significant influence over Tidewater. Consequently, AltaGas ceased accounting for the investment under the equity method and reclassified the carrying value of the investment of approximately $65.4 million to “Long-term investments and other assets”. The Tidewater common shares are now recorded at fair value and subsequent changes in fair value are recognized in the Consolidated Statement of Income under “Other income”.
Provisions on investments accounted for by the equity method
No provisions were recorded for the year ended December 31, 2017. For the year ended December 31, 2016, pre-tax provision of $4.0 million was recorded on the investment in ASTC.
13. SHORT-TERM DEBT
As at |
| December 31, |
| December 31, |
| ||
Bank indebtedness (a) |
| $ | 6.2 |
| $ | 6.0 |
|
US$150 million operating facility (b) |
| 31.7 |
| 116.8 |
| ||
$25 million operating facility (c) |
| 8.9 |
| 5.9 |
| ||
|
| $ | 46.8 |
| $ | 128.7 |
|
(a) Bank indebtedness bears interest at the lender’s prime rate or at the interest rate applicable to bankers’ acceptances. The prime lending rate at December 31, 2017 was 3.2 percent (December 31, 2016 — 2.7 percent).
(b) As at December 31, 2017, SEMCO held a US$150 million (December 31, 2016 - US$150.0 million) unsecured revolving operating credit facility with a Canadian chartered bank with a maturity date of December 15, 2022. Draws on the facility can be by way of U.S. base-rate loans, letters of credit and LIBOR loans. Letters of credit outstanding under this facility as at December 31, 2017 were $0.6 million (December 31, 2016 - $0.7 million).
(c) As at December 31, 2017, AltaGas held a $25.0 million (December 31, 2016 - $25.0 million) bank operating facility which is available for working capital purposes and expires on May 22, 2018. Draws on the facility are by way of prime-rate advances, bankers’ acceptances or letters of credit at the bank’s prime rate or for a fee. Letters of credit outstanding under this facility as at December 31, 2017 were $3.7 million (December 31, 2016 - $3.9 million).
Other Credit Facilities
As at December 31, 2017, the Corporation held a $50.0 million (December 31, 2016 - $50.0 million) unsecured demand revolving operating credit facility with a Canadian chartered bank. Draws on the facility bear interest at the lender’s prime rate or at the bankers’ acceptance rate plus a stamping fee. Letters of credit outstanding under this facility as at December 31, 2017 were $nil (December 31, 2016 - $nil).
As at December 31, 2017, AltaGas Utility Group Inc. held a $20.0 million (December 31, 2016 - $20.0 million) unsecured, uncommitted demand operating credit facility with a Canadian chartered bank. Draws on the facility can be by way of prime rate loans, U.S. base-rate loans, letters of credit, bankers’ acceptances and LIBOR loans. Letters of credit outstanding under this facility as at December 31, 2017 were $3.5 million (December 31, 2016 - $3.7 million).
As at December 31, 2017, AltaGas held a $150.0 million (December 31, 2016 - $150.0 million) unsecured four-year extendible revolving letter of credit facility. Draws on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers’ acceptances or letters of credit. Letters of credit outstanding under this facility as at December 31, 2017 were $40.8 million (December 31, 2016 - $49.1 million).
As at December 31, 2017, AltaGas held a $150.0 million (December 31, 2016 - $150.0 million) unsecured bilateral letter of credit demand facility with a Canadian chartered bank. Borrowings on the facility incur fees and interest at rates relevant to the nature of the draws made. Letters of credit outstanding under this facility as at December 31, 2017 were $71.3 million (December 31, 2016 - $104.0 million).
14. LONG-TERM DEBT
|
|
|
| December 31, |
| December 31, |
| ||
As at |
| Maturity date |
| 2017 |
| 2016 |
| ||
Credit facilities |
|
|
|
|
|
|
| ||
$1,400 million unsecured extendible revolving(a) |
| 15-Dec-2020 |
| $ | 219.1 |
| $ | 377.9 |
|
US$300 million unsecured extendible revolving(b) |
| 8-Dec-2019 |
| — |
| — |
| ||
Medium-term notes (MTNs) |
|
|
|
|
|
|
| ||
$200 million Senior unsecured - 5.49 percent |
| 27-Mar-2017 |
| — |
| 200.0 |
| ||
$175 million Senior unsecured - 4.60 percent |
| 15-Jan-2018 |
| 175.0 |
| 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 |
| — |
| ||
$250 million Senior unsecured - 4.99 percent |
| 4-Oct-2047 |
| 250.0 |
| — |
| ||
US$125 million Senior unsecured - floating(c) |
| 17-Apr-2017 |
| — |
| 167.8 |
| ||
SEMCO long-term debt |
|
|
|
|
|
|
| ||
US$300 million SEMCO Senior secured - 5.15 percent(d) |
| 21-Apr-2020 |
| 376.4 |
| 402.8 |
| ||
US$82 million CINGSA Senior secured - 4.48 percent(e) |
| 2-Mar-2032 |
| 85.2 |
| 97.5 |
| ||
Debenture notes |
|
|
|
|
|
|
| ||
PNG RoyNat Debenture(f) |
| 15-Sep-2017 |
| — |
| 7.4 |
| ||
PNG 2018 Series Debenture - 8.75 percent(f) |
| 15-Nov-2018 |
| 7.0 |
| 8.0 |
| ||
PNG 2025 Series Debenture - 9.30 percent(f) |
| 18-Jul-2025 |
| 13.0 |
| 13.5 |
| ||
PNG 2027 Series Debenture - 6.90 percent(f) |
| 2-Dec-2027 |
| 14.0 |
| 14.5 |
| ||
CINGSA capital lease - 3.50 percent |
| 1-May-2040 |
| 0.5 |
| 0.6 |
| ||
CINGSA capital lease - 4.48 percent |
| 4-Jun-2068 |
| 0.2 |
| 0.2 |
| ||
|
|
|
| $ | 3,639.8 |
| $ | 3,764.7 |
|
Less debt issuance costs |
|
|
| (14.4 | ) | (14.4 | ) | ||
|
|
|
| 3,625.4 |
| 3,750.3 |
| ||
Less current portion |
|
|
| (188.9 | ) | (383.4 | ) | ||
|
|
|
| $ | 3,436.5 |
| $ | 3,366.9 |
|
(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) The notes carried a floating rate coupon of three months LIBOR plus 0.85 percent.
(d) Collateral for the US$ MTNs is certain SEMCO assets.
(e) 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.
(f) Collateral for the Secured Debentures consists 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.
15. ASSET RETIREMENT OBLIGATIONS
As at |
| December 31, |
| December 31, |
| ||
Balance, beginning of year |
| $ | 81.6 |
| $ | 67.9 |
|
Obligations acquired |
| — |
| 11.3 |
| ||
New obligations |
| 1.5 |
| 0.7 |
| ||
Obligations settled |
| (4.0 | ) | (3.8 | ) | ||
Revision in estimated cash flow |
| 6.0 |
| 2.1 |
| ||
Accretion expense |
| 4.4 |
| 4.2 |
| ||
Foreign exchange translation |
| (0.9 | ) | (0.4 | ) | ||
Reclassified to liabilities associated with assets held for sale (note 4) |
| (0.3 | ) | (0.4 | ) | ||
Balance, end of year |
| $ | 88.3 |
| $ | 81.6 |
|
The majority of the asset retirement obligations are associated with gas processing facilities in the Gas segment.
AltaGas estimates the undiscounted cash required to settle the asset retirement obligations, excluding growth for inflation, at December 31, 2017 was $232.9 million (December 31, 2016 - $225.9 million).
The asset retirement obligations have been recorded in the Consolidated Financial Statements at estimated values discounted at rates between 4.0 and 8.5 percent and are expected to be incurred between 2018 and 2164. No assets have been legally restricted for settlement of the estimated liability.
In May 2014, the National Energy Board (NEB) issued a decision establishing that, by January 1, 2015, all NEB-regulated companies must have a mechanism in place for the accumulation of funds to pay for future pipeline abandonment. AltaGas Holdings Inc., a wholly-owned subsidiary of AltaGas, opted to comply with the NEB decision with a surety bond supplied by a surety company regulated by the Office of the Superintendent of Financial Institutions in the amount of $30.3 million.
16. OTHER LONG-TERM LIABILITIES
As at |
| December 31, |
| December 31, |
| ||
Deferred lease payable |
| $ | 2.4 |
| $ | 0.7 |
|
Deferred revenue |
| 3.8 |
| 4.0 |
| ||
Customer advances for construction |
| 40.9 |
| 43.9 |
| ||
NTL liability |
| 142.0 |
| 146.8 |
| ||
Sundance B PPA termination expense (a) |
| 4.0 |
| 6.0 |
| ||
Lease Inducement |
| 3.1 |
| 3.1 |
| ||
Other long-term liabilities |
| 5.7 |
| 1.8 |
| ||
|
| $ | 201.9 |
| $ | 206.3 |
|
(a) On December 16, 2016, AltaGas Pipeline Partnership and the Government of Alberta reached a definitive settlement agreement regarding the termination of the Sundance B PPAs. Under the settlement agreement, AltaGas has agreed to make a total of $6.0 million in cash payments in equal annual installments over three years starting in 2018, $2.0 million of which have been recorded under “Accounts payable and accrued liabilities”.
NTL Liability
In 2010, AltaGas entered into a 60-year CPI-indexed Electricity Purchase Agreement (EPA) and other related agreements with BC Hydro for the 195-MW Forrest Kerr run-of-river hydroelectric facility. As part of the related agreements, AltaGas agreed to pay BC Hydro annual payments of approximately $11.0 million per year, adjusted for inflation, in support of the construction and operation of the Northwest Transmission Line (NTL) until 2034.
The fair value of the firm commitment on initial recognition was measured using an estimated 2 percent inflation rate and 4.27 percent discount rate. As at December 31, 2017, the NTL liability has been recorded within other current liabilities for $11.5 million (December 31, 2016 - $11.3 million) and other long-term liabilities for $142.0 million (December 31, 2016 - $146.8
million). Accretion expense for the year ended December 31, 2017 was $6.5 million (2016 - $6.8 million). The initial consideration and the fair value of the future consideration of $258.5 million has been recognized within intangible assets and is being depreciated over 60 years, the term of the EPA with BC Hydro.
17. INCOME TAXES
Year ended December 31 |
| 2017 |
| 2016 |
| ||
Income before income taxes - consolidated |
| $ | 66.4 |
| $ | 246.2 |
|
Statutory income tax rate (%) |
| 27.0 |
| 27.0 |
| ||
Expected taxes at statutory rates |
| $ | 17.9 |
| $ | 66.5 |
|
Add (deduct) the tax effect of: |
|
|
| — |
| ||
Permanent differences |
| 9.5 |
| (1.9 | ) | ||
Statutory and other rate differences |
| (25.5 | ) | (0.3 | ) | ||
Rate adjustment for change in tax rates |
| (34.1 | ) | — |
| ||
Deferred income tax recovery on regulated assets |
| (7.4 | ) | (5.7 | ) | ||
Other |
| 6.1 |
| (25.8 | ) | ||
|
| $ | (33.5 | ) | $ | 32.8 |
|
Income tax provision |
|
|
|
|
| ||
Current |
|
|
|
|
| ||
Canada |
| 18.0 |
| 10.0 |
| ||
United States |
| 12.5 |
| 14.4 |
| ||
|
| $ | 30.5 |
| $ | 24.4 |
|
Deferred |
|
|
|
|
| ||
Canada |
| (7.4 | ) | (28.7 | ) | ||
United States |
| (56.6 | ) | 37.1 |
| ||
|
| $ | (64.0 | ) | $ | 8.4 |
|
Effective income tax rate (%) |
| (50.5 | ) | 13.3 |
| ||
Net deferred income tax liabilities were composed of the following:
As at |
| December 31, |
| December 31, |
| ||
PP&E and intangible assets |
| $ | 726.5 |
| $ | 737.0 |
|
Regulatory assets |
| 22.8 |
| 37.3 |
| ||
Tax pools, deferred financing and compensation |
| (302.3 | ) | (208.2 | ) | ||
Other |
| (59.3 | ) | 8.9 |
| ||
Valuation allowance |
| 53.7 |
| 43.9 |
| ||
|
| $ | 441.4 |
| $ | 618.9 |
|
The amount shown on the Consolidated Balance Sheets as deferred income tax liabilities represents the net differences between the tax basis and book carrying values on the Corporation’s balance sheets at enacted tax rates.
The Tax Cuts and Jobs Act (the U.S. tax reform) in the U.S. became law on December 22, 2017. The law includes significant changes to the U.S. corporate income tax system, including a federal corporate rate reduction from 35 percent to 21 percent beginning in 2018, changes to capital depreciation, limitations on the deductibility of interest expense and executive compensation, and the transition of U.S. international taxation from a worldwide tax system to a territorial tax system.
At December 31, 2017, as a result of the U.S. tax reform, the Corporation remeasured its U.S. deferred tax liability based upon the new statutory federal rate of 21 percent. This remeasurement resulted in a net reduction to the deferred tax liability in the amount of $135.9 million. As the Corporation’s U.S. utilities are subject to rate regulation, $101.8 million of the deferred tax remeasurement was recorded as a deferred regulatory liability on the Corporation’s Consolidated Balance Sheet. For the Corporation’s non-regulated U.S. businesses, the remeasurement was recorded as a $34.1 million reduction to income tax expense.
In addition to the U.S. federal rate change, the government of British Columbia increased the corporate tax rate to 12 percent from 11 percent beginning in 2018.
As at December 31, 2017, the Corporation had tax-effected non-capital losses of approximately $233.8 million for tax purposes, which will be available to offset future taxable income. If not used, these losses will expire between 2023 and 2037.
Uncertain Tax Positions
On an annual basis the Corporation and its subsidiaries file tax returns in Canada and various foreign jurisdictions. In Canada AltaGas’ federal and provincial tax returns for the years 2009 to 2016 remain subject to examination by taxation authorities. In the United States both the federal and state tax returns filed for the years 2011 to 2016 remain subject to examination by the taxation authorities.
Management determined that the following provision was required for uncertainty on income taxes during the year:
Year ended December 31 |
| 2017 |
| 2016 |
| ||
Balance, beginning of year |
| $ | 2.2 |
| $ | 3.7 |
|
Net changes during the year |
| 3.7 |
| (1.5 | ) | ||
Balance, end of year |
| $ | 5.9 |
| $ | 2.2 |
|
18. REGULATORY ASSETS AND LIABILITIES
AltaGas accounts for certain transactions in accordance with ASC 980, Regulated Operations. AltaGas refers to this accounting guidance for regulated entities as “regulatory accounting”. Under regulatory accounting, utilities are permitted to defer expenses and income as regulatory assets and liabilities, respectively, in the Consolidated Balance Sheet when it is probable that those expenses and income will be allowed in the rate-setting process in a period different from the period in which they would have been reflected in the Consolidated Statement of Income by a non-rate-regulated entity. These deferred regulatory assets and liabilities are included in the Consolidated Statement of Income in future periods when the amounts are reflected in customer rates. Management’s assessment of the probability of recovery or pass-through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory agency orders, rules, and rate-making conventions. The relevant regulatory bodies are the AUC, BCUC, and NSUARB in Canada, and the MPSC and RCA in the United States.
If, for any reason, the Corporation ceases to meet the criteria for application of regulatory accounting for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be de-recognized from the Consolidated Balance Sheet and included in the Consolidated Statement of Income for the period in which the discontinuance of regulatory accounting occurs. Criteria that give rise to the discontinuance of regulatory accounting include: (i) increasing competition that restricts the ability of the Corporation to charge prices sufficient to recover specific costs, and (ii) a significant change in the manner in which rates are set by regulatory agencies from cost-based regulation to another form of regulation. The Corporation’s review of these criteria currently supports the continued application of regulatory accounting for all its utilities.
The following table summarizes the regulatory assets and liabilities recorded in the Consolidated Balance Sheets, as well as the remaining period, as of December 31, 2017 and 2016, over which the Corporation expects to realize or settle the assets or liabilities:
As at |
| December 31, |
| December 31, |
| Recovery |
| ||
Regulatory assets - current |
|
|
|
|
|
|
| ||
Deferred cost of gas |
| $ | 0.5 |
| $ | 0.8 |
| Less than one year |
|
Deferred property taxes |
| 0.3 |
| 0.1 |
| Less than one year |
| ||
Energy optimization costs |
| 0.3 |
| — |
| Less than one year |
| ||
|
| $ | 1.1 |
| $ | 0.9 |
|
|
|
Regulatory assets - non-current |
|
|
|
|
|
|
| ||
Deferred regulatory costs and rate stabilization adjustment mechanism |
| $ | 20.5 |
| $ | 18.0 |
| 1 - 28 years |
|
Pipeline rehabilitation costs |
| 0.3 |
| 6.7 |
| 1-3 years |
| ||
Future recovery of pension and other retirement benefits (a) |
| 113.9 |
| 114.7 |
| Various |
| ||
Deferred environmental costs |
| 13.9 |
| 18.0 |
| 1-10 years |
| ||
Deferred loss on reacquired debt |
| 2.5 |
| 3.4 |
| 2-14 years |
| ||
Deferred depreciation and amortization (b) |
| 23.3 |
| 24.0 |
| Various |
| ||
Deferred future income taxes (c) |
| 104.7 |
| 104.7 |
| Various |
| ||
Deferred customer retention program amortization (d) |
| 16.5 |
| 6.4 |
| Various |
| ||
Revenue deficiency account (e) |
| 31.0 |
| 29.2 |
| Various |
| ||
Other |
| 2.0 |
| 4.0 |
| Various |
| ||
|
| $ | 328.6 |
| $ | 329.1 |
|
|
|
Regulatory liabilities - current |
|
|
|
|
|
|
| ||
Deferred cost of gas |
| $ | 9.0 |
| $ | 13.7 |
| Less than one year |
|
Energy optimization costs |
| — |
| 0.6 |
| Less than one year |
| ||
Interruptible storage service revenue |
| — |
| 0.3 |
| Less than one year |
| ||
Refundable tax credit (f) |
| 1.9 |
| 2.0 |
| Less than one year |
| ||
|
| $ | 10.9 |
| $ | 16.6 |
|
|
|
Regulatory liabilities - non-current |
|
|
|
|
|
|
| ||
Option fees deferral (g) |
| $ | 4.3 |
| $ | 4.1 |
| Various |
|
Refundable tax credit (f) |
| 7.5 |
| 10.1 |
| 4 years |
| ||
Future removal and site restoration costs (h) |
| 153.3 |
| 154.9 |
| Various |
| ||
Federal income tax rate change (i) |
| 101.8 |
| — |
| Various |
| ||
Insurance recovery of environmental costs |
| 0.3 |
| 0.5 |
| 1 year |
| ||
Other |
| 1.4 |
| 0.9 |
| Various |
| ||
|
| $ | 268.6 |
| $ | 170.5 |
|
|
|
(a) Certain utilities have recovered pension costs related to regulated operations in rates, and as such the Corporation has recorded a regulatory asset for the unamortized costs associated with the defined benefit and post-retirement benefit plans. Depending on the method utilized by the utility the recovery period can be either the expected service life of the employees or the benefit period for employees or a specific recovery period as approved by the respective regulator.
(b) Pursuant to the NSUARB decisions in 2009 and 2011, Heritage Gas was ordered to suspend amortization of property, plant and equipment and intangible assets for regulatory purposes for the fiscal periods from 2009 to 2013. The NSUARB, in its decision dated November 24, 2011, directed amortization to be phased in over a four year period at the following rates: 2014 at 25 percent of the authorized rates; 2015 at 50 percent of the authorized rates; 2016 at 75 percent of the authorized rates; and 2017 at 100 percent of the authorized rates. As a result of this order, the Heritage Gas recognizes a regulatory asset equal to the amortization that would have otherwise been included in rates.
(c) This regulatory asset reflects the amount of deferred income taxes expected to be refunded, or recovered from, customers in future rates.
(d) In September 2016, the NSUARB approved Heritage Gas’ Customer Retention Program application to decrease distribution rates for certain commercial and residential customers, suspend depreciation and to increase the capitalization rate for operating, maintenance and administrative expenses effective March 22, 2016.
(e) Heritage Gas has an approval from the NSUARB to use a revenue deficiency account (RDA) until it is fully recovered, subject to a cap of $50 million, imposed in 2010, which may be increased subject to approval by the NSUARB. The RDA is the cumulative difference between the revenue requirements and the actual amounts billed to customers.
(f) On September 18, 2013, CINGSA received a US$15.0 million gas storage facility tax credit from the State of Alaska for the benefit of its firm storage service customers. CINGSA will derive no direct or indirect benefit from the tax credit. Following receipt of the tax credit, CINGSA deposited it in a separate interest-bearing account. CINGSA will act as a custodian of the tax credit and any interest earned for the benefit of CINGSA’s customers. On an annual basis, covering the years 2012 through 2021, CINGSA will disburse to the customers 1/10th of the amount of the tax credit not subject to refund to the State and interest earned. The RCA has approved the disbursement methodology.
(g) Pursuant to BCUC approved negotiated settlement agreement.
(h) This amount and timing of draw down is dependent upon the cost of removal of underlying utility property, plant and equipment and the life of property, plant and equipment.
(i) The Tax Cuts and Jobs Act (the U.S. tax reform) was enacted on December 22, 2017, and required the Corporation to revalue its U.S. deferred tax assets and liabilities to the lower federal corporate tax rate of 21 percent resulting in excess accumulated deferred income taxes. The tax rate reduction created a reduction in deferred tax liability, which SEMCO Gas is required to refund to its ratepayers.
19. ACCUMULATED OTHER COMPREHENSIVE INCOME
($ millions) |
| Available- |
| Defined |
| Hedge net |
| Translation |
| Equity |
| Total |
| ||||||
Opening balance, January 1, 2017 |
| $ | 19.8 |
| $ | (11.3 | ) | $ | (135.6 | ) | $ | 526.3 |
| $ | 5.9 |
| $ | 405.1 |
|
OCI before reclassification |
| (30.3 | ) | (1.3 | ) | 6.6 |
| (183.4 | ) | (2.2 | ) | (210.6 | ) | ||||||
Amounts reclassified from OCI |
| — |
| 1.3 |
| — |
| — |
| — |
| 1.3 |
| ||||||
Current period OCI (pre-tax) |
| (30.3 | ) | — |
| 6.6 |
| (183.4 | ) | (2.2 | ) | (209.3 | ) | ||||||
Income tax on amounts retained in AOCI |
| 3.4 |
| 0.3 |
| — |
| — |
| — |
| 3.7 |
| ||||||
Income tax on amounts reclassified to earnings |
| — |
| (0.4 | ) | — |
| — |
| — |
| (0.4 | ) | ||||||
Net current period OCI |
| (26.9 | ) | (0.1 | ) | 6.6 |
| (183.4 | ) | (2.2 | ) | (206.0 | ) | ||||||
Ending balance, December 31, 2017 |
| $ | (7.1 | ) | $ | (11.4 | ) | $ | (129.0 | ) | $ | 342.9 |
| $ | 3.7 |
| $ | 199.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Opening balance, January 1, 2016 |
| $ | (2.4 | ) | $ | (9.6 | ) | $ | (169.6 | ) | $ | 610.5 |
| $ | 4.6 |
| $ | 433.5 |
|
OCI before reclassification |
| 25.6 |
| (3.4 | ) | 44.6 |
| (84.2 | ) | 1.3 |
| (16.1 | ) | ||||||
Amounts reclassified from OCI |
| — |
| 1.0 |
| — |
| — |
| — |
| 1.0 |
| ||||||
Current period OCI (pre-tax) |
| 25.6 |
| (2.4 | ) | 44.6 |
| (84.2 | ) | 1.3 |
| (15.1 | ) | ||||||
Income tax on amounts retained in AOCI |
| (3.4 | ) | 1.0 |
| (10.6 | ) | — |
| — |
| (13.0 | ) | ||||||
Income tax on amounts reclassified to earnings |
| — |
| (0.3 | ) | — |
| — |
| — |
| (0.3 | ) | ||||||
Net current period OCI |
| 22.2 |
| (1.7 | ) | 34.0 |
| (84.2 | ) | 1.3 |
| (28.4 | ) | ||||||
Ending balance, December 31, 2016 |
| $ | 19.8 |
| $ | (11.3 | ) | $ | (135.6 | ) | $ | 526.3 |
| $ | 5.9 |
| $ | 405.1 |
|
Reclassification From Accumulated Other Comprehensive Income
|
|
|
| For the year ended |
| ||||
AOCI components reclassified |
| Income statement line item |
| 2017 |
| 2016 |
| ||
Defined benefit pension and PRB plans |
| Operating and administrative expense |
| $ | 1.3 |
| $ | 1.0 |
|
Deferred income taxes |
| Income tax expenses — deferred |
| (0.4 | ) | (0.3 | ) | ||
|
|
|
| $ | 0.9 |
| $ | 0.7 |
|
20. 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. AltaGas estimates forward prices based on published sources adjusted for factors specific to the asset or liability, including basis and location differentials, discount rates, and currency exchange. The forward curves used to mark-to-market these derivative instruments are vetted against public sources.
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.
The following methods and assumptions were used to estimate the fair value of each significant class of financial instruments:
Cash and cash equivalents, Accounts receivable, Accounts payable, Other current liabilities, Short-term debt and Dividends payable - the carrying amounts approximate fair value because of the short maturity of these instruments.
Current portion of long-term debt, Long-term debt and Other long-term liabilities - the fair value of these liabilities has been estimated based on discounted future interest and principal payments using the current market interest rates of instruments with similar terms.
Risk management assets and liabilities - the fair values of power, natural gas and NGL derivative contracts were calculated using forward prices from published sources for the relevant period. 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
|
| December 31, 2017 |
| |||||||||||||
|
| Carrying |
| Level 1 |
| Level 2 |
| Level 3 |
| Total |
| |||||
Financial assets |
|
|
|
|
|
|
|
|
|
|
| |||||
Cash and cash equivalents |
| $ | 27.3 |
| $ | 27.3 |
| $ | — |
| $ | — |
| $ | 27.3 |
|
Risk management assets - current |
| 38.6 |
| — |
| 38.6 |
| — |
| 38.6 |
| |||||
Risk management assets - non-current |
| 15.9 |
| — |
| 15.9 |
| — |
| 15.9 |
| |||||
Long-term investments and other assets (a) |
| 170.0 |
| 95.0 |
| 85.6 |
| — |
| 180.6 |
| |||||
|
| $ | 251.8 |
| $ | 122.3 |
| $ | 140.1 |
| $ | — |
| $ | 262.4 |
|
Financial liabilities |
|
|
|
|
|
|
|
|
|
|
| |||||
Risk management liabilities - current |
| $ | 57.6 |
| $ | — |
| $ | 57.6 |
| $ | — |
| $ | 57.6 |
|
Risk management liabilities - non-current |
| 13.8 |
| — |
| 13.8 |
| — |
| 13.8 |
| |||||
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) Excludes non-financial assets.
(b) Excludes non-financial liabilities.
|
| December 31, 2016 |
| |||||||||||||
|
| Carrying |
| Level 1 |
| Level 2 |
| Level 3 |
| Total |
| |||||
Financial assets |
|
|
|
|
|
|
|
|
|
|
| |||||
Cash and cash equivalents |
| $ | 19.0 |
| $ | 19.0 |
| $ | — |
| $ | — |
| $ | 19.0 |
|
Risk management assets - current |
| 40.4 |
| — |
| 40.4 |
| — |
| 40.4 |
| |||||
Risk management assets - non-current |
| 24.1 |
| — |
| 24.1 |
| — |
| 24.1 |
| |||||
Long-term investments and other assets (a) |
| 113.0 |
| 49.4 |
| 63.6 |
| — |
| 113.0 |
| |||||
|
| $ | 196.5 |
| $ | 68.4 |
| $ | 128.1 |
| $ | — |
| $ | 196.5 |
|
Financial liabilities |
|
|
|
|
|
|
|
|
|
|
| |||||
Risk management liabilities - current |
| $ | 32.9 |
| $ | — |
| $ | 32.9 |
| — |
| $ | 32.9 |
| |
Risk management liabilities - non-current |
| 12.6 |
| — |
| 12.6 |
| — |
| 12.6 |
| |||||
Current portion of long-term debt |
| 383.4 |
| — |
| 385.3 |
| — |
| 385.3 |
| |||||
Long-term debt |
| 3,366.9 |
| — |
| 3,500.9 |
| — |
| 3,500.9 |
| |||||
Other current liabilities (b) |
| 22.3 |
| — |
| 22.0 |
| — |
| 22.0 |
| |||||
Other long-term liabilities (b) |
| 152.8 |
| — |
| 152.4 |
| — |
| 152.4 |
| |||||
|
| $ | 3,970.9 |
| $ | — |
| $ | 4,106.1 |
| $ | — |
| $ | 4,106.1 |
|
(a) Excludes non-financial assets.
(b) Excludes non-financial liabilities.
Summary of Unrealized Gains (Losses) on Risk Management Contracts Recognized in Net Income
For the year ended December 31 |
| 2017 |
| 2016 |
| ||
Natural gas |
| $ | 2.2 |
| $ | 0.2 |
|
Storage optimization |
| 2.7 |
| (5.3 | ) | ||
NGL frac spread |
| (11.7 | ) | (12.2 | ) | ||
Power |
| (20.8 | ) | 4.7 |
| ||
Heat rate |
| — |
| (0.1 | ) | ||
Foreign exchange |
| (34.9 | ) | 1.0 |
| ||
Embedded derivative |
| — |
| 0.3 |
| ||
|
| $ | (62.5 | ) | $ | (11.4 | ) |
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 related financial assets and financial liabilities.
|
| December 31, 2017 |
| |||||||
Risk management assets (a) |
| Gross amounts of |
| Gross amounts |
| Net amounts |
| |||
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.
|
| December 31, 2016 |
| |||||||
Risk management assets (a) |
| Gross amounts of |
| Gross amounts |
| Net amounts |
| |||
Natural gas |
| $ | 20.1 |
| $ | (2.9 | ) | $ | 17.2 |
|
Storage optimization |
| 0.7 |
| (0.7 | ) | — |
| |||
NGL frac spread |
| 3.4 |
| — |
| 3.4 |
| |||
Power |
| 43.5 |
| — |
| 43.5 |
| |||
Foreign exchange |
| 1.8 |
| (1.4 | ) | 0.4 |
| |||
|
| $ | 69.5 |
| $ | (5.0 | ) | $ | 64.5 |
|
|
|
|
|
|
|
|
| |||
Risk management liabilities (b) |
|
|
|
|
|
|
| |||
Natural gas |
| $ | 16.5 |
| $ | (2.9 | ) | $ | 13.6 |
|
Storage optimization |
| 3.5 |
| (0.7 | ) | 2.8 |
| |||
NGL frac spread |
| 15.7 |
| — |
| 15.7 |
| |||
Power |
| 13.4 |
| — |
| 13.4 |
| |||
Foreign exchange |
| 1.4 |
| (1.4 | ) | — |
| |||
|
| $ | 50.5 |
| $ | (5.0 | ) | $ | 45.5 |
|
(a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $40.4 million and risk management assets (non-current) balance of $24.1 million.
(b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $32.9 million and risk management liabilities (non-current) balance of $12.6 million.
Risks associated with financial instruments
AltaGas is exposed to various financial risks in the normal course of operations such as market risks resulting from fluctuations in commodity prices, currency exchange rates and interest rates as well as credit risk and liquidity risk.
Commodity Price Risk
AltaGas enters into financial derivative contracts to manage exposure to fluctuations in commodity prices. The use of derivative instruments is governed under formal risk management policies and is subject to parameters set out by AltaGas’ Risk Management Committee and Board of Directors. AltaGas does not make use of derivative instruments for speculative purposes.
Natural Gas
In the normal course of business, AltaGas purchases and sells natural gas to support its infrastructure business. The fixed price and market price contracts for both the purchase and sale of natural gas extend to 2022. AltaGas had the following forward contracts and commodity swaps outstanding related to the activities in the energy services business as at December 31, 2017 and 2016:
December 31, 2017 |
| Fixed price |
| Period |
| Notional volume |
| Fair Value |
|
Sales |
| 0.42 to 6.89 |
| 1-60 |
| 94,804,039 |
| 14.8 |
|
Purchases |
| 0.52 to 6.40 |
| 1-48 |
| 61,980,315 |
| (16.8 | ) |
Swaps |
| 2.86 to 9.38 |
| 1-10 |
| 6,039,642 |
| 7.9 |
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016 |
| Fixed price |
| Period |
| Notional volume |
| Fair Value |
|
Sales |
| 1.96 to 8.46 |
| 1-60 |
| 63,209,420 |
| 6.6 |
|
Purchases |
| 1.94 to 6.50 |
| 1-60 |
| 58,913,082 |
| (4.4 | ) |
Swaps |
| 8.78 to 9.91 |
| 1-3 |
| 474,037 |
| 1.4 |
|
NGL Frac Spread
AltaGas entered into a series of swaps to lock in a portion of the volumes exposed to NGL frac spread. AltaGas had the following contracts outstanding as at December 31, 2017 and 2016:
December 31, 2017 |
| Fixed price |
| Period |
| Notional volume |
| Fair Value |
|
Propane swaps |
| $28.77 to $49.21 /Bbl |
| 1-12 |
| 1,992,927 Bbl |
| (10.9 | ) |
Butane swaps |
| $47.83 to $54.67 /Bbl |
| 1-12 |
| 130,088 Bbl |
| (0.3 | ) |
Crude oil swaps |
| $61.05 to $75.64 /Bbl |
| 1-12 |
| 518,665 Bbl |
| (4.4 | ) |
Natural gas swaps |
| $0.42 to $2.27 /GJ |
| 1-12 |
| 11,428,515 GJ |
| (8.4 | ) |
|
|
|
|
|
|
|
|
|
|
December 31, 2016 |
| Fixed price |
| Period |
| Notional volume |
| Fair Value |
|
Propane swaps |
| $25.51 to $29.92 /Bbl |
| 1-12 |
| 1,330,063 Bbl |
| (12.5 | ) |
Butane swaps |
| $29.88 /Bbl |
| 1-3 |
| 49,500 Bbl |
| (1.0 | ) |
Crude oil swaps |
| $56.40 to $70.75 /Bbl |
| 1-12 |
| 302,710 Bbl |
| (2.2 | ) |
Natural gas swaps |
| $2.23 to $2.88 /GJ |
| 1-12 |
| 7,639,175 GJ |
| 3.4 |
|
Power
AltaGas sells power to the Alberta Electric System Operator at market prices as well as to commercial and industrial users in Alberta at fixed prices. AltaGas’ strategy is to mitigate the cash flow risk to Alberta power prices to provide predictable earnings. Therefore, AltaGas uses third party swaps and purchase contracts to fix the prices over time on a portion of the volumes to mitigate financial exposure associated with the sale contracts. These power purchase and sale contracts extend to 2022. As at December 31, 2017, AltaGas had no intention to terminate any contracts prior to maturity. AltaGas had the following power commodity forward contracts and commodity swaps outstanding as at December 31, 2017 and 2016:
December 31, 2017 |
| Fixed price |
| Period |
| Notional volume |
| Fair Value |
|
Power sales |
| 38.20 to 95.03 |
| 1-60 |
| 2,169,321 |
| (2.5 | ) |
Power purchases |
| 58.50 |
| 1-12 |
| 17,520 |
| (4.5 | ) |
Swap purchases |
| 37.50 to 63.50 |
| 1-48 |
| 1,563,160 |
| 6.5 |
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016 |
| Fixed price |
| Period |
| Notional volume |
| Fair Value |
|
Power sales |
| 34.00 to 99.25 |
| 1-60 |
| 2,671,748 |
| 36.2 |
|
Power purchases |
| 52.68 to 69.72 |
| 1-24 |
| 217,520 |
| 0.5 |
|
Swap purchases |
| 30.00 to 58.50 |
| 1-60 |
| 1,472,040 |
| (6.6 | ) |
The table below provides the potential impact on pre-tax income due to changes in the fair value of risk management contracts in place as at December 31, 2017:
Factor |
| Increase or |
| Increase or decrease to |
| |
Alberta power price |
| $ | 1/MWh |
| 0.6 |
|
AECO natural gas price |
| $ | 0.50/GJ |
| 2.2 |
|
NGL frac spread: |
|
|
|
|
| |
Propane |
| $ | 1/Bbl |
| 2.0 |
|
Butane |
| $ | 1/Bbl |
| 0.1 |
|
Western Texas Intermediate (WTI) crude oil |
| $ | 1/Bbl |
| 0.8 |
|
Natural gas |
| $ | 0.50/GJ |
| 5.8 |
|
Foreign Exchange Risk
AltaGas is exposed to foreign exchange risk as changes in foreign exchange rates may affect the fair value or future cash flows of the Corporation’s financial instruments. AltaGas has foreign operations whereby the functional currency is the U.S. dollar. As a result, the Corporation’s earnings, cash flows, and OCI are exposed to fluctuations resulting from changes in foreign exchange rates. This risk is partially mitigated to the extent that AltaGas has U.S. dollar-denominated debt and/or preferred shares outstanding. AltaGas may also enter into foreign exchange forward derivatives to manage the risk of fluctuating cash flows due to variations in foreign exchange rates. As at December 31, 2017, AltaGas did not have any outstanding foreign exchange forward contracts. As at December 31, 2016, AltaGas had outstanding foreign exchange forward contracts for US$5.1 million at an average rate of $1.26 Canadian per U.S. dollar which settled in 2017.
AltaGas may also designate its U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. As at December 31, 2017, AltaGas designated $nil of outstanding debt as a net investment hedge (December 31, 2016 - US$301.0 million). For the year ended December 31, 2017, AltaGas incurred an after-tax unrealized gain of $6.6 million arising from the translation of debt in OCI (2016 - after-tax unrealized gain of $34.0 million).
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 approximately 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 year ended December 31, 2017, an unrealized loss of $34.3 million was recognized under the line item “unrealized losses from risk management contracts” in the consolidated statement of income in relation to these contracts (2016 - $nil).
Interest Rate Risk
AltaGas is exposed to interest rate risk as changes in interest rates may impact future cash flows and the fair value of its financial instruments. The Corporation manages its interest rate risk by holding a mix of both fixed and floating interest rate debt. As at December 31, 2017, approximately 93 percent of AltaGas’ total outstanding short-term and long-term debt was at fixed rates. In addition, from time to time, AltaGas may enter into interest rate swap agreements to fix the interest rate on a portion of its banker’s acceptances issued under its credit facilities. There were no outstanding interest rate swaps as at December 31, 2017.
Credit Risk
Credit risk results from the possibility that a counterparty to a financial instrument fails to fulfill its obligations in accordance with the terms of the contract.
AltaGas’ credit policy details the parameters used to grant, measure, monitor and report on credit provided to counterparties. AltaGas minimizes counterparty risk by conducting credit reviews on counterparties in order to establish specific credit limits, both prior to providing products or services and on a recurring basis. In addition, most contracts include credit mitigation clauses that allow AltaGas to obtain financial or performance assurances from counterparties under certain circumstances. AltaGas maintains an allowance for doubtful accounts in the normal course of its business.
AltaGas’ maximum credit exposure consists primarily of the carrying value of the non-derivative financial assets and the fair value of derivative financial assets. As at December 31, 2017, AltaGas had no concentration of credit risk with a single counterparty.
Accounts Receivable Past Due or Impaired
AltaGas had the following past due or impaired accounts receivable (AR):
As at December 31, 2017 |
| Total |
| AR |
| Receivables |
| Less than |
| 31 to |
| 61 to |
| Over |
| |||||||
Trade receivable |
| $ | 383.0 |
| $ | 184.6 |
| $ | 2.4 |
| $ | 187.0 |
| $ | 7.9 |
| $ | 1.4 |
| $ | (0.3 | ) |
Other |
| 2.3 |
| — |
| — |
| 2.3 |
| — |
| — |
| — |
| |||||||
Allowance for credit losses |
| (2.4 | ) | — |
| (2.4 | ) | — |
| — |
| — |
| — |
| |||||||
|
| $ | 382.9 |
| $ | 184.6 |
| $ | — |
| $ | 189.3 |
| $ | 7.9 |
| $ | 1.4 |
| $ | (0.3 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
As at December 31, 2016 |
| Total |
| AR |
| Receivables |
| Less than |
| 31 to |
| 61 to |
| Over |
| |||||||
Trade receivable |
| $ | 339.1 |
| $ | 160.4 |
| $ | 2.5 |
| $ | 166.1 |
| $ | 6.4 |
| $ | 2.4 |
| $ | 1.3 |
|
Other |
| 2.2 |
| — |
| — |
| 2.2 |
| — |
| — |
| — |
| |||||||
Allowance for credit losses |
| (2.5 | ) | — |
| (2.5 | ) | — |
| — |
| — |
| — |
| |||||||
|
| $ | 338.8 |
| $ | 160.4 |
| $ | — |
| $ | 168.3 |
| $ | 6.4 |
| $ | 2.4 |
| $ | 1.3 |
|
Allowance for credit losses |
| December 31, |
| December 31, |
| ||
Balance, beginning of year |
| $ | 2.5 |
| $ | 2.7 |
|
Foreign exchange translation |
| (0.1 | ) | — |
| ||
New allowance |
| 0.4 |
| 0.4 |
| ||
Allowance applied to uncollectible customer accounts |
| (0.4 | ) | (0.6 | ) | ||
Balance, end of year |
| $ | 2.4 |
| $ | 2.5 |
|
Liquidity Risk
Liquidity risk is the risk that AltaGas will not be able to meet its financial obligations as they come due. AltaGas manages this risk through its extensive budgeting and monitoring process to ensure it has sufficient cash and credit facilities to meet its obligations. AltaGas’ objective is to maintain its investment-grade ratings to ensure it has access to debt and equity funding as required.
AltaGas had the following contractual maturities with respect to financial liabilities:
|
| Payments due by period |
| |||||||||||||
As at December 31, 2017 |
| Total |
| Less than |
| 1-3 years |
| 4-5 years |
| After |
| |||||
Accounts payable and accrued liabilities |
| $ | 415.3 |
| $ | 415.3 |
| $ | — |
| $ | — |
| $ | — |
|
Dividends payable |
| 32.0 |
| 32.0 |
| — |
| — |
| — |
| |||||
Short-term debt |
| 46.8 |
| 46.8 |
| — |
| — |
| — |
| |||||
Other current liabilities (a) |
| 22.4 |
| 22.4 |
| — |
| — |
| — |
| |||||
Other long-term liabilities (a) |
| 146.0 |
| — |
| 25.7 |
| 20.8 |
| 99.5 |
| |||||
Risk management contract liabilities |
| 71.4 |
| 57.6 |
| 11.1 |
| 2.7 |
| — |
| |||||
Current portion of long-term debt (b) |
| 188.9 |
| 188.9 |
| — |
| — |
| — |
| |||||
Long-term debt (b) |
| 3,450.9 |
| — |
| 1,009.1 |
| 363.8 |
| 2,078.0 |
| |||||
|
| $ | 4,373.7 |
| $ | 763.0 |
| $ | 1,045.9 |
| $ | 387.3 |
| $ | 2,177.5 |
|
(a) Excludes non-financial liabilities
(b) Excludes deferred financing costs and discounts
|
| Payments due by period |
| |||||||||||||
As at December 31, 2016 |
| Total |
| Less than |
| 1-3 years |
| 4-5 years |
| After |
| |||||
Accounts payable and accrued liabilities |
| $ | 345.8 |
| $ | 345.8 |
| $ | — |
| $ | — |
| $ | — |
|
Dividends payable |
| 29.2 |
| 29.2 |
| — |
| — |
| — |
| |||||
Short-term debt |
| 128.7 |
| 128.7 |
| — |
| — |
| — |
| |||||
Other current liabilities (a) |
| 22.3 |
| 22.3 |
| — |
| — |
| — |
| |||||
Other long-term liabilities (a) |
| 152.8 |
| — |
| 25.2 |
| 22.4 |
| 105.2 |
| |||||
Risk management contract liabilities |
| 45.5 |
| 32.9 |
| 9.1 |
| 3.5 |
| — |
| |||||
Current portion of long-term debt (b) |
| 383.5 |
| 383.5 |
| — |
| — |
| — |
| |||||
Long-term debt (b) |
| 3,381.2 |
| — |
| 396.6 |
| 1,345.2 |
| 1,639.4 |
| |||||
|
| $ | 4,489.0 |
| $ | 942.4 |
| $ | 430.9 |
| $ | 1,371.1 |
| $ | 1,744.6 |
|
(a) Excludes non-financial liabilities
(b) Excludes deferred financing costs and discounts
21. 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.
Common Shares
On June 6, 2016, AltaGas closed a public offering of 14,685,000 common shares, on a bought deal basis, at an issue price of $30 per common share, for total gross proceeds of approximately $440.6 million.
Premium DividendTM, Dividend Reinvestment and Optional Cash Purchase Plan (DRIP or the Plan)
The Plan consists of three components: a Premium Dividend™ 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).
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
TM Denotes trademark of Canaccord Genuity Corp.
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 |
| Amount |
| |
January 1, 2016 |
| 146,281,247 |
| $ | 3,168.1 |
|
Shares issued on public offering, net of issuance costs |
| 14,685,000 |
| 422.2 |
| |
Shares issued for cash on exercise of options |
| 337,750 |
| 9.3 |
| |
Deferred taxes on share issuance cost |
| — |
| 0.2 |
| |
Shares issued under DRIP |
| 5,602,836 |
| 173.6 |
| |
December 31, 2016 |
| 166,906,833 |
| 3,773.4 |
| |
Shares issued for cash on exercise of options |
| 240,125 |
| 6.5 |
| |
Deferred taxes on share issuance costs |
| — |
| (8.3 | ) | |
Shares issued under DRIP |
| 8,132,258 |
| 236.3 |
| |
Issued and outstanding at December 31, 2017 |
| 175,279,216 |
| $ | 4,007.9 |
|
Preferred Shares
As at |
| December 31, 2017 |
| December 31, 2016 |
| ||||||
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 |
| — |
| — |
| ||
Share issuance costs, net of taxes |
|
|
| (27.9 | ) |
|
| (20.5 | ) | ||
|
| 52,000,000 |
| $ | 1,277.7 |
| 40,000,000 |
| $ | 985.1 |
|
The following table outlines the characteristics of the cumulative redeemable preferred shares (a):
|
| Current |
| Annual dividend |
| Redemption price |
| Redemption and conversion |
| Right to convert |
| ||||
Series A (e) |
| 3.38 | % | $ | 0.845 |
| $ | 25 |
| September 30, 2020 |
| Series B |
| ||
Series B (f) |
| Floating | (f) | Floating | (f) | $ | 25 |
| September 30, 2020 | (g) | Series A |
| |||
Series C (h) |
| 5.29 | % | US$ | 1.3225 |
| US$ | 25 |
| September 30, 2022 |
| Series D |
| ||
Series E (e) |
| 5.00 | % | $ | 1.25 |
| $ | 25 |
| December 31, 2018 |
| Series F |
| ||
Series G (e) |
| 4.75 | % | $ | 1.1875 |
| $ | 25 |
| September 30, 2019 |
| Series H |
| ||
Series I (i) |
| 5.25 | % | $ | 1.3125 |
| $ | 25 |
| December 31, 2020 |
| Series J |
| ||
Series K (j) |
| 5.00 | % | $ | 1.25 |
| $ | 25 |
| March 31, 2022 |
| Series L |
| ||
(a) The table above only includes those series of preferred shares that are currently issued and outstanding. The Corporation is authorized to issue up to 8,000,000 of each of Series D Shares, Series F Shares, Series H Shares, and Series J Shares, and up to 12,000,000 of Series L Shares, subject to certain conditions, upon conversion by the holders of the applicable currently issued and outstanding series of preferred shares noted opposite such series in the table on the applicable conversion option date. If issued upon the conversion of the applicable series of preferred shares, Series F Shares, Series H Shares, Series J Shares, and Series L Shares are also redeemable for $25.50, and Series D Shares are redeemable for US$25.50 on any date after the applicable conversion option date, plus all accrued but unpaid dividends to, but excluding, the date fixed for redemption.
(b) The holders of Series A Shares, Series C Shares, Series E Shares, Series G Shares, Series I Shares and Series K Shares are entitled to receive a cumulative quarterly fixed dividend as and when declared by the Board of Directors. The holders of Series B Shares are entitled to receive a quarterly floating dividend as and when declared by the Board of Directors. If issued upon the conversion of the applicable series of Preferred Shares, the holders of Series D Shares, Series F Shares, Series H Shares, Series J Shares and Series L Shares will be entitled to receive a quarterly floating dividend as and when declared by the Board of Directors.
(c) AltaGas may, at its option, redeem all or a portion of the outstanding shares for the redemption price per share, plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary thereafter.
(d) The holder will have the right, subject to certain conditions, to convert their preferred shares of a specified series into Preferred Shares of that other specified series as noted in this column of the table on the applicable conversion option date and every fifth anniversary thereafter.
(e) �� Holders will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at a rate equal to the sum of the then five-year Government of Canada bond yield plus 2.66 percent (Series A Shares), 3.17 percent (Series E Shares), and 3.06 percent (Series G Shares).
(f) Holders of Series B Shares will be entitled to receive cumulative quarterly floating dividends, which will reset each quarter thereafter at a rate equal to the sum of the then 90-day government of Canada Treasury Bill rate plus 2.66 percent. Each quarterly dividend is calculated as the annualized amount multiplied by the number of days in the quarter, divided by the number of days in the year. Commencing December 31, 2017, the floating quarterly dividend rate for Series B Shares is $0.21760 per share for the period starting December 31, 2017 to, but excluding, March 31, 2018.
(g) Series B Shares can be redeemed for $25.50 per share on any date after September 30, 2015 that is not a Series B conversion date, plus all accrued and unpaid dividends to, but excluding, the date fixed for redemption.
(h) Holders of Series C Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the sum of the five-year U.S. Government bond yield plus 3.58 percent.
(i) Holders of Series I Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 4.19 percent, provided that, in any event, such rate shall not be less than 5.25 percent per annum.
(j) Holders of Series K Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 3.80 percent, provided that, in any event, such rate shall not be less than 5.00 percent per annum.
Share Option Plan
AltaGas has an employee share option plan under which employees and directors are eligible to receive grants. As at December 31, 2017, 12,994,161 shares were reserved for issuance under the plan. As at December 31, 2017, 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 December 31, 2017, unexpensed fair value of share option compensation cost associated with future periods was $1.3 million (December 31, 2016 - $1.0 million).
The following table summarizes information about the Corporation’s share options:
As at |
| December 31, 2017 |
| December 31, 2016 |
| ||||||
|
| Options outstanding |
| Options outstanding |
| ||||||
|
| Number of |
| Exercise |
| Number of |
| Exercise |
| ||
Share options outstanding, beginning of year |
| 4,119,386 |
| $ | 32.39 |
| 4,559,261 |
| $ | 32.02 |
|
Granted |
| 848,000 |
| 30.80 |
| 89,500 |
| 31.45 |
| ||
Exercised |
| (240,125 | ) | 24.63 |
| (337,750 | ) | 25.28 |
| ||
Forfeited |
| (193,500 | ) | 36.36 |
| (191,625 | ) | 35.60 |
| ||
Share options outstanding, end of year |
| 4,533,761 |
| $ | 32.35 |
| 4,119,386 |
| $ | 32.39 |
|
Share options exercisable, end of year |
| 3,326,197 |
| $ | 31.93 |
| 3,279,133 |
| $ | 30.56 |
|
(a) Weighted average.
As at December 31, 2017, the aggregate intrinsic value of the total options exercisable was $6.0 million (December 31, 2016 - $16.5 million), the total intrinsic value of options outstanding was $6.0 million (December 31, 2016 - $16.8 million) and the total intrinsic value of options exercised was $1.4 million (December 31, 2016 - $2.6 million).
The following table summarizes the employee share option plan as at December 31, 2017:
|
| 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 |
| 1.29 |
| 157,750 |
| $ | 15.22 |
| 1.29 |
|
$18.01 to $25.08 |
| 480,975 |
| 20.88 |
| 2.69 |
| 480,975 |
| 20.88 |
| 2.69 |
| ||
$25.09 to $50.89 |
| 3,895,036 |
| 34.45 |
| 4.04 |
| 2,687,472 |
| 34.89 |
| 3.75 |
| ||
|
| 4,533,761 |
| $ | 32.35 |
| 3.80 |
| 3,326,197 |
| $ | 31.93 |
| 3.48 |
|
The fair value of each option granted is estimated on the date of grant using the Black-Scholes-Merton option pricing model. The weighted average grant date fair value and assumptions are as follows:
Year ended December 31 |
| 2017 |
| 2016 |
|
Fair value per option ($) |
| 1.91 |
| 2.09 |
|
Risk-free interest rate (%) |
| 1.31 |
| 1.12 |
|
Expected life (years) |
| 6 |
| 6 |
|
Expected volatility (%) |
| 21.05 |
| 20.65 |
|
Annual dividend per share ($) |
| 2.12 |
| 1.98 |
|
Forfeiture rate (%) (a) |
| — |
| 16.00 |
|
(a) Effective January 1, 2017, AltaGas adopted ASU No. 2016-09 and elected to account for forfeitures when they occur instead of estimating the number of awards that are expected to vest. Refer to Note 2.
MTIP and DSUP
AltaGas has a MTIP for employees and executive officers, which includes RUs and PUs with vesting periods between 36 to 44 months from the grant date. In addition, AltaGas has a DSUP, which allows granting of DSUs to directors. DSUs granted under the DSUP vests immediately but settlement of the DSUs occur when the individual ceases to be a director.
PUs, RUs, and DSUs |
|
|
|
|
|
(number of units) |
| December 31, 2017 |
| December 31, 2016 |
|
Balance, beginning of year |
| 364,839 |
| 409,037 |
|
Granted |
| 386,126 |
| 91,288 |
|
Additional units added by performance factor |
| 24,301 |
| — |
|
Vested and paid out |
| (221,775 | ) | (136,359 | ) |
Forfeited |
| (27,279 | ) | (13,565 | ) |
Units in lieu of dividends |
| 38,337 |
| 14,438 |
|
Outstanding, end of year |
| 564,549 |
| 364,839 |
|
For the year ended December 31, 2017, the compensation expense recorded for the MTIP and DSUP was $9.1 million (2016 - $7.0 million). As at December 31, 2017, the unrecognized compensation expense relating to the remaining vesting period for the MTIP was $8.4 million (December 31, 2016 - $11.9 million) and is expected to be recognized over the vesting period.
22. NET INCOME PER COMMON SHARE
The following table summarizes the computation of net income per common share:
For the year ended December 31 |
| 2017 |
| 2016 |
| ||
Numerator: |
|
|
|
|
| ||
Net income applicable to controlling interests |
| $ | 91.6 |
| $ | 203.5 |
|
Less: Preferred share dividends |
| (61.3 | ) | (48.1 | ) | ||
Net income applicable to common shares |
| $ | 30.3 |
| $ | 155.4 |
|
Denominator: |
|
|
|
|
| ||
(millions) |
|
|
|
|
| ||
Weighted average number of common shares outstanding |
| 171.0 |
| 157.2 |
| ||
Dilutive equity instruments(a) |
| 0.3 |
| 0.4 |
| ||
Weighted average number of common shares outstanding - diluted |
| 171.3 |
| 157.6 |
| ||
Basic net income per common share |
| $ | 0.18 |
| $ | 0.99 |
|
Diluted net income per common share |
| $ | 0.18 |
| $ | 0.99 |
|
(a) Includes all options that have a strike price lower than the share price of AltaGas’ common shares as at December 31, 2017 and 2016.
For the year ended December 31, 2017, 2.8 million of share options (2016 – 2.2 million) were excluded from the diluted net income per share calculation as their effects were anti-dilutive.
23. OTHER INCOME
Year ended December 31 |
| 2017 |
| 2016 |
| ||
Gains (losses) from sale of assets |
| $ | (2.7 | ) | $ | 4.2 |
|
Interest income and other revenue |
| 10.3 |
| 3.9 |
| ||
Unrealized gains from held-for-trading assets |
| 3.6 |
| 0.5 |
| ||
|
| $ | 11.2 |
| $ | 8.6 |
|
24. OPERATING LEASES
Certain of AltaGas’ revenues are obtained through power purchase agreements or take-or-pay contracts whereby AltaGas is the lessor in these operating lease arrangements. Minimum lease payments received are amortized over the term of the lease. Contingent rentals are recorded when the condition that created the present obligation to make such payments occurs such as when actual electricity is generated and delivered. The carrying value of property, plant, and equipment associated with these leases was $3.0 billion as at December 31, 2017 (December 31, 2016 - $3.1 billion). For the year ended December 31, 2017, the total revenue earned from minimum lease payments was $290.8 million (2016 - $238.2 million) and from contingent rentals was $175.6 million (2016 - $116.3 million).
The following table sets forth the future fixed minimum revenue related to the operating leases for the years ended December 31:
2018 |
| 289.7 |
2019 |
| 287.4 |
2020 |
| 250.2 |
2021 |
| 208.8 |
2022 |
| 194.5 |
25. 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.
Defined Contribution Plan
AltaGas has a defined contribution (DC) pension plan for substantially all employees who are not members of defined benefit plans. The pension cost recorded for the DC plan was $8.4 million for the year ended December 31, 2017 (2016 - $8.1 million).
Defined Benefit Plans
AltaGas has several defined benefit pension plans in Canada and the United States for unionized and non-unionized employees. These benefit plans are funded.
Supplemental Executive Retirement Plan (SERP)
AltaGas has non-registered, defined benefit plans that provide defined benefit pension benefits to eligible executives based on average earnings, years of service and age at retirement. The SERP benefits will be paid from the general revenue of the Corporation as payments come due. Security will be provided for the SERP benefits through a letter of credit within a retirement compensation arrangement trust account.
Post-Retirement Benefits
AltaGas has several post-retirement benefit plans for unionized and non-unionized employees in Canada and the United States. Benefits provided to retired employees are limited to the payment of life insurance and health insurance premiums. These benefit plans are not funded, except for one plan. Post-retirement benefit plans in the United States provide certain medical and prescription drug benefits to eligible retired employees, their spouses and covered dependents. Benefits are based on a combination of the retiree’s age and years of service at retirement. These benefit plans are funded.
AltaGas’ most recent actuarial valuation of the Canadian defined benefit plans for funding purposes was completed in 2016. AltaGas is required to file an actuarial valuation of its Canadian defined benefit plans with the pension regulators at least every three years. The next actuarial valuation for funding purposes is required to be completed as of a date no later than December 31, 2019 and is expected to be filed with the pension regulators in 2020. Actuarial valuations are required annually for AltaGas’ U.S. defined benefit plans.
The following table summarizes the details of the defined benefit plans, including the SERP and post-retirement plans in Canada and the United States:
|
| Canada |
| United States |
| Total |
| ||||||||||||
|
|
|
| Post- |
|
|
| Post- |
|
|
| Post- |
| ||||||
|
| Defined |
| Retirement |
| Defined |
| Retirement |
| Defined |
| Retirement |
| ||||||
Year ended December 31, 2017 |
| Benefit |
| Benefits |
| Benefit |
| Benefits |
| Benefit |
| Benefits |
| ||||||
Accrued benefit obligation |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Balance, beginning of year |
| $ | 150.0 |
| $ | 16.4 |
| $ | 290.5 |
| $ | 72.7 |
| $ | 440.5 |
| $ | 89.1 |
|
Actuarial loss (gain) |
| 8.3 |
| (1.6 | ) | 23.2 |
| 14.4 |
| 31.5 |
| 12.8 |
| ||||||
Current service cost |
| 7.9 |
| 0.7 |
| 8.0 |
| 1.8 |
| 15.9 |
| 2.5 |
| ||||||
Member contributions |
| 0.2 |
| — |
| — |
| — |
| 0.2 |
| — |
| ||||||
Interest cost |
| 5.8 |
| 0.6 |
| 11.7 |
| 2.9 |
| 17.5 |
| 3.5 |
| ||||||
Benefits paid |
| (6.3 | ) | (0.3 | ) | (8.6 | ) | (3.2 | ) | (14.9 | ) | (3.5 | ) | ||||||
Expenses paid |
| (0.3 | ) | — |
| (0.8 | ) | (0.1 | ) | (1.1 | ) | (0.1 | ) | ||||||
Plan settlements |
| — |
| — |
| — |
| (0.5 | ) | — |
| (0.5 | ) | ||||||
Foreign exchange translation |
| — |
| — |
| (20.2 | ) | (5.3 | ) | (20.2 | ) | (5.3 | ) | ||||||
Balance, end of year |
| $ | 165.6 |
| $ | 15.8 |
| $ | 303.8 |
| $ | 82.7 |
| $ | 469.4 |
| $ | 98.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Plan assets |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Fair value, beginning of year |
| $ | 101.5 |
| $ | 6.8 |
| $ | 226.9 |
| $ | 67.2 |
| $ | 328.4 |
| $ | 74.0 |
|
Actual return on plan assets |
| 8.5 |
| 0.4 |
| 37.9 |
| 11.0 |
| 46.4 |
| 11.4 |
| ||||||
Employer contributions |
| 11.6 |
| 1.2 |
| 9.5 |
| 0.6 |
| 21.1 |
| 1.8 |
| ||||||
Member contributions |
| 0.2 |
| — |
| — |
| — |
| 0.2 |
| — |
| ||||||
Benefits paid |
| (6.3 | ) | (0.3 | ) | (8.6 | ) | (3.2 | ) | (14.9 | ) | (3.5 | ) | ||||||
Expenses paid |
| (0.3 | ) | — |
| (0.8 | ) | (0.1 | ) | (1.1 | ) | (0.1 | ) | ||||||
Foreign exchange translation |
| — |
| — |
| (16.2 | ) | (4.7 | ) | (16.2 | ) | (4.7 | ) | ||||||
Fair value, end of year |
| $ | 115.2 |
| $ | 8.1 |
| $ | 248.7 |
| $ | 70.8 |
| $ | 363.9 |
| $ | 78.9 |
|
Net amount recognized |
| $ | (50.4 | ) | $ | (7.7 | ) | $ | (55.1 | ) | $ | (11.9 | ) | $ | (105.5 | ) | $ | (19.6 | ) |
|
| Canada |
| United States |
| Total |
| ||||||||||||
|
|
|
| Post- |
|
|
| Post- |
|
|
| Post- |
| ||||||
|
| Defined |
| Retirement |
| Defined |
| Retirement |
| Defined |
| Retirement |
| ||||||
Year ended December 31, 2016 |
| Benefit |
| Benefits |
| Benefit |
| Benefits |
| Benefit |
| Benefits |
| ||||||
Accrued benefit obligation |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Balance, beginning of year |
| $ | 135.1 |
| $ | 14.7 |
| $ | 280.0 |
| $ | 88.0 |
| $ | 415.1 |
| $ | 102.7 |
|
Actuarial loss (gain) |
| 7.9 |
| 0.8 |
| 8.8 |
| (13.4 | ) | 16.7 |
| (12.6 | ) | ||||||
Current service cost |
| 7.0 |
| 0.6 |
| 7.1 |
| 1.9 |
| 14.1 |
| 2.5 |
| ||||||
Member contributions |
| 0.2 |
| — |
| — |
| — |
| 0.2 |
| — |
| ||||||
Interest cost |
| 5.6 |
| 0.6 |
| 11.8 |
| 3.9 |
| 17.4 |
| 4.5 |
| ||||||
Benefits paid |
| (5.7 | ) | (0.3 | ) | (8.2 | ) | (2.9 | ) | (13.9 | ) | (3.2 | ) | ||||||
Expenses paid |
| (0.3 | ) | — |
| — |
| — |
| (0.3 | ) | — |
| ||||||
Net transfer in (out) (including the effect of acquisitions/divestitures) |
| 0.2 |
| — |
| — |
| — |
| 0.2 |
| — |
| ||||||
Plan amendments |
| — |
| — |
| — |
| (2.0 | ) | — |
| (2.0 | ) | ||||||
Plan settlements |
| — |
| — |
| (0.9 | ) | — |
| (0.9 | ) | — |
| ||||||
Foreign exchange translation |
| — |
| — |
| (8.1 | ) | (2.8 | ) | (8.1 | ) | (2.8 | ) | ||||||
Balance, end of year |
| $ | 150.0 |
| $ | 16.4 |
| $ | 290.5 |
| $ | 72.7 |
| $ | 440.5 |
| $ | 89.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Plan assets |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Fair value, beginning of year |
| $ | 93.5 |
| $ | 5.7 |
| $ | 214.8 |
| $ | 66.2 |
| $ | 308.3 |
| $ | 71.9 |
|
Actual return on plan assets |
| 6.1 |
| 0.2 |
| 15.9 |
| 4.9 |
| 22.0 |
| 5.1 |
| ||||||
Employer contributions |
| 7.5 |
| 1.2 |
| 11.5 |
| 0.9 |
| 19.0 |
| 2.1 |
| ||||||
Member contributions |
| 0.2 |
| — |
| — |
| — |
| 0.2 |
| — |
| ||||||
Benefits paid |
| (5.7 | ) | (0.3 | ) | (8.2 | ) | (2.9 | ) | (13.9 | ) | (3.2 | ) | ||||||
Expenses paid |
| (0.3 | ) | — |
| — |
| — |
| (0.3 | ) | — |
| ||||||
Acquisitions/ divestitures |
| 0.2 |
| — |
| — |
| — |
| 0.2 |
| — |
| ||||||
Plan settlements |
| — |
| — |
| (0.9 | ) | — |
| (0.9 | ) | — |
| ||||||
Foreign exchange translation |
| — |
| — |
| (6.2 | ) | (1.9 | ) | (6.2 | ) | (1.9 | ) | ||||||
Fair value, end of year |
| $ | 101.5 |
| $ | 6.8 |
| $ | 226.9 |
| $ | 67.2 |
| $ | 328.4 |
| $ | 74.0 |
|
Net amount recognized |
| $ | (48.5 | ) | $ | (9.6 | ) | $ | (63.6 | ) | $ | (5.5 | ) | $ | (112.1 | ) | $ | (15.1 | ) |
The following amounts were included in the Consolidated Balance Sheets:
|
| December 31, 2017 |
| December 31, 2016 |
| ||||||||||||||
|
|
|
| Post- |
|
|
|
|
| Post- |
|
|
| ||||||
|
| Defined |
| Retirement |
|
|
| Defined |
| Retirement |
|
|
| ||||||
|
| Benefit |
| Benefits |
| Total |
| Benefit |
| Benefits |
| Total |
| ||||||
Other assets (note 10) |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 2.8 |
| $ | 2.8 |
|
Accounts payable and accrued liabilities |
| (0.6 | ) | — |
| (0.6 | ) | (0.5 | ) | — |
| (0.5 | ) | ||||||
Future employee obligations |
| (104.9 | ) | (19.6 | ) | (124.5 | ) | (111.6 | ) | (17.9 | ) | (129.5 | ) | ||||||
|
| $ | (105.5 | ) | $ | (19.6 | ) | $ | (125.1 | ) | $ | (112.1 | ) | $ | (15.1 | ) | $ | (127.2 | ) |
The funded status based on the accumulated benefit obligation for all defined benefit plans were:
|
| December 31, 2017 |
| December 31, 2016 |
| ||||||||
|
| Canada |
| United States |
| Canada |
| United States |
| ||||
Accumulated benefit obligation (a) |
| $ | (143.9 | ) | $ | (274.2 | ) | $ | (128.9 | ) | $ | (262.1 | ) |
Fair value of plan assets |
| 115.2 |
| 248.7 |
| 101.5 |
| 226.9 |
| ||||
Funded status |
| $ | (28.7 | ) | $ | (25.5 | ) | $ | (27.4 | ) | $ | (35.2 | ) |
(a) Accumulated benefit obligation differs from accrued benefit obligation in that it does not include an assumption with respect to future compensation levels.
The following amounts were not recognized in the net periodic benefit cost and recorded in the other comprehensive losses:
|
| Canada |
| United States |
| Total |
| ||||||||||||
|
|
|
| Post- |
|
|
| Post- |
|
|
| Post- |
| ||||||
|
| Defined |
| Retirement |
| Defined |
| Retirement |
| Defined |
| Retirement |
| ||||||
Year ended December 31, 2017 |
| Benefit |
| Benefits |
| Benefit |
| Benefits |
| Benefit |
| Benefits |
| ||||||
Past service cost |
| $ | (0.4 | ) | $ | — |
| $ | — |
| $ | — |
| $ | (0.4 | ) | $ | — |
|
Net actuarial loss |
| (13.9 | ) | (1.3 | ) | — |
| — |
| (13.9 | ) | (1.3 | ) | ||||||
Recognized in AOCI pre-tax |
| $ | (14.3 | ) | $ | (1.3 | ) | $ | — |
| $ | — |
| $ | (14.3 | ) | $ | (1.3 | ) |
Increase (decrease) by the amount included in deferred tax liabilities |
| 4.0 |
| 0.3 |
| (0.1 | ) | — |
| 3.9 |
| 0.3 |
| ||||||
Net amount in AOCI after-tax |
| $ | (10.3 | ) | $ | (1.0 | ) | $ | (0.1 | ) | $ | — |
| $ | (10.4 | ) | $ | (1.0 | ) |
|
| Canada |
| United States |
| Total |
| ||||||||||||
|
|
|
| Post- |
|
|
| Post- |
|
|
| Post- |
| ||||||
|
| Defined |
| Retirement |
| Defined |
| Retirement |
| Defined |
| Retirement |
| ||||||
Year ended December 31, 2016 |
| Benefit |
| Benefits |
| Benefit |
| Benefits |
| Benefit |
| Benefits |
| ||||||
Past service cost |
| $ | (0.5 | ) | $ | — |
| $ | — |
| $ | (0.3 | ) | $ | (0.5 | ) | $ | (0.3 | ) |
Net actuarial loss |
| (13.7 | ) | (1.0 | ) | — |
| — |
| (13.7 | ) | (1.0 | ) | ||||||
Recognized in AOCI pre-tax |
| $ | (14.2 | ) | $ | (1.0 | ) | $ | — |
| $ | (0.3 | ) | $ | (14.2 | ) | $ | (1.3 | ) |
Increase (decrease) by the amount included in deferred tax liabilities |
| 3.8 |
| 0.3 |
| — |
| 0.1 |
| 3.8 |
| 0.4 |
| ||||||
Net amount in AOCI after-tax |
| $ | (10.4 | ) | $ | (0.7 | ) | $ | — |
| $ | (0.2 | ) | $ | (10.4 | ) | $ | (0.9 | ) |
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.
|
|
|
| Post- |
| ||
|
| Defined |
| Retirement |
| ||
Amounts to be amortized in the next fiscal year from AOCI |
| Benefit |
| Benefits |
| ||
Past service costs |
| $ | 0.1 |
| $ | — |
|
Actuarial losses |
| 0.9 |
| — |
| ||
Total |
| $ | 1.0 |
| $ | — |
|
The net pension expense by plan for the period was as follows:
|
| Year ended December 31, 2017 |
| ||||||||||||||||
|
| Canada |
| United States |
| Total |
| ||||||||||||
|
|
|
| Post- |
|
|
| Post- |
|
|
| Post- |
| ||||||
|
| Defined |
| retirement |
| Defined |
| retirement |
| Defined |
| retirement |
| ||||||
|
| Benefit |
| Benefits |
| Benefit |
| Benefits |
| Benefit |
| Benefits |
| ||||||
Current service cost |
| $ | 7.9 |
| $ | 0.7 |
| $ | 8.0 |
| $ | 1.8 |
| $ | 15.9 |
| $ | 2.5 |
|
Interest cost |
| 5.8 |
| 0.6 |
| 11.7 |
| 2.9 |
| 17.5 |
| 3.5 |
| ||||||
Expected return on plan assets |
| (5.9 | ) | (0.2 | ) | (16.9 | ) | (4.7 | ) | (22.8 | ) | (4.9 | ) | ||||||
Settlement of plan |
| — |
| — |
| — |
| 0.2 |
| — |
| 0.2 |
| ||||||
Amortization of past service cost |
| 0.2 |
| — |
| — |
| — |
| 0.2 |
| — |
| ||||||
Amortization of net actuarial loss |
| 0.7 |
| — |
| — |
| — |
| 0.7 |
| — |
| ||||||
Amortization of regulatory asset/liability |
| 1.3 |
| 0.1 |
| 6.5 |
| (0.3 | ) | 7.8 |
| (0.2 | ) | ||||||
Net benefit cost (income) recognized |
| $ | 10.0 |
| $ | 1.2 |
| $ | 9.3 |
| $ | (0.1 | ) | $ | 19.3 |
| $ | 1.1 |
|
|
| Year ended December 31, 2016 |
| ||||||||||||||||
|
| Canada |
| United States |
| Total |
| ||||||||||||
|
|
|
| Post- |
|
|
| Post- |
|
|
| Post- |
| ||||||
|
| Defined |
| retirement |
| Defined |
| retirement |
| Defined |
| retirement |
| ||||||
|
| Benefit |
| Benefits |
| Benefit |
| Benefits |
| Benefit |
| Benefits |
| ||||||
Current service cost |
| $ | 7.0 |
| $ | 0.6 |
| $ | 7.1 |
| $ | 1.9 |
| $ | 14.1 |
| $ | 2.5 |
|
Interest cost |
| 5.6 |
| 0.6 |
| 11.8 |
| 3.9 |
| 17.4 |
| 4.5 |
| ||||||
Expected return on plan assets |
| (5.3 | ) | (0.2 | ) | (15.1 | ) | (4.5 | ) | (20.4 | ) | (4.7 | ) | ||||||
Settlement (gain) loss |
| — |
| — |
| 0.1 |
| — |
| 0.1 |
| — |
| ||||||
Amortization of past service cost |
| 0.2 |
| — |
| — |
| — |
| 0.2 |
| — |
| ||||||
Amortization of net actuarial loss |
| 0.8 |
| 0.1 |
| — |
| — |
| 0.8 |
| 0.1 |
| ||||||
Amortization of regulatory asset |
| 1.2 |
| — |
| 6.3 |
| 0.8 |
| 7.5 |
| 0.8 |
| ||||||
Net benefit cost recognized |
| $ | 9.5 |
| $ | 1.1 |
| $ | 10.2 |
| $ | 2.1 |
| $ | 19.7 |
| 3.2 |
| |
The objective of the Corporation’s investment policy is to maximize long-term total return while protecting the capital value of the fund from major market fluctuations through diversification and selection of investments.
The objective for fund returns, over three to five-year periods, is the sum of two components - a passive component, which is the benchmark index market returns for the asset mix in effect, plus the added value expected from active management. It is the Corporation’s belief that the potential additional returns justify the additional risk associated with active management. The risk inherent in the investment strategy over a market cycle (a three-to five-year period) is two-fold. There is a risk that the market returns, as measured by the benchmark returns, will not be in line with expectations. The other risk is that the expected added value of active management over passive management will not be realized over the time period prescribed in each fund manager’s mandate. There is also the risk of annual volatility in returns, which means that in any one year the actual return may be very different from the expected return.
Cash and money market investments may be held from time to time as short-term investment decisions at the discretion of the fund manager(s) within the constraints prescribed by their mandate(s).
The Corporation has a target asset mix for the Canadian plans of 45 percent to 55 percent fixed income assets. The target asset mix for the U.S. plans is 33 percent fixed income assets. These objectives have taken into account the nature of the liabilities and the risk-reward tolerance of the Corporation.
The collective investment mixes for the plans are as follows as at December 31, 2017:
Canada |
| Fair value |
| Level 1 |
| Level 2 |
| Percentage of |
| |||
Cash and short-term equivalents |
| $ | 6.2 |
| $ | 6.2 |
| $ | — |
| 5.0 |
|
Canadian equities |
| 40.8 |
| 40.8 |
| — |
| 33.1 |
| |||
Foreign equities |
| 22.7 |
| 22.7 |
| — |
| 18.4 |
| |||
Fixed income |
| 47.1 |
| 47.0 |
| 0.1 |
| 38.2 |
| |||
Real estate |
| 6.5 |
| — |
| 6.5 |
| 5.3 |
| |||
|
| $ | 123.3 |
| $ | 116.7 |
| $ | 6.6 |
| 100.0 |
|
United States |
| Fair value |
| Level 1 |
| Level 2 |
| Percentage of |
| |||
Cash and short-term equivalents |
| $ | 0.8 |
| $ | 0.8 |
| $ | — |
| 0.3 |
|
Foreign equities |
| 212.0 |
| 212.0 |
| — |
| 66.3 |
| |||
Fixed income |
| 106.7 |
| 106.7 |
| — |
| 33.4 |
| |||
|
| $ | 319.5 |
| $ | 319.5 |
| $ | — |
| 100.0 |
|
Total |
| Fair value |
| Level 1 |
| Level 2 |
| Percentage of |
| |||
Cash and short-term equivalents |
| $ | 7.0 |
| $ | 7.0 |
| $ | — |
| 1.6 |
|
Canadian equities |
| 40.8 |
| 40.8 |
| — |
| 9.2 |
| |||
Foreign equities |
| 234.7 |
| 234.7 |
| — |
| 53.0 |
| |||
Fixed income |
| 153.8 |
| 153.7 |
| 0.1 |
| 34.7 |
| |||
Real estate |
| 6.5 |
| — |
| 6.5 |
| 1.5 |
| |||
|
| $ | 442.8 |
| $ | 436.2 |
| $ | 6.6 |
| 100.0 |
|
|
|
|
| Post- |
|
|
| Post- |
|
|
| Defined |
| Retirement |
| Defined |
| Retirement |
|
Significant actuarial assumptions used in measuring net benefit plan costs |
| Benefit |
| Benefits |
| Benefit |
| Benefits |
|
For the year ended December 31 |
| 2017 |
| 2016 |
| ||||
Discount rate (%) |
| 2.65 - 4.20 |
| 4.00 - 4.20 |
| 2.70 - 4.50 |
| 4.20 - 4.60 |
|
Expected long-term rate of return on plan assets (%) (a) |
| 6.18 - 7.30 |
| 3.10 - 7.30 |
| 6.00 - 7.30 |
| 3.10 - 7.30 |
|
Rate of compensation increase (%) |
| 2.75 - 4.00 |
| 3.25 |
| 2.75 - 4.00 |
| 3.25 |
|
Average remaining service life of active employees (years) |
| 12.7 |
| 13.5 |
| 12.5 |
| 13.6 |
|
(a) Only applicable for funded plans
|
|
|
| Post- |
|
|
| Post- |
|
|
| Defined |
| Retirement |
| Defined |
| Retirement |
|
Significant actuarial assumptions used in measuring benefit obligations |
| Benefit |
| Benefits |
| Benefit |
| Benefits |
|
As at December 31 |
| 2017 |
| 2016 |
| ||||
Discount rate (%) |
| 2.80 - 3.70 |
| 3.60 - 3.70 |
| 2.65 - 4.20 |
| 4.00 - 4.20 |
|
Rate of compensation increase (%) |
| 2.75 - 4.00 |
| 3.25 |
| 2.75 - 4.00 |
| 3.25 |
|
The expected rate of return on assets is based on the current level of expected returns on risk free investments, the historical level of risk premium associated with other asset classes in which the portfolio is invested, and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based on the target asset allocation to develop the expected rate of return on assets assumption for the portfolio.
The discount rate is based on high-quality long-term corporate bonds, with maturities matching the estimated timing and amount of expected benefit payments.
The estimates for health care benefits take into consideration increased health care benefits due to aging and cost increases in the future. The assumed health care cost trend rates used to measure the expected cost of benefits for the next year were between 6.5 and 6.7 percent. The health care cost trend rates were assumed to decline to between 4.5 and 5 percent by 2029.
The assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one percentage point change in the assumed health care trend rates would have the following effects for 2017:
|
| Increase |
| Decrease |
| ||
Service and interest costs |
| $ | 1.5 |
| $ | (1.1 | ) |
Accrued benefit obligation |
| $ | 19.3 |
| $ | (15.0 | ) |
The following table shows the expected cash flows for defined benefit pension and other-post retirement plans:
|
|
|
| Post- |
| ||
|
| Defined |
| Retirement |
| ||
|
| Benefit |
| Benefits |
| ||
Expected employer contributions: |
|
|
|
|
| ||
2018 |
| $ | 15.2 |
| $ | 3.0 |
|
Expected benefit payments: |
|
|
|
|
| ||
2018 |
| $ | 16.4 |
| $ | 3.2 |
|
2019 |
| 17.6 |
| 3.3 |
| ||
2020 |
| 19.1 |
| 3.5 |
| ||
2021 |
| 20.2 |
| 3.7 |
| ||
2022 |
| 21.6 |
| 3.9 |
| ||
2023 - 2027 |
| $ | 124.4 |
| $ | 21.7 |
|
26. COMMITMENTS, CONTINGENCIES AND GUARANTEES
Commitments
AltaGas has long-term natural gas purchase and transportation arrangements, service agreements, storage contract 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.
Future payments of these commitments at December 31, 2017 are estimated as follows:
|
| 2018 |
| 2019 |
| 2020 |
| 2021 |
| 2022 |
| 2023 and |
| Total |
| |||||||
Gas purchase(a) |
| $ | 362.4 |
| $ | 349.9 |
| $ | 342.2 |
| $ | 317.5 |
| $ | 285.3 |
| $ | 224.6 |
| $ | 1,881.9 |
|
Service agreement(b)(c)(d) |
| 11.1 |
| 21.2 |
| 21.2 |
| 14.9 |
| 12.8 |
| 183.0 |
| 264.2 |
| |||||||
Storage services(e) |
| 3.5 |
| 3.5 |
| 3.5 |
| 3.6 |
| 3.6 |
| 25.8 |
| 43.5 |
| |||||||
Capital projects(f) |
| 105.0 |
| — |
| — |
| — |
| — |
| — |
| 105.0 |
| |||||||
Operating leases(g) |
| 9.0 |
| 18.3 |
| 6.1 |
| 5.5 |
| 4.6 |
| 12.1 |
| 55.6 |
| |||||||
|
| $ | 491.0 |
| $ | 392.9 |
| $ | 373.0 |
| $ | 341.5 |
| $ | 306.3 |
| $ | 445.5 |
| $ | 2,350.2 |
|
(a) 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.
(b) 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 the Blythe facility over 116,000 equivalent operating hour per CT, or 20 years, whichever comes first. The LTSA has fixed fees that will be incurred in the five years following December 31, 2014 and variable fees on a per equivalent operating hour basis. As at December 31, 2017, the total commitment was $196.5 million payable over the next 17 years, of which $55.1 million is expected to be paid over the next five years.
(c) 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 $7.6 million over the next four years.
(d) In 2017, AltaGas entered into a 12-year service agreement for tug services to support the marine operations of RIPET.
(e) In 2009, AltaGas entered into a 20-year storage contract at the Dawn Hub in southwest Ontario. AltaGas is obligated to pay approximately $3.5 million per annum over the term of the contract for storage services.
(f) Commitments for capital projects. Estimated amounts are subject to variability depending on the actual construction costs.
(g) Operating leases include lease arrangements for office spaces, vehicles, rail cars, office and other equipment.
Guarantees
On 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 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.
27. RELATED PARTY TRANSACTIONS
In the normal course of business, AltaGas transacts with its subsidiaries, affiliates and joint ventures. Amounts due to or from related parties on the Consolidated Balance Sheets were measured at the exchange amount and were as follows:
As at |
| December 31, |
| December 31, |
| ||
Due from related parties |
|
|
|
|
| ||
Accounts receivable (a) |
| $ | 0.8 |
| $ | 0.7 |
|
Long-term investments and other assets (b)(c) |
| 75.0 |
| 63.3 |
| ||
|
| $ | 75.8 |
| $ | 64.0 |
|
Due to related parties |
|
|
|
|
| ||
Accounts payable (d) |
| 3.2 |
| 3.2 |
| ||
|
| $ | 3.2 |
| $ | 3.2 |
|
(a) Receivable from joint ventures.
(b) AltaGas and one of its executives agreed to a loan in the principal amount of $0.8 million to be paid in full with accrued interest at the rate prescribed by the Income Tax Act (Canada) on the earlier of the date of employment termination and February 8, 2021. The provisions of the loan were amended in 2015 to include provision for forgiveness of the loan. In 2017, the loan was forgiven.
(c) AltaGas has provided a $100.0 million interest bearing secured loan facility to Petrogas of which $50.0 million is committed. The facility is available for Petrogas to draw upon from time to time for general corporate purposes. The facility is subject to annual renewal and has a maturity date of June 27, 2021. As at December 31, 2017, Petrogas had drawn $75.0 million (December 31, 2016 - $62.5 million) under the facility.
(d) Payables to joint ventures.
The following transactions with related parties have been recorded on the Consolidated Statements of Income for the year ended December 31, 2017 and 2016:
Year ended December 31 |
| 2017 |
| 2016 |
| ||
Revenue (a)(b) |
| $ | 15.0 |
| $ | 16.1 |
|
Cost of sales (c) |
| $ | (6.5 | ) | $ | (6.5 | ) |
Operating and administrative expenses (d) |
| $ | — |
| $ | 0.7 |
|
Other income (e) |
| $ | 4.4 |
| $ | 1.3 |
|
(a) In the ordinary course of business, AltaGas sold natural gas and natural gas liquids to a joint venture and an affiliate.
(b) In 2016, PNG recognized revenue of $6.8 million related to the recovery of development costs from Triton LNG Limited Partnership for the PNG Pipeline Looping Project.
(c) In the ordinary course of business, AltaGas obtained natural gas storage services from a joint venture as well as incurred costs related to the sale of natural gas liquids to an affiliate.
(d) Administrative costs recovered from joint ventures. In 2017, amount was offset by the expense associated with the forgiveness of the loan to an executive.
(e) Interest income from an affiliate.
28. SUPPLEMENTAL CASH FLOW INFORMATION
The following table details the changes in operating assets and liabilities from operating activities:
For the year ended December 31 |
| 2017 |
| 2016 |
| ||
Source (use) of cash: |
|
|
|
|
| ||
Accounts receivable |
| $ | (55.5 | ) | $ | (6.1 | ) |
Inventory |
| 4.7 |
| (14.4 | ) | ||
Other current assets |
| 7.0 |
| (20.8 | ) | ||
Regulatory assets (current) |
| (0.2 | ) | 3.3 |
| ||
Accounts payable and accrued liabilities |
| 85.5 |
| (4.6 | ) | ||
Customer deposits |
| (2.8 | ) | (4.6 | ) | ||
Regulatory liabilities (current) |
| (4.8 | ) | (4.1 | ) | ||
Other current liabilities |
| 13.0 |
| 4.3 |
| ||
Other operating assets and liabilities |
| (41.0 | ) | (30.5 | ) | ||
Changes in operating assets and liabilities |
| $ | 5.9 |
| $ | (77.5 | ) |
The following cash payments have been included in the determination of earnings:
For the year ended December 31 |
| 2017 |
| 2016 |
| ||
Interest paid (net of capitalized interest) |
| $ | 151.1 |
| $ | 141.5 |
|
Income taxes paid |
| $ | 36.3 |
| $ | 35.9 |
|
29. 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. |
Geographic Information
Year ended December 31 |
| 2017 |
| 2016 |
| ||
Revenue(a) |
|
|
|
|
| ||
Canada |
| $ | 1,508.8 |
| $ | 1,192.3 |
|
United States |
| 1,109.9 |
| 1,008.8 |
| ||
Total |
| $ | 2,618.7 |
| $ | 2,201.1 |
|
(a) Operating revenue from external customers, excluding unrealized gains (losses) on risk management contracts.
As at December 31 |
| 2017 |
| 2016 |
| ||
Property, plant and equipment |
|
|
|
|
| ||
Canada |
| $ | 4,320.5 |
| $ | 4,080.3 |
|
United States |
| 2,369.3 |
| 2,654.6 |
| ||
Total |
| $ | 6,689.8 |
| $ | 6,734.9 |
|
The following tables show the composition by segment:
|
| Year ended December 31, 2017 |
| ||||||||||||||||
|
| Gas |
| Power |
| Utilities |
| Corporate |
| Intersegment |
| Total |
| ||||||
Revenue |
| $ | 1,008.0 |
| $ | 631.7 |
| $ | 1,127.6 |
| $ | 3.2 |
| $ | (151.8 | ) | $ | 2,618.7 |
|
Unrealized losses on risk management contracts |
| — |
| — |
| (0.9 | ) | (61.6 | ) | — |
| (62.5 | ) | ||||||
Cost of sales |
| (647.0 | ) | (242.8 | ) | (610.1 | ) | — |
| 142.8 |
| (1,357.1 | ) | ||||||
Operating and administrative |
| (165.0 | ) | (93.1 | ) | (226.1 | ) | (99.1 | ) | 9.5 |
| (573.8 | ) | ||||||
Accretion expenses |
| (3.9 | ) | (6.9 | ) | (0.1 | ) | — |
| — |
| (10.9 | ) | ||||||
Depreciation and amortization |
| (68.6 | ) | (118.0 | ) | (81.8 | ) | (14.0 | ) | — |
| (282.4 | ) | ||||||
Provisions on assets (note 9) |
| (6.6 | ) | (133.0 | ) | — |
| — |
| — |
| (139.6 | ) | ||||||
Income from equity investments |
| 22.0 |
| 6.8 |
| 2.6 |
| — |
| — |
| 31.4 |
| ||||||
Other income (loss) |
| (0.9 | ) | 0.8 |
| 3.9 |
| 7.9 |
| (0.5 | ) | 11.2 |
| ||||||
Foreign exchange gains |
| 0.2 |
| — |
| — |
| 1.5 |
| — |
| 1.7 |
| ||||||
Interest expense |
| — |
| — |
| — |
| (170.3 | ) | — |
| (170.3 | ) | ||||||
Income (loss) before income taxes |
| $ | 138.2 |
| $ | 45.5 |
| $ | 215.1 |
| $ | (332.4 | ) | $ | — |
| $ | 66.4 |
|
Net additions (reductions) to: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Property, plant and equipment(b) |
| $ | 245.3 |
| $ | 16.5 |
| $ | 124.3 |
| $ | 1.5 |
| $ | — |
| $ | 387.6 |
|
Intangible assets |
| $ | 2.8 |
| $ | 13.2 |
| $ | 2.1 |
| $ | 2.2 |
| $ | — |
| $ | 20.3 |
|
(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.
|
| Year ended December 31, 2016 |
| ||||||||||||||||
|
| Gas |
| Power |
| Utilities |
| Corporate |
| Intersegment |
| Total |
| ||||||
Revenue |
| $ | 804.1 |
| $ | 574.7 |
| $ | 1,065.8 |
| $ | 11.7 |
| $ | (255.2 | ) | $ | 2,201.1 |
|
Unrealized gains (losses) on risk management contracts |
| — |
| — |
| 0.5 |
| (11.9 | ) | — |
| (11.4 | ) | ||||||
Cost of sales |
| (496.1 | ) | (200.5 | ) | (557.1 | ) | — |
| 236.8 |
| (1,016.9 | ) | ||||||
Operating and administrative |
| (154.3 | ) | (100.1 | ) | (229.7 | ) | (44.1 | ) | 18.9 |
| (509.3 | ) | ||||||
Accretion expenses |
| (3.9 | ) | (7.0 | ) | (0.1 | ) | — |
| — |
| (11.0 | ) | ||||||
Depreciation and amortization |
| (65.8 | ) | (108.7 | ) | (82.3 | ) | (14.7 | ) | — |
| (271.5 | ) | ||||||
Income (loss) from equity investments |
| 7.6 |
| (6.8 | ) | 2.6 |
| — |
| — |
| 3.4 |
| ||||||
Other income (loss) |
| 4.8 |
| — |
| 1.7 |
| 2.6 |
| (0.5 | ) | 8.6 |
| ||||||
Foreign exchange gains |
| — |
| — |
| — |
| 4.0 |
| — |
| 4.0 |
| ||||||
Interest expense |
| — |
| — |
| — |
| (150.8 | ) | — |
| (150.8 | ) | ||||||
Income (loss) before income taxes |
| $ | 96.4 |
| $ | 151.6 |
| $ | 201.4 |
| $ | (203.2 | ) | $ | — |
| $ | 246.2 |
|
Net additions (reductions) to: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Property, plant and equipment(b) |
| $ | 193.0 |
| $ | 95.0 |
| $ | 112.7 |
| $ | 4.3 |
| $ | — |
| $ | 405.0 |
|
Intangible assets |
| $ | 2.6 |
| $ | 15.1 |
| $ | 2.4 |
| $ | 5.9 |
| $ | — |
| $ | 26.0 |
|
(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 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 |
|
As at December 31, 2016 |
|
|
|
|
|
|
|
|
|
|
| |||||
Goodwill |
| $ | 152.9 |
| $ | — |
| $ | 703.1 |
| $ | — |
| $ | 856.0 |
|
Segmented assets |
| $ | 2,826.3 |
| $ | 3,501.3 |
| $ | 3,586.4 |
| $ | 286.6 |
| $ | 10,200.6 |
|
30. SUBSEQUENT EVENTS
Subsequent events have been reviewed through February 28, 2018, the date these Consolidated Financial Statements were issued. There were no subsequent events requiring disclosure or adjustment to the Consolidated Financial Statements.
Supplementary Quarterly Operating Information
|
| Q4-17 |
| Q3-17 |
| Q2-17 |
| Q1-17 |
| Q4-16 |
|
OPERATING HIGHLIGHTS |
|
|
|
|
|
|
|
|
|
|
|
GAS |
|
|
|
|
|
|
|
|
|
|
|
Total inlet gas processed (Mmcf/d)(1) |
| 1,424 |
| 1,322 |
| 1,300 |
| 1,404 |
| 1,337 |
|
Extraction volumes (Bbls/d)(1)(2) |
| 68,306 |
| 64,026 |
| 58,885 |
| 71,958 |
| 69,687 |
|
Frac spread - realized ($/Bbl)(1)(3) |
| 18.02 |
| 14.96 |
| 9.06 |
| 10.56 |
| 6.11 |
|
Frac spread - average spot price ($/Bbl)(1)(4) |
| 30.66 |
| 21.28 |
| 10.98 |
| 17.26 |
| 8.40 |
|
POWER |
|
|
|
|
|
|
|
|
|
|
|
Renewable power sold (GWh) |
| 301 |
| 681 |
| 499 |
| 148 |
| 196 |
|
Conventional power sold (GWh) |
| 1,059 |
| 992 |
| 409 |
| 385 |
| 374 |
|
Renewable capacity factor (%) |
| 27.5 |
| 70.3 |
| 50.7 |
| 9.5 |
| 18.8 |
|
Contracted conventional availability factor (%)(5) |
| 96.3 |
| 99.6 |
| 99.9 |
| 96.0 |
| 99.8 |
|
UTILITIES |
|
|
|
|
|
|
|
|
|
|
|
Canadian utilities |
|
|
|
|
|
|
|
|
|
|
|
Natural gas deliveries - end-use (PJ)(6) |
| 11.2 |
| 3.7 |
| 4.8 |
| 13.5 |
| 10.8 |
|
Natural gas deliveries - transportation (PJ)(6) |
| 1.6 |
| 1.3 |
| 1.5 |
| 1.9 |
| 1.5 |
|
U.S. utilities |
|
|
|
|
|
|
|
|
|
|
|
Natural gas deliveries end use (Bcf) (6) |
| 24.3 |
| 5.9 |
| 10.3 |
| 30.2 |
| 22.8 |
|
Natural gas deliveries transportation (Bcf)(6) |
| 14.2 |
| 10.9 |
| 11.5 |
| 15.4 |
| 14.2 |
|
Service sites(7) |
| 581,518 |
| 575,602 |
| 575,084 |
| 576,829 |
| 574,875 |
|
Degree day variance from normal - AUI (%)(8) |
| 4.0 |
| (16.9 | ) | (7.4 | ) | (2.2 | ) | (0.6 | ) |
Degree day variance from normal - Heritage Gas (%)(8) |
| (4.6 | ) | (20.4 | ) | (4.3 | ) | (1.9 | ) | (1.0 | ) |
Degree day variance from normal - SEMCO Gas (%)(9) |
| 4.8 |
| 5.7 |
| (8.4 | ) | (11.8 | ) | (6.1 | ) |
Degree day variance from normal - ENSTAR (%)(9) |
| (8.3 | ) | (16.6 | ) | (5.4 | ) | 9.6 |
| (1.4 | ) |
(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.
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 business 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