MANAGEMENT’S DISCUSSION AND ANALYSIS
This Management’s Discussion and Analysis (MD&A) dated October 29, 2018 is provided to enable readers to assess the results of operations, liquidity and capital resources of AltaGas Ltd. (AltaGas or the Corporation) as at and for the three and nine months ended September 30, 2018. This MD&A should be read in conjunction with the accompanying unaudited condensed interim Consolidated Financial Statements and notes thereto of AltaGas as at and for the three and nine months ended September 30, 2018 and the audited Consolidated Financial Statements and MD&A as at and for the year ended December 31, 2017.
The Consolidated Financial Statements and comparative information have been prepared in accordance with United States (U.S.) generally accepted accounting principles (U.S. GAAP) and in Canadian dollars, unless otherwise indicated. Throughout this MD&A, references to GAAP refer to U.S. GAAP and dollars refer to Canadian dollars, unless otherwise indicated.
Abbreviations, acronyms and capitalized terms used in this MD&A without express definition shall have the same meanings given to those terms in the MD&A as at and for the year ended December 31, 2017 or the Annual Information Form.
This MD&A contains forward-looking information (forward-looking statements). Words such as “may”, “can”, “would”, “could”, “should”, “will”, “intend”, “plan”, “anticipate”, “believe”, “aim”, “seek”, “propose”, “contemplate”, “estimate”, “focus”, “strive”, “forecast”, “expect”, “project”, “target”, “potential”, “objective”, “continue”, “outlook”, “vision”, “opportunity” and similar expressions suggesting future events or future performance, as they relate to the Corporation or any affiliate of the Corporation, are intended to identify forward-looking statements. In particular, this MD&A contains forward-looking statements with respect to, among other things, business objectives, expected growth, results of operations, performance, business projects and opportunities and financial results.
Specifically, such forward-looking statements included in this document include, but are not limited to, statements with respect to the following: the implementation and success of AltaGas’ strategy for the Corporation as a whole and each of its business segments; the aim to maintain a long-term balanced mix of energy infrastructure assets across AltaGas’ business segments; the expected benefits of AltaGas’ export-related infrastructure assets; AltaGas’ ability to take advantage of the demand for clean energy through its clean energy assets; the expected benefits of the WGL Acquisition to each segment, including increases in EBITDA; the expected timing and components of repayment of bridge facility, including assets sales and securities offerings; expected AltaGas ownership in AltaGas Canada Inc.; expected proceeds of the Company’s asset sales to date; expected amount outstanding under the bridge facility after accounting for the asset sales to date; expected receipt of approvals and timing of closing of the non-core midstream and power assets in Canada and the gas-fired power assets in California; expected impacts of the Black Swan transaction, including the expected capital investment associated with this transaction; expected expansion of the Townsend complex; expected benefits of the Kelt transaction; expected EBITDA and funds from operations increase compared to the prior year, and the expected impact of contributing factors; expected exposure to frac spreads prior to hedging activities; expected capital expenditures company-wide, by segment and by project; expected maintenance capital; expected funding of the committed capital program; expected cost, capacity, tolling arrangements, timing, supply and benefits of RIPET; expected expansion of the Central Penn pipeline and expected in service timing; expected timing, cost, and investment of the Mountain Valley pipeline; expected timing and capacity of the Alton Natural Gas Storage Project; expected capital spending and new customer growth in the Utilities segment, estimated cost of the accelerated pipe recovery plans; expected timing of the Marquette Connector Pipeline; potential value of WGL’s solar projects; expected timing of decisions in the Maryland, Virginia and CINGSA rate case and the CINGSA redundancy project hearing; and the expected achievement of objectives to maintain AltaGas’ investment grade credit rating, ensure adequate liquidity, optimize profitability and grow energy infrastructure. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results, events, and achievements to differ materially from those expressed or implied by such statements. Such statements reflect AltaGas’ current expectations, estimates, and projections based on certain material factors and assumptions at the time the statement was made. Material assumptions include: expected commodity supply, demand and pricing; volumes and rates; exchange rates; inflation; interest rates; credit rating; regulatory approvals and policies; future operating and capital costs; project completion dates; capacity expectations; implications of recent U.S. tax legislation changes; the outcomes of significant commercial contract negotiations; and financing of the WGL Acquisition.
AltaGas’ forward-looking statements are subject to certain risks and uncertainties which could cause results or events to differ from current expectations, including, without limitation: access to and use of capital markets; market value of AltaGas’ securities; AltaGas’ ability to pay dividends; AltaGas’ ability to service or refinance its debt and manage its credit rating and risk; prevailing economic conditions; potential litigation; AltaGas’ relationships with external stakeholders, including Aboriginal stakeholders; volume throughput and the impacts of commodity pricing, supply, composition and other market risks; available electricity prices; interest rate, exchange rate and counterparty risks; the Harmattan Rep agreements; legislative and regulatory environment; underinsured losses; weather, hydrology and climate changes; the potential for service interruptions; availability of supply from Cook Inlet; availability of biomass fuel; AltaGas’ ability to economically and safely develop, contract and operate assets; AltaGas’ ability to update infrastructure on a timely basis; AltaGas’ dependence on certain partners; impacts of climate change and carbon taxing; effects of decommissioning, abandonment and reclamation costs; impact of labour relations and reliance on key personnel; cybersecurity risks; risks associated with the acquisition and integration of WGL, and the underlying business of WGL; and the other factors discussed under the heading “Risk Factors” in the Corporation’s AIF for the year ended December 31, 2017 and set out in AltaGas’ other continuous disclosure documents.
Many factors could cause AltaGas’ or any particular business segment’s actual results, performance or achievements to vary from those described in this MD&A, including, without limitation, those listed above and the assumptions upon which they are based proving incorrect. These factors should not be construed as exhaustive. Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially from those described in this MD&A as intended, planned, anticipated, believed, sought, proposed, estimated, forecasted, expected, projected or targeted and such forward-looking statements included in this MD&A, should not be unduly relied upon. The impact of any one assumption, risk, uncertainty, or other factor on a particular forward-looking statement cannot be determined with certainty because they are interdependent and AltaGas’ future decisions and actions will depend on management’s assessment of all information at the relevant time. Such statements speak only as of the date of this MD&A. AltaGas does not intend, and does not assume any obligation, to update these forward-looking statements except as required by law. The forward-looking statements contained in this MD&A are expressly qualified by these cautionary statements.
Financial outlook information contained in this MD&A about prospective financial performance, financial position, or cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on AltaGas management’s (Management) assessment of the relevant information currently available. Readers are cautioned that such financial outlook information contained in this MD&A should not be used for purposes other than for which it is disclosed herein.
Additional information relating to AltaGas, including its quarterly and annual MD&A and Consolidated Financial Statements, Annual Information Form, and press releases are available through AltaGas’ website at www.altagas.ca or through SEDAR at www.sedar.com.
RECENT DEVELOPMENTS
Public Offering of AltaGas Canada Inc.
On September 12, 2018, AltaGas filed a preliminary prospectus for the initial public offering (IPO) of AltaGas Canada Inc. (ACI), a wholly owned subsidiary of AltaGas. ACI will hold Canadian rate-regulated natural gas distribution utility assets and contracted wind power in Canada, as well as an approximate 10 percent indirect equity interest in the Northwest Hydro Electric facilities in British Columbia (Northwest Hydro). The final prospectus was filed on October 18, 2018 reflecting a final price of $14.50 per common share of ACI. On October 25, 2018, the ACI IPO was successfully completed. Upon close, AltaGas holds approximately 45 percent of ACI common shares, which could be reduced to approximately 37 percent if the over-allotment option is exercised in full. Total expected proceeds to AltaGas (including $239 million from the sale of common shares and $635 million of debt) are approximately $874 million (before the deduction of underwriting fees and expenses) which could increase to approximately $910 million (before the deduction of underwriting fees and expenses) if the over-allotment option is exercised in full.
The expected proceeds from the ACI IPO, sale of non-core midstream and power assets (See Pending Sales of Non-Core Midstream and Power Assets section below), as well as the recently completed monetization of the 35 percent interest in the Northwest Hydro facilities in the second quarter of 2018, are expected to raise approximately $2.4 billion (US$1.9 billion). After taking into effect these asset sales, AltaGas will have approximately US$1.2 billion remaining on the bridge facility related to the
acquisition of WGL Holdings, Inc. (the WGL Acquisition). The final planned step in the repayment of the bridge facility is expected to include term debt and hybrid securities issuances. AltaGas expects to complete all funding steps for the total repayment of the outstanding bridge facility in the fourth quarter of 2018.
Pending Sales of Non-Core Midstream and Power Assets
On September 10, 2018, AltaGas announced that it had entered into definitive agreements for the sale of non-core midstream and power assets in Canada and power assets in the United States, for total proceeds of approximately $560 million. The proceeds will be used to repay a significant portion of the bridge facility.
The sale of non-core midstream and power assets in Canada is to Birch Hill Equity Partners Management Inc., as general partner of Birch Hill Equity Partners Fund V (Birch Hill), for approximately $165 million. Included in the sale is AltaGas’ commercial and industrial customer portfolio in Canada as well as 43.7 million shares of Tidewater Midstream and Infrastructure Inc. (Tidewater). The sale of the Tidewater shares was completed in September 2018 for proceeds of approximately $63 million, with the remainder of the transaction expected to be completed in the fourth quarter of 2018, pending various approvals.
The sale of gas-fired power assets in California is to Middle River Power III (Middle River), a whole owned-subsidiary of Avenue Capital, for a purchase price of approximately US$300 million. The assets comprise the Tracy, Hanford and Henrietta plants totaling 523 MW of capacity. The effective date of the transaction is September 1, 2018, and it is expected to close in the fourth quarter of 2018, pending regulatory approvals.
Acquisition of WGL Holdings, Inc. (WGL)
Following the receipt of all required federal, state, and local regulatory approvals, on July 6, 2018 the Corporation acquired WGL Holdings, Inc., creating a North American leader in the clean energy economy and enhancing AltaGas’ position as a leading North American clean energy infrastructure company. The aggregate purchase price was approximately $9.3 billion (US$7.1 billion), including the assumption of approximately $3.3 billion (US$2.5 billion) of debt and $41 million (US$31 million) of preferred shares. The WGL Acquisition will benefit all three business segments: Gas, Power and Utilities. In the Gas segment, the combined midstream business will provide producers with global market access; in the Power segment, a clean power generation footprint covering hydroelectric, gas, wind, small scale solar, biomass, and energy storage will expand AltaGas’ clean energy offerings; and in the Utility segment, the high quality utility assets will be underpinned by regulated, low risk cash flow.
Under the terms of the transaction, WGL shareholders received US$88.25 per common share. The net cash consideration was approximately $6.0 billion (US$4.6 billion). The WGL Acquisition was financed through net proceeds of approximately $2.3 billion from the sale of subscription receipts, gross proceeds of approximately $922 million from the sale of a 35 percent minority interest in the Northwest Hydro facilities, draws on the fully committed acquisition credit facility of $3.0 billion (US$2.3 billion) and existing cash on hand. The total funding included additional amounts for the payment of fees and regulatory commitments related to the WGL Acquisition. The acquisition credit facility could remain in place for up to 12 to 18 months after closing of the WGL Acquisition, however AltaGas expects to fully repay the facility in the fourth quarter of 2018, subject to the close of pending asset sales and the timing of offering of term debt and hybrid securities. The sale of the subscription receipts was completed in the first quarter of 2017 (see Share Information section below) and upon closing of the WGL Acquisition, the subscription receipts were exchanged into approximately 84.5 million common shares of AltaGas.
WGL is a diversified energy infrastructure company and the sole common shareholder of Washington Gas Light Company (Washington Gas), a regulated natural gas utility headquartered in Washington, D.C., serving approximately 1.2 million customers in Virginia, Maryland, 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 northeastern United States. WGL’s midstream business has interstate transportation and storage contracts as well as marine-based energy export capabilities via the U.S. East Coast through WGL’s access to the Cove Point LNG Terminal in Maryland which was developed by a third party and recently began exporting LNG. WGL also owns contracted clean power assets, with a focus on solar distributed generation and energy efficiency assets throughout the United States. In addition, WGL has a retail gas and power marketing business with approximately 211,000 customers in Maryland, Virginia, Delaware, Pennsylvania and the District
of Columbia. With the close of the WGL Acquisition, AltaGas has over $22 billion of assets and approximately 1.8 million rate regulated gas customers (approximately 1.6 million customers after the close of the ACI IPO).
WGL’s activities are carried out through AltaGas’ three business segments: Gas, Power, and Utilities. Specifically,
· AltaGas’ Gas segment now includes WGL Midstream, Inc.’s (WGL Midstream) interest in four pipelines in the northeastern United States. This includes 30 percent ownership in the Stonewall Gas Gathering System (Stonewall), which is currently in service and designed to gather 1.4 Bcf/d from West Virginia; a net 21 percent ownership in Central Penn Pipeline (Central Penn), which is designed to transport 1.7 Bcf/d in Pennsylvania and became operational in October 2018; 10 percent ownership in Mountain Valley Pipeline, which is designed to transport 2.0 Bcf/d from West Virginia to Virginia with an expected in-service date in the fourth quarter of 2019; and 10 percent ownership in the proposed Constitution Pipeline. In addition, AltaGas’ Gas segment will include the results from the retail gas marketing business of WGL Energy Services, Inc. (WGL Energy Services).
· AltaGas’ Power segment now includes the results from WGL Energy Systems, Inc. (WGL Energy Systems), which provides clean and energy-efficient solutions including distributed generation (commercial solar, fuel cells, combined heat and power and other distributed generation solutions) and energy efficiency projects to government and commercial clients, as well as the operations of WGSW Inc. (WGSW), a holding company formed to invest in alternative energy assets. In addition, AltaGas’ Power segment includes the results from WGL Energy Services’ retail power marketing business.
· AltaGas’ Utilities segment now includes the results from the operations of Washington Gas and Hampshire Gas Company (Hampshire). Washington Gas provides regulated gas distribution services (including the sale and delivery of natural gas) to end-use customers. Hampshire provides regulated interstate natural gas storage services to Washington Gas.
For the three and nine months ended September 30, 2018, the results of WGL have been included for the period subsequent to the close of the transaction on July 6, 2018.
ALTAGAS ORGANIZATION
The businesses of AltaGas are operated by AltaGas and a number of its subsidiaries including, without limitation, AltaGas Services (U.S.) Inc., AltaGas Utility Holdings (U.S.) Inc., and SEMCO Holding Corporation; 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, Northwest 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). Upon close of the ACI IPO, AUI, Heritage Gas and PNG are no longer subsidiaries of AltaGas.
With the close of the WGL Acquisition, AltaGas’ subsidiaries also include: Wrangler 1 LLC, WGL Holdings Inc., and Washington Gas Resources Corporation; in regards to the Gas business, WGL Midstream and the retail gas marketing business of WGL Energy Services; in regards to the Power business, WGSW, WGL Energy Systems, and the retail power marketing business of WGL Energy Services; and, in regards to the Utility business, Washington Gas and Hampshire.
OVERVIEW OF THE BUSINESS
AltaGas, a Canadian corporation, is a leading North American clean energy infrastructure company with strong growth opportunities and a focus on owning and operating assets to provide clean and affordable energy to its customers. The Corporation’s long-term strategy is to grow in attractive areas across its Gas, Power, and Utility business segments seeking optimal capital deployment. In the Gas business, the Corporation is focused on optimizing the full value chain of energy exports by providing producers with solutions, including global market access off both coasts of North America via the Corporation’s
footprint in two of the most prolific gas plays — the Montney and Marcellus. To optimize capital deployment, the Corporation seeks to differentially invest in U.S utilities located in strong growth markets with increasing construction to support customer additions, system improvement and accelerated replacement programs. In the Power business, AltaGas seeks to create innovative solutions with light capital investment utilizing the Corporation’s clean energy expertise. AltaGas has three business segments:
· Gas, which transacts more than 3 Bcf/d of natural gas and includes natural gas gathering and processing, natural gas liquids (NGL) extraction and fractionation, transmission, storage, natural gas and NGL marketing, the Corporation’s 50 percent interest in AltaGas Idemitsu Joint Venture Limited Partnership (AIJVLP), an indirectly held one-third ownership investment in Petrogas Energy Corp. (Petrogas), through which AltaGas’ interest in the Ferndale Terminal is held, an interest in four regulated pipelines in the Marcellus/Utica gas formation in the northeastern United States and WGL’s retail gas marketing business;
· Power, which, after the close of the ACI IPO, includes 1,931 MW of gross capacity from natural gas-fired, hydro, wind, biomass, solar, other distributed generation and energy storage assets located in 2 provinces in Canada and 20 states and the District of Columbia in the United States. The Power business also includes energy efficiency contracting and WGL’s retail power marketing business; and
· Utilities, which, after the close of the ACI IPO, serves approximately 1.6 million customers with a rate base of approximately $4.4 billion through ownership of regulated natural gas distribution utilities across 5 jurisdictions in the United States, and a regulated natural gas storage utility in the United States, delivering clean and affordable natural gas to homes and businesses. The Utilities business also includes storage facilities and contracts for interstate natural gas transportation and storage services.
THIRD QUARTER FINANCIAL HIGHLIGHTS
(Normalized EBITDA, normalized funds from operations, normalized net income, net debt, and net debt to total capitalization ratio are non-GAAP financial measures. Please see Non-GAAP Financial Measures section of this MD&A.)
· On July 6, 2018, AltaGas completed the acquisition of WGL for an aggregate purchase price of approximately $9.3 billion (US$7.1 billion), including the assumption of debt and preferred shares. Upon closing of the WGL Acquisition, 84.5 million subscription receipts were exchanged for common shares;
· On September 12, 2018, AltaGas filed a preliminary prospectus for the IPO of AltaGas Canada Inc., a wholly owned subsidiary of AltaGas. ACI will hold Canadian rate-regulated natural gas distribution utility assets and contracted wind power in Canada, as well as an approximate 10 percent indirect equity interest in the Northwest Hydro facilities in British Columbia;
· On September 10, 2018, AltaGas announced that it has entered into definitive agreements for the sale of non-core midstream and power assets in Canada and power assets in the United States for total proceeds of approximately $560 million;
· On September 26, 2018, AltaGas announced that it has entered into a definitive agreement with Black Swan Energy Ltd. (Black Swan) to acquire 50 percent ownership in certain existing and future natural gas processing plants of Black Swan. AltaGas and Black Swan will also enter into long term processing, transportation and marketing agreements that include new AltaGas liquids handling infrastructure, strengthening AltaGas’ Northeast B.C. value proposition and connecting producers with additional options for energy exports. The total capital investment by AltaGas is expected to be approximately $230 million and the transaction closed on October 2, 2018;
· On August 27, 2018, AltaGas announced that it has entered into definitive agreements with Kelt Exploration (LNG) Ltd. (Kelt) to provide an energy infrastructure solution for the liquids-rich Inga Montney development located in British Columbia. This underpins the expansion of AltaGas’ Townsend complex including the addition of a 198 MMcf per day C3+ deep cut gas processing facility and provides Kelt with firm processing of 75 MMcf per day of raw gas under an initial 10 year take-or-pay agreement;
· On July 26, 2018, AltaGas announced the expansion of its Board of Directors (the Board) from nine to twelve seats and the appointment of three new directors. The expansion of the Board reflects AltaGas’ scope and growing complexity and the experience and expertise required by the Board to support AltaGas’ business, operations and strategic objectives;
· On July 25, 2018, AltaGas announced the resignation of David Harris, President and CEO. David Cornhill, the Founder and Chairman of AltaGas, and Phillip Knoll, an experienced industry executive and Board Member, will act as interim co-CEOs until a replacement is found. The key strategic priorities, financing plan for WGL and business operations remain unchanged and on track;
· Normalized EBITDA was $226 million compared to $190 million in the third quarter of 2017;
· Normalized funds from operations were $117 million ($0.45 per share) compared to $143 million ($0.83 per share) in the third quarter of 2017;
· Net loss applicable to common shares was $726 million ($2.78 per share) compared to net income of $18 million ($0.10 per share) in the third quarter of 2017;
· Normalized net loss was $17 million ($0.07 per share) compared to normalized net income of $48 million ($0.28 per share) in the third quarter of 2017;
· Net debt was $10.4 billion as at September 30, 2018, compared to $3.6 billion at December 31, 2017; and
· Net debt-to-total capitalization ratio was 60 percent as at September 30, 2018, compared to 44 percent as at December 31, 2017.
HIGHLIGHTS SUBSEQUENT TO QUARTER END
· On October 18, 2018, AltaGas announced the filing of the final prospectus and pricing for the ACI IPO. Final pricing is $14.50 per ACI common share;
· On October 25, 2018, the ACI IPO was successfully completed. Upon close, AltaGas holds approximately 45 percent of ACI common shares, which could be reduced to approximately 37 percent if the over-allotment option is exercised in full. Total expected proceeds to AltaGas (including $239 million from the sale of common shares and $635 million of debt) are
approximately $874 million (before the deduction of underwriting fees and expenses) which could increase to approximately $910 million (before the deduction of underwriting fees and expenses) if the over-allotment option is exercised in full; and
· On October 4, 2018, the Federal Energy Regulatory Commission (FERC) issued its authorization to place the Central Penn Pipeline into service. The pipeline began operations on October 6, 2018.
· On October 29, 2018, the Board suspended, until further notice, its Premium Dividend Reinvestment Plan (PDRIP), effective December 18, 2018. Accordingly, the dividend payable on December 17, 2018 will be the last dividend to be included in the PDRIP. The Dividend Reinvestment Plan will remain unchanged.
CONSOLIDATED FINANCIAL REVIEW
|
| Three Months Ended |
| Nine Months Ended |
| ||||
($ millions) |
| 2018 |
| 2017 |
| 2018 |
| 2017 |
|
Revenue |
| 1,041 |
| 502 |
| 2,530 |
| 1,811 |
|
Normalized EBITDA(1) | �� | 226 |
| 190 |
| 615 |
| 584 |
|
Net income (loss) applicable to common shares |
| (726 | ) | 18 |
| (676 | ) | 41 |
|
Normalized net income (loss)(1) |
| (17 | ) | 48 |
| 76 |
| 141 |
|
Total assets |
| 22,958 |
| 9,932 |
| 22,958 |
| 9,932 |
|
Total long-term liabilities |
| 11,319 |
| 4,624 |
| 11,319 |
| 4,624 |
|
Net additions to property, plant and equipment |
| 367 |
| 147 |
| 556 |
| 274 |
|
Dividends declared(2) |
| 162 |
| 90 |
| 357 |
| 268 |
|
Normalized funds from operations(1) |
| 117 |
| 143 |
| 407 |
| 436 |
|
|
| Three Months Ended |
| Nine Months Ended |
| ||||
($ per share, except shares outstanding) |
| 2018 |
| 2017 |
| 2018 |
| 2017 |
|
Net income (loss) per common share - basic |
| (2.78 | ) | 0.10 |
| (3.28 | ) | 0.24 |
|
Net income (loss) per common share - diluted |
| (2.78 | ) | 0.10 |
| (3.28 | ) | 0.24 |
|
Normalized net income (loss) - basic(1) |
| (0.07 | ) | 0.28 |
| 0.37 |
| 0.83 |
|
Dividends declared(2) |
| 0.55 |
| 0.53 |
| 1.64 |
| 1.58 |
|
Normalized funds from operations(1) |
| 0.45 |
| 0.83 |
| 1.98 |
| 2.57 |
|
Shares outstanding - basic (millions) |
|
|
|
|
|
|
|
|
|
During the period(3) |
| 261 |
| 172 |
| 206 |
| 170 |
|
End of period |
| 269 |
| 173 |
| 269 |
| 173 |
|
(1) Non-GAAP financial measure; see discussion in Non-GAAP Financial Measures section of this MD&A.
(2) Dividends declared per common share per month: $0.175 beginning on August 25, 2016, and $0.1825 beginning on November 27, 2017.
(3) Weighted average.
Three Months Ended September 30
Normalized EBITDA for the third quarter of 2018 was $226 million, compared to $190 million for the same quarter in 2017. Factors positively impacting normalized EBITDA included contributions from WGL for the period subsequent to transaction close on July 6, 2018, contributions from the Townsend 2A and North Pine facilities which commenced commercial operations in the fourth quarter of 2017, higher realized frac spread, and the stronger U.S. dollar on reported results from U.S. assets. These were partially offset by lower river flows at Northwest Hydro, decreased revenue from SEMCO due to U.S. tax reform, the expiry of the Power Purchase Arrangement (PPA) at the Ripon gas-fired electricity generation facility in May 2018 (partially offset by the new Resource Adequacy (RA) contract which began in the second quarter of 2018 and is in place until the end of 2018), and impacts related to the change in operatorship of the Younger extraction facility (Younger). For the three months ended September 30, 2018, the average Canadian/U.S. dollar exchange rate increased to 1.31 from an average of 1.25 in the same quarter of 2017, resulting in an increase in normalized EBITDA of approximately $3 million.
Normalized funds from operations for the third quarter of 2018 were $117 million ($0.45 per share), compared to $143 million ($0.83 per share) for the same quarter in 2017. The decrease was mainly due to the same drivers as normalized EBITDA and higher interest expense. In the third quarter of 2018, AltaGas received $3 million of dividend income from the Petrogas Preferred Shares (2017 - $3 million) and $1 million of common share dividends from Petrogas (2017 - $1 million).
In the third quarter of 2018, AltaGas recorded pre-tax provisions of approximately $698 million (after-tax $539 million). These provisions were primarily related to assets classified as held for sale, including the San Joaquin Power assets in California comprising of the Tracy, Hanford and Henrietta plants, non-core midstream and power assets in Canada, and certain assets included in the IPO of ACI. (See sections Pending Sales of Non-Core Midstream and Power Assets and Public Offering of
AltaGas Canada Inc. above). In addition, pre-tax provisions of $37 million and $2 million were recorded on certain remaining gas assets and the Pomona Gas Repowering project, respectively.
Operating and administrative expenses for the third quarter of 2018 were $496 million, compared to $125 million for the same quarter in 2017. The increase was mainly due to WGL merger commitment costs of $182 million and higher transaction costs on acquisitions (primarily related to the WGL Acquisition) of $35 million in the third quarter of 2018 compared to $9 million in the same quarter in 2017, as well as the inclusion of WGL’s operating and administrative expenses for the period since transaction close on July 6, 2018. Depreciation and amortization expense for the third quarter of 2018 was $122 million, compared to $69 million for the same quarter in 2017. The increase was mainly due to depreciation and amortization expense on assets acquired in the WGL Acquisition. Interest expense for the third quarter of 2018 was $112 million, compared to $40 million for the same quarter in 2017. The increase was predominantly due to interest on the bridge facility, interest on debt assumed in the WGL Acquisition and higher average debt balances.
AltaGas recorded an income tax recovery of $221 million for the third quarter of 2018 compared to income tax expense of $14 million in the same quarter of 2017. The decrease in tax expense was mainly due to tax recoveries booked on asset provisions and WGL transaction and merger commitment costs.
Net loss applicable to common shares for the third quarter of 2018 was $726 million ($2.78 per share), compared to net income of $18 million ($0.10 per share) for the same quarter in 2017. The decrease was mainly due to provisions on assets recognized during the quarter as discussed above, higher transaction and merger commitment costs related to the WGL Acquisition, higher depreciation and amortization expense, higher interest expense, and higher net income applicable to non-controlling interests, partially offset by a higher income tax recovery, the same previously referenced factors impacting normalized EBITDA, lower unrealized losses recognized on risk management contracts, and higher gains on investments.
Normalized net loss was $17 million ($0.07 per share) for the third quarter of 2018, compared to normalized net income of $48 million ($0.28 per share) reported for the same quarter in 2017. The decrease was mainly due to higher depreciation and amortization expense, interest expense, and preferred share dividends, partially offset by a higher income tax recovery, and the same previously referenced factors impacting normalized EBITDA. Normalizing items in the third quarter of 2018 included after-tax amounts related to provisions on assets, merger commitment costs and transaction costs associated with the WGL Acquisition, gains on investments, unrealized losses on risk management contracts, realized gains on foreign exchange derivatives, change in fair value of natural gas optimization inventory, and financing costs associated with the bridge facility of $12 million. In the third quarter of 2017, normalizing items included after-tax amounts related to transaction costs on acquisitions, unrealized losses on risk management contracts, unrealized gains on long-term investments, and financing costs associated with the bridge facility for the WGL Acquisition of $4 million.
Nine Months Ended September 30
Normalized EBITDA for the nine months ended September 30, 2018 was $615 million, compared to $584 million for the same period in 2017. The increase was mainly due to contributions from WGL for the period subsequent to transaction close on July 6, 2018, higher realized frac spread and frac exposed volumes, contributions from the Townsend 2A and North Pine facilities which commenced commercial operations in the fourth quarter of 2017, and higher rates and growth in customer base as well as colder weather experienced at certain of the utilities. These increases were partially offset by decreased revenue from SEMCO due to U.S. tax reform, lower river flows at Northwest Hydro, the expiry of the Ripon PPA in May 2018 (partially offset by the new RA contract which began in the second quarter of 2018 and is in place until the end of 2018), the impact from the weaker U.S. dollar on reported results from U.S. assets, and lower equity earnings from Petrogas. For the nine months ended September 30, 2018, the average Canadian/U.S. dollar exchange rate decreased to 1.29 from an average of 1.31 in the same period of 2017, resulting in a decrease in normalized EBITDA of approximately $6 million.
Normalized funds from operations for the nine months ended September 30, 2018 were $407 million ($1.98 per share), compared to $436 million ($2.57 per share) for the same period in 2017, reflecting the same drivers as normalized EBITDA and higher interest expense. During the nine months ended September 30, 2018, AltaGas received $9 million of dividend income
from the Petrogas Preferred Shares (2017 - $9 million) and $4 million of common share dividends from Petrogas (2017 - $4 million).
As mentioned above, in the third quarter of 2018, AltaGas recorded pre-tax provisions of approximately $698 million (after-tax $539 million), primarily relating to assets held for sale.
Operating and administrative expenses for the nine months ended September 30, 2018 were $783 million, compared to $421 million for the same period in 2017. The increase was mainly due to WGL merger commitment costs of $182 million and higher transaction costs on acquisitions (primarily related to the WGL Acquisition) of $52 million in the first nine months of 2018 compared to $50 million in the same period of 2017, as well as the inclusion of WGL’s operating and administrative expenses for the period since transaction close on July 6, 2018. Depreciation and amortization expense for the nine months ended September 30, 2018 was $268 million, compared to $211 million for the same period in 2017. The increase was mainly due to depreciation and amortization expense on assets acquired in the WGL Acquisition. Interest expense for the nine months ended September 30, 2018 was $198 million, compared to $127 million for the same period in 2017. The increase was mainly due to interest on the bridge facility, interest on debt assumed in the WGL Acquisition and higher average debt balances.
AltaGas recorded an income tax recovery of $200 million for the nine months ended September 30, 2018 compared to income tax expense of $43 million for the same period of 2017. The decrease in tax expense was mainly due to tax recoveries booked on asset provisions and WGL transaction and merger commitment costs.
Net loss applicable to common shares for the nine months ended September 30, 2018 was $676 million ($3.28 per share) compared to net income of $41 million ($0.24 per share) for the same period in 2017. The decrease was mainly due to provisions on assets recognized during the third quarter of 2018 as discussed above, higher transaction and merger commitment costs related to the WGL Acquisition, higher depreciation and amortization expense, higher interest expense, higher realized losses on foreign exchange derivatives, higher net income applicable to non-controlling interests and higher preferred share dividends, partially offset by a higher income tax recovery, lower unrealized losses recognized on risk management contracts and the same previously referenced factors impacting normalized EBITDA.
Normalized net income was $76 million ($0.37 per share) for the nine months ended September 30, 2018, compared to normalized net income of $141 million ($0.83 per share) reported for the same period in 2017. The decrease was mainly due to higher depreciation and amortization expense, higher interest expense and higher preferred share dividends, partially offset by a higher income tax recovery, and the same previously referenced factors impacting normalized EBITDA. Normalizing items for the nine months ended September 30, 2018 included after-tax amounts related to provisions on assets, merger commitment costs and transaction costs associated with the WGL Acquisition, realized losses on foreign exchange derivatives, unrealized gains on risk management contracts, gains on investments, change in fair value of natural gas optimization inventory, gains on sale of assets, and financing costs associated with the bridge facility of $18 million. For the nine months ended September 30, 2017, normalizing items included after-tax amounts related to transaction costs on acquisitions, unrealized losses on risk management contracts and long-term investments, losses on sale of assets, provision on assets, and financing costs associated with the bridge facility for the WGL Acquisition of $11 million.
2018 OUTLOOK
The WGL Acquisition closed on July 6, 2018. As a combined entity, AltaGas expects normalized EBITDA to increase by approximately 25 to 30 percent and normalized funds from operations to increase by approximately 10 percent compared to prior year. The decrease in normalized funds from operations estimates to approximately 10 percent compared to the estimates of 15 to 20 percent disclosed in the second quarter of 2018 are primarily due to timing and seasonality of WGL earnings, higher WGL utility leak remediation expenses, lower Northwest Hydro river flows, and delays to the Central Penn pipeline in-service date.
The WGL Acquisition will drive growth in all three business segments. The combined Utilities segment is expected to have the largest contribution to EBITDA, followed by the Gas segment and then the Power segment. Specifically for Utilities, the combined segment has an overall rate base of approximately $4.4 billion (after the closing of the ACI IPO) and is expected to grow through utility capital investments such as accelerated utility pipe recovery plans and the Marquette Connector Pipeline (MCP) as well as the addition of new customers. The WGL Acquisition has also increased the number of utility customers by approximately 1.2 million. The Gas segment is expected to benefit from the addition of WGL’s pipeline investments in the prolific Marcellus/Utica gas resource regions as well as a gas supply agreement associated with the Cove Point LNG Terminal which began exporting LNG this year. WGL’s investment in Stonewall is currently in-service, the Central Penn pipeline became operational in October 2018 and the Corporation expects the Mountain Valley pipeline to be operational in the fourth quarter of 2019. Finally, the Power segment is expected to benefit from the addition of WGL’s commercial energy systems and retail marketing business, both of which are expected to provide ongoing growth opportunities. For further information on the WGL Acquisition see the Recent Developments section of this MD&A.
The expected increase to EBITDA and funds from operations in 2018 compared to 2017 for the combined entity is mainly as a result of contributions from the WGL Acquisition in all three segments, as well as higher realized frac spreads mainly due to higher hedged prices, full year contributions from Townsend 2A and the first train of the North Pine facility, and colder weather and rate base and customer growth at certain of the utilities. These increases may be partially offset by the impact of the timing of pending sales of non-core midstream and power assets, the timing of the close of the ACI IPO, lower Northwest Hydro river flows, the expiry of the Ripon PPA, and a weaker U.S. dollar on reported results of the U.S. assets. U.S. tax reform is expected to be negative to normalized EBITDA and funds from operations for AltaGas’ U.S. businesses while, on a net income basis, the impact of U.S. tax reform is expected to be positive.
The overall forecasted normalized EBITDA and funds from operations for the combined business include assumptions around the U.S./Canadian dollar exchange rate, the impact of certain contemplated asset monetizations and other financing initiatives as part of the WGL financing plan, and the impact of U.S. tax reform. Any variance from AltaGas’ current assumptions could impact the forecasted increase to normalized EBITDA and funds from operations.
AltaGas estimates an average of approximately 10,200 Bbls/d will be exposed to frac spreads prior to hedging activities. For 2018, AltaGas has frac hedges in place for approximately 7,500 Bbls/d at an average price of approximately $33/Bbl excluding basis differentials.
GROWTH CAPITAL
Based on projects currently under review, development or construction, and including the WGL capital program for the period subsequent to close, AltaGas expects net invested capital expenditures for the combined entity in the range of $1.2 to $1.4 billion. For the combined entity, the Gas segment will account for approximately 45 to 50 percent of total capital expenditures, while the Utilities segment will account for approximately 45 to 50 percent and the Power segment will account for the remainder. Gas and Power maintenance capital is expected to be approximately $30 to $35 million of the total capital expenditures in 2018. The majority of AltaGas’ capital expenditures is focused on the continued construction at the Ridley Island Propane Export Terminal (RIPET), maintaining and growing rate base at the Utilities, WGL’s investments in the Central Penn and Mountain Valley gas pipeline developments in the Marcellus/Utica gas formation, pre-construction design, engineering, and right-of-way procurement for the Marquette Connector Pipeline, capital expenditures related to the recent agreement with Black Swan, the Townsend 2B project with Kelt, and growth capital associated with the tie-in of incremental third party gas volumes in the Western Canadian Basin. The Corporation continues to focus on enhancing productivity and streamlining businesses.
AltaGas’ 2018 committed capital program is expected to be funded through internally-generated cash flow, asset sales, the Premium DividendTM, Dividend Reinvestment and Optional Cash Purchase Plan (DRIP), and normal course borrowings on existing committed credit facilities.
TM Denotes trademark of Canaccord Genuity Corp.
Gas Projects
Ridley Island Propane Export Terminal
RIPET is located near Prince Rupert, British Columbia, and is expected to be the first propane export facility off the west coast of Canada. The site has a locational advantage given very short shipping distances to markets in Asia, notably a 10-day shipping time compared to 25 days from the U.S. Gulf Coast. The construction cost of RIPET is estimated to be approximately $450 to $500 million and RIPET is expected to ship 1.2 million tonnes of propane per annum (which is equivalent to approximately 40,000 Bbls/d of export capacity).
Construction of RIPET commenced during the second quarter of 2017. With internal steel tank construction and related infrastructure advancing as planned, the overall LPG storage tank construction remains on schedule. Rail and marine loading infrastructure are also progressing, with placement of the sub-ballast and ballast underway and foundations for the rail offloading racks advancing. Installation of the marine jetty modules has advanced ahead of schedule and is expected to be completed during the fourth quarter of 2018. The team is simultaneously continuing construction of the balance of plant and has commenced work on the operations building. The site construction management team and project support teams have successfully hit all critical milestones to date on the RIPET master schedule and members of the operations team are now permanently on site to initiate a smooth transition. After comprehensive commissioning activities, the facility will begin its operational phase in the first quarter of 2019 with the introduction of feedstock propane and filling the refrigerated storage tank with liquefied product. First cargo is expected early in the second quarter of 2019 which aligns with the propane contract year.
Based on production from its existing facilities and forecasts from new plants under construction and in active development, AltaGas anticipates having physical volumes equal to approximately 50 percent of the expected capacity of 1.2 million tonnes per annum. The remaining 50 percent is expected to be supplied by producers and other suppliers. Based on signed agreements and other initiatives AltaGas is pursuing, total propane supply for RIPET is expected to achieve the initial 40,000 bbl/d target by the project in-service date. Based on negotiations with a number of producers and other suppliers, AltaGas expects to underpin approximately 40 percent of RIPET’s annual expected capacity under tolling arrangements.
AltaGas LPG and Astomos have entered into a multi-year agreement for the purchase of at least 50 percent of the 1.2 million tonnes per annum of propane expected to be available to be shipped from RIPET each year. Commercial agreements to secure the remaining capacity commitments are currently under negotiation and are expected to be completed by the end of 2018.
In 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 Ridley Island LPG Export Limited Partnership (RILE LP) to develop, own, and operate RIPET. AltaGas’ subsidiaries hold a 70 percent interest while Vopak holds a 30 percent interest in RILE LP. The construction cost of RIPET will be funded by AltaGas LPG and Vopak in proportion to their respective interests in RILE LP. RILE LP will be consolidated by AltaGas. AltaGas LPG has the right to 100 percent of the capacity of RIPET.
Central Penn Pipeline
Central Penn is a new 185 mile pipeline originating in Susquehanna County, Pennsylvania and extending to Lancaster County, Pennsylvania, and is an integral part of the larger Atlantic Sunrise project operated by The Williams Companies through Transcontinental Gas Pipeline Company LLC (Transco). The Central Penn pipeline is regulated by the FERC. The Atlantic Sunrise project is designed to supply enough natural gas to meet the daily needs of more than 7 million American homes in the region. WGL Midstream owns an indirect 21 percent interest in Central Penn, which will have the capacity to transport and deliver up to approximately 1.7 Bcf/d of natural gas from the northeastern Marcellus producing area to markets in the mid-Atlantic and Southeastern regions of the United States. On February 3, 2017, the FERC issued an order granting Certificate of Public Convenience and Necessity, subject to certain conditions. On September 15, 2017, the FERC granted authorization to proceed with the construction of the Central Penn pipeline. Central Penn was placed in service in early October 2018.
In February 2014, WGL Midstream and certain partners formed Meade Pipeline Co LLC (Meade). Meade (39 percent) and Transco (61 percent) have joint ownership of Central Penn. WGL Midstream expects to invest approximately US$450 million for
a 55 percent interest in Meade (21 percent indirect interest in Central Penn). On a cash basis, as of September 30, 2018, WGL Midstream has spent approximately US$435 million on Meade.
In addition to the investment in Meade, WGL Midstream entered into an agreement with Cabot Oil & Gas Corporation (Cabot) whereby WGL Midstream will purchase 0.5 Bcf/d of natural gas from Cabot over a 15 year term. As part of this agreement, Cabot has acquired 0.5 Bcf/d of firm gas transportation capacity on Transco’s Atlantic Sunrise project. This capacity will be released to WGL Midstream.
In August 2018, Meade executed an agreement with Transco to participate in an expansion of the Central Penn Pipeline (Leidy South) with an estimated capital investment of up to US$50 million by WGL Midstream. Leidy South is expected to add an estimated 0.6 Bcf/d of natural gas capacity to Central Penn through the addition of compression at new and existing stations. Meade will own 39 percent of the expanded capacity. WGL Midstream will indirectly own 21 percent of the expanded capacity through its 55 percent ownership interest in Meade. Leidy South is anticipated to be in-service as early as the fourth quarter of 2021 assuming all necessary regulatory approvals are received in a timely manner.
Mountain Valley Pipeline, LLC (Mountain Valley)
WGL Midstream owns a 10 percent equity interest in Mountain Valley. The proposed pipeline, which will be operated by EQT Midstream Partners, LP (EQT) and developed, constructed, and owned by Mountain Valley (a venture of EQT and other entities), will transport approximately 2.0 Bcf/d and will extend EQT Corporation’s Equitrans system in Wetzel County, West Virginia to Transco’s Station 165 in Pittsylvania County, Virginia. The pipeline is estimated to span approximately 300 miles and provide access to the growing Southeast demand markets.
On October 13, 2017, the FERC issued the Certificate of Public Convenience and Necessity for the pipeline. In early 2018, the FERC granted several notices to proceed with certain construction activities on the pipeline. Mountain Valley has submitted additional requests to the FERC for notices to proceed. On June 21, 2018, the 4th U.S. Circuit Court of Appeals granted a stay of permit for certain construction activities in West Virginia, while the court considers challenging a federal permit. On July 27, 2018, the Court of Appeals set aside the U.S. Forest Service and Bureau of Land Management’s decisions granting a right-of-way for a 3.5 mile segment of the pipeline. On August 29, 2018, FERC and the Court of Appeals issued separate orders that allowed for full construction activities to restart along the route with the exception of areas located within proximity of the Weston Gauley Bridge Turnpike Trail and the Jefferson National Forest. As a result of the legal, regulatory, and weather related delays, Mountain Valley has modified its construction schedule and the pipeline is targeted to be placed in-service during the fourth quarter of 2019. On October 2, 2018, the 4th Circuit Court of Appeals vacated a Clean Water Act Section 404 stream and wetland crossing permit issued by the Huntington District of the U.S. Army Corps of Engineers (USACE). This decision affects stream and wetland crossings along approximately 160 miles of the route in West Virginia, and Mountain Valley is evaluating options to understand its ability to continue with construction activities that do not include stream and wetland crossings along this portion of the route. Mountain Valley intends to apply for a new permit with the USACE. Mountain Valley expects to secure a new Nationwide 12 permit from the USACE early in 2019. With ongoing evaluation of its construction plan, Mountain Valley continues to target a full in-service during the fourth quarter 2019.
WGL Midstream expects to invest approximately US$350 million through the in-service date of the pipeline based on scheduled capital contributions and its contracted share of project costs. On a cash basis, as of September 30, 2018, WGL Midstream has invested approximately US$169 million in the pipeline. In addition, WGL has gas purchase commitments to buy approximately 0.5 Bcf/day of natural gas, at index-based prices, for a 20-year term, and will also be a shipper on the proposed pipeline.
In April 2018, WGL Midstream entered into a separate agreement with EQT to acquire a 5 percent equity interest in a project to build an interstate natural gas pipeline (the MVP Southgate project). The proposed pipeline will receive gas from the Mountain Valley Pipeline mainline in Pittsylvania County, Virginia and extend approximately 73 miles south to new delivery points in Rockingham and Alamance counties, North Carolina. The total commitment by WGL Midstream is expected to be approximately US$17.0 million and the lateral pipeline is expected to be placed into service in late 2020.
Northeastern British Columbia Expansion Projects
Townsend 2B
On August 27, 2018, AltaGas announced that it entered into definitive agreements with Kelt Exploration (LNG) Ltd. (Kelt) to provide an energy infrastructure solution for the liquids-rich Inga Montney development located in Northeast British Columbia. The commercial arrangements underpin the expansion of AltaGas’ Townsend complex including the addition of a 198 MMcf per day C3+ deep cut gas processing facility and provides Kelt with firm processing of 75 MMcf per day of raw gas under an initial 10 year take-or-pay agreement. The additional natural gas liquids will increase utilization in AltaGas’ existing liquids pipelines, position the Corporation well for an expansion of the North Pine fractionator, and provide additional propane supply to RIPET. The expansion of the Townsend complex coupled with enhanced NGL recovery will provide producers with more options for energy exports. The estimated project cost is approximately $180 million with an expected on-stream date in the fourth quarter of 2019.
Black Swan
On September 26, 2018, AltaGas announced that it entered into a definitive agreement with Black Swan to acquire 50 percent ownership in certain existing and future natural gas processing plants of Black Swan. AltaGas and Black Swan will also enter into long term processing, transportation and marketing agreements that include new AltaGas liquids handling infrastructure, strengthening AltaGas’ Northeast British Columbia value proposition and connecting producers with additional options for energy exports. The total capital investment by AltaGas is expected to be approximately $230 million and the transaction closed on October 2, 2018.
Alton Natural Gas Storage Project
Development of the Alton Natural Gas Storage Project, located near Truro, Nova Scotia is focusing on regulatory and construction planning, environmental study, and community engagement. The start-date for solution mining for cavern development is being determined. The Nova Scotia Minister of Environment is expected to make a decision on the Industrial Approval (IA) appeal by Sipekne’katik First Nation (SFN) in due course. In the meantime, the IA remains in effect for the project. AltaGas continues to work constructively with governments, regulators, and the Mi’kmaq of Nova Scotia. The Alton Natural Gas Storage Project is expected to provide up to 10 Bcf of natural gas storage capacity. The first phase of storage service for two caverns, consisting of approximately 4 Bcf of storage capacity, is expected to commence in 2022.
Utility Projects
Accelerated Utility Pipe Recovery Plans
Accelerated pipe replacement programs are in place in all three of Washington Gas’ utility jurisdictions. These are long-term programs with 17 to 35 remaining years, subject to both changing conditions and regulatory review and approval in five year increments. The anticipated expenditures over the next five years are approximately US$1 billion, with future increments projected to include significant expenditures as well. Washington Gas is accelerating pipe replacement in order to further enhance the safety and reliability of the pipeline system. In contrast to the traditional rate-making approach to capital investments, Washington Gas begins recovering the cost, including a return, for these investments immediately through approved surcharges for each accelerated pipe replacement program. Once new base rates are put into effect in a given jurisdiction, expenditures previously being recovered through the accelerated pipe replacement surcharge will be collected through the new base rates.
In the District of Columbia, the construction activities related to an accelerated replacement and encapsulation program targeting vintage mechanically coupled pipe began in 2009 and were completed in January 2017, with restoration and paving continuing into 2017. In 2013, Washington Gas filed PROJECTpipes in which Washington Gas proposed to replace bare and/or unprotected steel services, bare and targeted unprotected steel main, and cast iron main in its distribution system in the District of Columbia. In 2015, the PSC of DC approved the settlement agreement for PROJECTpipes, authorizing the recovery, through a surcharge, of total project costs not to exceed US$110 million through 2019.
In 2014, pursuant to the Strategic Infrastructure Development and Enhancement (STRIDE) law in Maryland, the PSC of Maryland approved Washington Gas’ initial STRIDE Plan to recover the reasonable and prudent costs associated with qualifying
infrastructure replacements through monthly surcharges. The PSC of Maryland approved replacement of bare and/or unprotected steel services and targeted copper and/or pre-1975 plastic services, bare and targeted unprotected steel main, mechanically coupled pipe main and service, and cast iron main in Washington Gas’ Maryland distribution system at an estimated five-year cost of US$200 million, including cost of removal, through 2018. In 2015, the PSC of Maryland approved one additional program applicable to gas distribution system replacements and three of the four requested additional programs applicable to gas transmission system replacements at an incremental cost of US$19 million, including cost of removal, in eligible infrastructure replacements over the remaining four years of the initial STRIDE Plan. In June 2018, Washington Gas filed a request for a second five-year plan (STRIDE 2.0) with the PSC of Maryland at an estimated cost of approximately US$394 million starting January 2019. The STRIDE 2.0 request is pending PSC of Maryland approval.
On April 21, 2011, the Commonwealth of Virginia State Corporation Commission (SCC of VA), pursuant to a new law to advance Virginia’s Energy Plan (SAVE Act), approved Washington Gas’ initial SAVE Plan for accelerated replacement of infrastructure facilities and a SAVE Rider to recover eligible costs associated with those replacement programs. Subsequently, the Commission approved three amendments to Washington Gas’ SAVE Plan, increasing the overall investment, the scope of approved programs and new facilities replacement programs. Washington Gas’ approved SAVE Plan encompasses eight ongoing programs: (i) bare and/or unprotected steel service replacement program, (ii) bare and unprotected steel main replacement program, (iii) mechanically coupled pipe replacement, (iv) copper services replacement program, (v) black plastic services replacement program, (vi) cast iron mains replacement program, (vii) meter set and piping remediation/replacement program and (viii) transmission programs. Washington Gas was authorized to invest US$256 million, including cost of removal, over the five-year calendar period through 2017. In November 2017, the Commission approved Washington Gas’ application to amend and extend its SAVE Plan (SAVE 2.0). SAVE 2.0 authorizes Washington Gas to invest approximately US$500 million over a five-year period, to continue work on both previously approved and new distribution and transmission system accelerated replacement programs.
Marquette Connector Pipeline
On August 23, 2017, the Michigan Public Service Commission (MPSC) approved SEMCO Gas’ application to construct, own, and operate the MCP. The MCP is a proposed new pipeline that will connect the Great Lakes Gas Transmission Pipeline to the Northern Natural Gas Pipeline in Marquette, Michigan, which will provide system redundancy and increase deliverability, reliability and diversity of supply to SEMCO Gas’ approximately 35,000 customers in Michigan’s Western Upper Peninsula.
The Company received approval for all environmental permits in September 2018 and the completed Archeological Assessment has been submitted to the state’s Historical Preservation Officer. It is expected that the construction bid package will be released to approximately ten contractors in late October 2018. Construction is expected to begin in 2019, with clearing and mobilization scheduled to begin in the first quarter of 2019 and an anticipated in-service date near the end of the fourth quarter of 2019.
New Customer Growth
The Utility business actively markets and adds new customers through both capital expenditures and different rate mechanisms aimed at bringing the benefits of natural gas, including lower energy bills and reduced carbon emissions, to more residents in its territories. In 2018, Washington Gas, SEMCO and ENSTAR expect new customer growth of 1.0 percent, 1.0 percent, and 1.1 percent, respectively, supported by additional capital and rate base. Adding new customers directly drives earnings growth through additional distribution revenues.
Power Projects
Distributed Generation Investments
WGL currently owns and manages distributed generation projects with approximately 325 MW of gross capacity across 20 states and the District of Columbia in the United States. The power output from these projects is generally contracted directly with end-user customers under long-term service agreements, providing clean energy solutions to a variety of commercial, government, institutional, and residential customers. For certain investments, WGL, along with its tax equity partners, has recently formed several tax equity funds to acquire, own, and operate distributed generation projects. These funds have invested
approximately US$207 million in distributed generation projects since 2016, of which WGL’s share was approximately US$133 million. WGL is the managing member of these funds and provided cash equal to the purchase price of the distributed generation projects less any contributions from the tax-equity partner for projects sold by WGL into the funds. WGL is the operations and maintenance provider, and was the developer of these projects.
One of the tax equity partnerships, SFGF II, LLC, is currently acquiring new solar projects. To date, SFGF II, LLC has invested a total of US$122 million in new projects since June 30, 2017 and there is US$28 million remaining for additional acquisitions through March 31, 2019. As of September 30, 2018, WGL has contributed US$47 million into SFGF II, LLC. The estimated total contribution by WGL to this fund is expected to be approximately US$95 million by the end of the commitment period.
On March 28, 2018, WGL entered into a new arrangement whereby WGL develops renewable solar projects after signing long-term power service agreements with customers and then sells the completed solar projects to a financing partner who will lease the project back to WGL, allowing the investor to retain the tax benefits of the projects. This optimizes the tax attributes associated with the projects, lowering the financing cost for WGL. WGL has until September 28, 2019 to sell the commercial distributed generation projects under the arrangement to the investor and it could lease each project back over a period of up to 25 years. The total value of these solar projects could be up to US$75 million, none of which has been committed to date.
The Company continues to consider additional energy storage and renewables opportunities.
NON-GAAP FINANCIAL MEASURES
This MD&A contains references to certain financial measures used by AltaGas that do not have a standardized meaning prescribed by GAAP and may not be comparable to similar measures presented by other entities. Readers are cautioned that these non-GAAP measures should not be construed as alternatives to other measures of financial performance calculated in accordance with GAAP. The non-GAAP measures and their reconciliation to GAAP financial measures are shown below. These non-GAAP measures provide additional information that management believes is meaningful in describing AltaGas’ operational performance, liquidity and capacity to fund dividends, capital expenditures, and other investing activities. The specific rationale for, and incremental information associated with, each non-GAAP measure is discussed below.
References to normalized EBITDA, normalized net income, normalized funds from operations, net debt, and net debt to total capitalization throughout this MD&A have the meanings as set out in this section.
Normalized EBITDA
|
| Three Months Ended |
| Nine Months Ended |
| ||||||||
($ millions) |
| 2018 |
| 2017 |
| 2018 |
| 2017 |
| ||||
Normalized EBITDA |
| $ | 226 |
| $ | 190 |
| $ | 615 |
| $ | 584 |
|
Add (deduct): |
|
|
|
|
|
|
|
|
| ||||
Transaction costs related to acquisitions |
| (35 | ) | (9 | ) | (52 | ) | (50 | ) | ||||
Merger commitment costs |
| (182 | ) | — |
| (182 | ) | — |
| ||||
Unrealized gains (losses) on risk management contracts |
| (9 | ) | (25 | ) | 13 |
| (47 | ) | ||||
Changes in fair value of natural gas optimization inventory |
| 3 |
| — |
| 3 |
| — |
| ||||
Non-controlling interest related to HLBV investments |
| (17 | ) | — |
| (17 | ) | — |
| ||||
Realized losses on foreign exchange derivatives |
| — |
| — |
| (36 | ) | — |
| ||||
Gains (losses) on investments |
| 15 |
| 5 |
| — |
| (3 | ) | ||||
Gains (losses) on sale of assets |
| — |
| — |
| 1 |
| (3 | ) | ||||
Provisions on assets |
| (698 | ) | — |
| (698 | ) | (1 | ) | ||||
Investment tax credits related to distributed generation assets |
| (2 | ) | — |
| (2 | ) | — |
| ||||
Accretion expenses |
| (3 | ) | (3 | ) | (8 | ) | (8 | ) | ||||
Foreign exchange gains |
| 3 |
| — |
| 4 |
| 2 |
| ||||
EBITDA |
| $ | (699 | ) | $ | 158 |
| $ | (359 | ) | $ | 474 |
|
Add (deduct): |
|
|
|
|
|
|
|
|
| ||||
Depreciation and amortization |
| (122 | ) | (69 | ) | (268 | ) | (211 | ) | ||||
Interest expense |
| (112 | ) | (40 | ) | (198 | ) | (127 | ) | ||||
Income tax recovery (expense) |
| 221 |
| (14 | ) | 200 |
| (43 | ) | ||||
Net income (loss) after taxes (GAAP financial measure) |
| $ | (712 | ) | $ | 35 |
| $ | (625 | ) | $ | 93 |
|
EBITDA is a measure of AltaGas’ operating profitability prior to how business activities are financed, assets are amortized, or earnings are taxed. EBITDA is calculated from the Consolidated Statements of Income using net income adjusted for pre-tax depreciation and amortization, interest expense, and income tax expense.
Normalized EBITDA includes additional adjustments for unrealized gains (losses) on risk management contracts, realized loss on foreign exchange derivatives, gains (losses) on investments, transaction costs related to acquisitions, merger commitment costs, gains (losses) on the sale of assets, provisions on assets, accretion expenses related to asset retirement obligations and the Northwest Transmission Line liability, foreign exchange gains, distributed generation asset related investment tax credits, non-controlling interest of certain investments to which Hypothetical Liquidation at Book Value (HLBV) accounting is applied, and changes in fair value of natural gas optimization inventory. AltaGas presents normalized EBITDA as a supplemental measure. Normalized EBITDA is frequently used by analysts and investors in the evaluation of entities within the industry as it excludes items that can vary substantially between entities depending on the accounting policies chosen, the book value of assets and the capital structure.
Normalized Net Income (Loss)
|
| Three Months Ended |
| Nine Months Ended |
| ||||||||
($ millions) |
| 2018 |
| 2017 |
| 2018 |
| 2017 |
| ||||
Normalized net income (loss) |
| $ | (17 | ) | $ | 48 |
| $ | 76 |
| $ | 141 |
|
Add (deduct) after-tax: |
|
|
|
|
|
|
|
|
| ||||
Transaction costs related to acquisitions |
| (26 | ) | (9 | ) | (41 | ) | (39 | ) | ||||
Merger commitment costs |
| (135 | ) | — |
| (135 | ) | — |
| ||||
Unrealized gains (losses) on risk management contracts |
| (23 | ) | (22 | ) | 3 |
| (43 | ) | ||||
Changes in fair value of natural gas optimization inventory |
| 3 |
| — |
| 3 |
| — |
| ||||
Realized gain (loss) on foreign exchange derivatives |
| 1 |
| — |
| (35 | ) | — |
| ||||
Gains (losses) on investments |
| 22 |
| 5 |
| 9 |
| (3) |
| ||||
Gains (losses) on sale of assets |
| — |
| — |
| 1 |
| (3) |
| ||||
Provisions on assets |
| (539 | ) | — |
| (539 | ) | (1) |
| ||||
Financing costs associated with the bridge facility |
| (12 | ) | (4 | ) | (18 | ) | (11 | ) | ||||
Net income (loss) applicable to common shares (GAAP financial measure) |
| $ | (726 | ) | $ | 18 |
| $ | (676 | ) | $ | 41 |
|
Normalized net income (loss) represents net income (loss) applicable to common shares adjusted for the after-tax impact of unrealized gains (losses) on risk management contracts, realized gain (loss) on foreign exchange derivatives, gains (losses) on investments, transaction costs related to acquisitions, gains (losses) on the sale of assets, provisions on assets, financing costs associated with the bridge facility for the WGL Acquisition, and changes in fair value of natural gas optimization inventory. This measure is presented in order to enhance the comparability of AltaGas’ earnings, as it reflects the underlying performance of AltaGas’ business activities.
Normalized Funds from Operations
|
| Three Months Ended |
| Nine Months Ended |
| ||||||||
($ millions) |
| 2018 |
| 2017 |
| 2018 |
| 2017 |
| ||||
Normalized funds from operations |
| $ | 117 |
| $ | 143 |
| $ | 407 |
| $ | 436 |
|
Add (deduct): |
|
|
|
|
|
|
|
|
| ||||
Transaction and financing costs related to acquisitions |
| (36 | ) | (12 | ) | (56 | ) | (54 | ) | ||||
Merger commitment costs |
| (182 | ) | — |
| (182 | ) | — |
| ||||
Funds from operations |
| (101 | ) | 131 |
| 169 |
| 382 |
| ||||
Add (deduct): |
|
|
|
|
|
|
|
|
| ||||
Net change in operating assets and liabilities |
| (253 | ) | (43 | ) | (185 | ) | 12 |
| ||||
Asset retirement obligations settled |
| (1 | ) | — |
| (2 | ) | (3 | ) | ||||
Cash from (used by) operations (GAAP financial measure) |
| $ | (355 | ) | $ | 88 |
| $ | (18 | ) | $ | 391 |
|
Normalized funds from operations is used to assist management and investors in analyzing the liquidity of the Corporation without regard to changes in operating assets and liabilities in the period and non-operating related expenses (net of current taxes) such as transaction and financing costs related to acquisitions.
Funds from operations are calculated from the Consolidated Statement of Cash Flows and are defined as cash from operations before net changes in operating assets and liabilities and expenditures incurred to settle asset retirement obligations. Management uses this measure to understand the ability to generate funds for capital investments, debt repayment, dividend payments and other investing activities.
Funds from operations and normalized funds from operations as presented should not be viewed as an alternative to cash from operations or other cash flow measures calculated in accordance with GAAP.
Net Debt and Net Debt to Total Capitalization
Net debt and net debt to total capitalization are used by the Corporation to monitor its capital structure and financing requirements. It is also used as a measure of the Corporation’s overall financial strength. Net debt is defined as short-term debt, plus current and long-term portions of long-term debt, less cash and cash equivalents. Total capitalization is defined as net debt plus shareholders’ equity and non-controlling interests. Additional information regarding these non-GAAP measures can be found under the section Capital Resources of this MD&A.
RESULTS OF OPERATIONS BY REPORTING SEGMENT
Normalized EBITDA (1)
|
| Three Months Ended |
| Nine Months Ended |
| ||||||||
($ millions) |
| 2018 |
| 2017 |
| 2018 |
| 2017 |
| ||||
Gas |
| $ | 65 |
| $ | 51 |
| $ | 184 |
| $ | 159 |
|
Power |
| 128 |
| 106 |
| 245 |
| 232 |
| ||||
Utilities |
| 32 |
| 38 |
| 194 |
| 208 |
| ||||
Sub-total: Operating Segments |
| 225 |
| 195 |
| 623 |
| 599 |
| ||||
Corporate |
| 1 |
| (5 | ) | (8 | ) | (15 | ) | ||||
|
| $ | 226 |
| $ | 190 |
| $ | 615 |
| $ | 584 |
|
(1) Non-GAAP financial measure; See discussion in Non-GAAP Financial Measures section of this MD&A.
GAS
OPERATING STATISTICS
|
| Three Months Ended |
| Nine Months Ended |
| ||||
|
| 2018 |
| 2017 |
| 2018 |
| 2017 |
|
Extraction inlet gas processed (Mmcf/d)(1) |
| 871 |
| 946 |
| 905 |
| 966 |
|
FG&P inlet gas processed (Mmcf/d)(1) |
| 462 |
| 376 |
| 462 |
| 375 |
|
Total inlet gas processed (Mmcf/d)(1) |
| 1,333 |
| 1,322 |
| 1,367 |
| 1,341 |
|
Extraction ethane volumes (Bbls/d)(1) |
| 24,204 |
| 27,229 |
| 23,974 |
| 27,954 |
|
Extraction NGL volumes (Bbls/d)(1) (2) |
| 36,741 |
| 36,797 |
| 37,810 |
| 36,390 |
|
Total extraction volumes (Bbls/d)(1) (3) |
| 60,945 |
| 64,026 |
| 61,784 |
| 64,344 |
|
Frac spread - realized ($/Bbl)(1) (4) |
| 15.60 |
| 14.96 |
| 16.42 |
| 11.61 |
|
Frac spread - average spot price ($/Bbl)(1) (5) |
| 25.87 |
| 21.28 |
| 23.09 |
| 16.54 |
|
Natural gas optimization inventory (Bcf) |
| 36.7 |
| 2.6 |
| 36.7 |
| 2.6 |
|
WGL retail energy marketing - gas sales volumes (Mmcf) |
| 8,155 |
| — |
| 8,155 |
| — |
|
(1) Average for the period.
(2) NGL volumes refer to propane, butane, and condensate.
(3) Includes Harmattan NGL processed on behalf of customers.
(4) 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.
(5) 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, divided by the respective frac exposed volumes for the period.
Inlet gas volumes processed at the extraction facilities for the three months ended September 30, 2018 decreased by 75 Mmcf/d, compared to the same period in 2017. The decrease was primarily due to reduced ownership at Younger effective April 2018, partially offset by higher inlet volumes at the Joffre Ethane Extraction Plant (JEEP) due to higher available gas flows. Inlet gas volumes processed at the field gathering and processing (FG&P) facilities for the three months ended September 30, 2018 increased by 86 Mmcf/d primarily due to volumes received at Townsend and the newly constructed Townsend 2A facilities, partially offset by the disposition of certain non-core facilities in the first quarter of 2018.
Inlet gas volumes processed at the extraction facilities for the nine months ended September 30, 2018 decreased by 61 Mmcf/d, compared to the same period in 2017. The decrease was mainly due to reduced ownership at Younger effective April 2018, partially offset by higher inlet volumes at JEEP and Edmonton Ethane Extraction Plant (EEEP) due to higher available gas flows. Inlet gas volumes processed at the FG&P facilities for the nine months ended September 30, 2018 increased by 87 Mmcf/d primarily due to volumes received at the Townsend and the newly constructed Townsend 2A facilities, and higher volumes at Gordondale, partially offset by the disposition of certain non-core assets in the first quarter of 2018.
Average ethane volumes for the three months ended September 30, 2018 decreased by 3,025 Bbls/d, while average NGL volumes were comparable to the same period in 2017. Lower ethane volumes were as a result of rejecting production at Younger due to uneconomic pricing, partially offset by higher ethane production at PEEP, EEEP and JEEP.
Average ethane volumes for the nine months ended September 30, 2018 decreased by 3,980 Bbls/d compared to the same period in 2017. Lower ethane volumes were primarily due to rejecting production due to uneconomic pricing at Younger in the second and third quarters of 2018 and at PEEP in the first quarter of 2018, and lower ethane volumes at Harmattan due to a planned turnaround in the second quarter, partially offset by higher production at EEEP. Average NGL volumes increased by 1,420 Bbls/d compared to the same period in 2017. Higher NGL volumes were primarily due to increased volumes produced at the Townsend and the newly constructed Townsend 2A facilities, Gordondale, and EEEP facilities, partially offset by the planned turnaround at Harmattan and reduced ownership at Younger.
With the addition of WGL, for the period from transaction close to September 30, 2018, U.S. retail sales volumes were 8,155 Mmcf.
Three Months Ended September 30
The Gas segment reported normalized EBITDA of $65 million in the third quarter of 2018, compared to $51 million in the same quarter of 2017. The increase was mainly due to contributions to normalized EBITDA from WGL for the period after transaction close on July 6, 2018, contributions from the Townsend 2A and North Pine facilities which commenced commercial operations in the fourth quarter of 2017, higher revenues at Harmattan due to increased NGL activities, and higher realized frac spreads and frac exposed volumes, partially offset by the impact of reduced ownership at Younger. During the third quarter of 2018, AltaGas recorded equity earnings of $2 million from Petrogas, compared to $6 million in the same quarter of 2017. The decrease in equity earnings from Petrogas was mainly due to unrealized mark to market losses on hedges.
During the third quarter of 2018, AltaGas recognized pre-tax provisions of $152 million in the Gas segment. Of this, $115 million was related to certain non-core midstream assets classified as held for sale during the quarter. As a result of the pending sale, AltaGas is focusing on its core Gas operating assets and recognized an additional pre-tax impairment of $37 million related to other shut-in assets in the South, Cold Lake and Northwest operating areas.
During the third quarter of 2018, AltaGas hedged approximately 7,500 Bbls/d of NGL volumes at an average price of $33/Bbl excluding basis differentials. During the third quarter of 2017, AltaGas hedged 5,800 Bbls/d of NGL at an average price of $23/Bbl, excluding basis differentials. The average indicative spot NGL frac spread in the third quarter of 2018 was approximately $26/Bbl, compared to $21/Bbl in the third quarter of 2017. The realized frac spread of approximately $16/Bbl in the third quarter of 2018 (2017 - $15/Bbl) was higher than the same quarter in 2017 due to improved commodity prices.
On August 27, 2018, AltaGas announced that it entered into definitive agreements with Kelt Exploration (LNG) Ltd. (Kelt) to provide an energy infrastructure solution for the liquids-rich Inga Montney development located in British Columbia. This underpins the expansion of AltaGas’ Townsend complex including the addition of a 198 MMcf per day C3+ deep cut gas processing facility and provides Kelt with firm processing of 75 MMcf per day of raw gas under an initial 10 year take-or-pay agreement.
On September 26, 2018, AltaGas announced that it entered into a definitive agreement with Black Swan to acquire 50 percent ownership in certain existing and future natural gas processing plants of Black Swan. AltaGas and Black Swan will also enter into long term processing, transportation and marketing agreements that include new AltaGas liquids handling infrastructure, strengthening AltaGas’ Northeast British Columbia value proposition and connecting producers with additional options for energy exports. The total capital investment by AltaGas is expected to be approximately $230 million and the transaction closed on October 2, 2018.
In the third quarter of 2018, as part of the agreement for the sale of non-core midstream and power assets in Canada, AltaGas sold 43.7 million shares of Tidewater Midstream and Infrastructure Inc. The sale of the Tidewater shares was completed in September 2018. For the three months ended September 30, 2018, unrealized gains of $11 million were partially offset by a realized loss of $2 million relating to the sale of these shares.
Nine Months Ended September 30
The Gas segment reported normalized EBITDA of $184 million in the first nine months of 2018, compared to $159 million in the same period of 2017. The increase was mainly due to higher realized frac spread and frac exposed volumes, contributions from the North Pine and Townsend 2A facilities which commenced commercial operations in the fourth quarter of 2017, contributions from WGL for the period after transaction close on July 6, 2018, higher operating cost recoveries at Harmattan, and a one-time payment related to the change in operatorship of Younger, partially offset by lower natural gas storage margins, the impact of the sale of the EDS and JFP transmission assets in the first quarter of 2017, the planned turnaround at the Harmattan facility and lower rates at Blair Creek due to contractual arrangements with producers. During the nine months ended September 30, 2018, AltaGas recorded equity earnings of $13 million from Petrogas, compared to $19 million in the same period in 2017. The
decrease in Petrogas earnings was due to a planned turnaround at the Ferndale Terminal in the first quarter of 2018 and unrealized mark to market losses on hedges.
During the nine months ended September 30, 2018 AltaGas recognized a pre-tax provision of $115 million on certain non-core midstream assets classified as held for sale, a pre-tax impairment of $37 million related to shut-in assets in the South, Cold Lake and Northwest operating areas, and a pre-tax gain of $1 million on the sale of a non-core gas processing facility, while in the same period of 2017, AltaGas recognized a pre-tax loss of $3 million on the sale of the EDS and JFP transmission assets.
During the nine months ended September 30, 2018, AltaGas hedged approximately 7,500 Bbls/d of NGL volumes at an average price of $33/Bbl, excluding basis differentials. During the nine months ended September 30, 2017, AltaGas hedged 5,500 Bbls/d of NGL at an average price of $23/Bbl, excluding basis differentials. The average indicative spot NGL frac spread for the nine months ended September 30, 2018 was approximately $23/Bbl compared to $17/Bbl in the same period of 2017. The realized frac spread of $16/Bbl in the nine months ended September 30, 2018 (2017 - $12/Bbl) was higher than the same period in 2017 due to improved commodity prices.
On April 3, 2018, AltaGas entered into a long-term natural gas processing arrangement (the Processing Arrangement) with Birchcliff Energy Ltd. (Birchcliff) at AltaGas’ deep-cut sour gas processing facility located in Gordondale, Alberta (the Gordondale Facility). Under the Processing Arrangement, Birchcliff is provided with up to 120 MMcf/d of natural gas processing on a firm-service basis, and Birchcliff’s take-or-pay obligation is 100 MMcf/d. The Processing Arrangement provides stable long-term cash flow by filling the existing operational capacity of 120 Mmcf/d at the Gordondale Facility and significantly enhances the potential to flow third-party volumes through the facility and to grow those volumes to bring the operating capacity up to 150 Mmcf/d. Growing propane volumes from Gordondale will be dedicated to RIPET as part of the commercial arrangements. The new Processing Arrangement was effective as of January 1, 2018 and replaces the parties’ existing Gordondale processing arrangement.
As mentioned above, in the third quarter of 2018, AltaGas sold 43.7 million shares of Tidewater Midstream and Infrastructure Inc. For the nine months ended September 30, 2018, an unrealized loss of $1 million and realized loss of $2 million was recorded relating to the sale of these shares.
POWER
OPERATING STATISTICS
|
| Three Months Ended |
| Nine Months Ended |
| ||||
|
| 2018 |
| 2017 |
| 2018 |
| 2017 |
|
Renewable power sold (GWh) |
| 690 |
| 681 |
| 1,318 |
| 1,328 |
|
Conventional power sold (GWh) |
| 1,255 |
| 992 |
| 2,739 |
| 1,785 |
|
Renewable capacity factor (%) |
| 44.6 |
| 70.3 |
| 36.6 |
| 43.5 |
|
Contracted conventional equivalent availability factor (%) (1) |
| 98.5 |
| 99.6 |
| 97.2 |
| 98.6 |
|
WGL retail energy marketing - electricity sales volumes (GWh) |
| 3,000 |
| — |
| 3,000 |
| — |
|
(1) 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.
During the three months ended September 30, 2018, the volume of renewable power sold increased by 9 GWh and the volume of conventional power sold increased by 263 GWh, compared to the same period in 2017. The increase in renewable volumes was due to the addition of WGL power generation for the period since transaction close, partially offset by unseasonably dry and cool weather at the Northwest Hydro facilities, as well as outages and derates at the Craven biomass facility (Craven). The significant increase in conventional volumes was due to increased run time at the San Joaquin Facilities and Blythe as a result of increased dispatch under the respective power purchase agreements and greater operational and fuel flexibility at Blythe.
The renewable capacity factor for the three months ended September 30, 2018 was lower as a result of unseasonably dry and cool weather at the Northwest Hydro facilities and the addition of WGL. The contracted conventional equivalent availability factor was lower for the three months ended September 30, 2018 as a result of unplanned outages at Blythe.
During the nine months ended September 30, 2018, the volume of renewable power sold decreased by 10 GWh and the volume of conventional power sold increased by 954 GWh, compared to the same period in 2017. The decrease in renewable volumes was due to lower generation at the Northwest Hydro facilities, lower generation at Craven, and lower wind generation at the Bear Mountain wind facility, partially offset by the addition of WGL power generation for the period since transaction close. The significant increase in conventional volumes was due to higher dispatch at Blythe due to greater operational and fuel flexibility.
The decreased renewable capacity factor for the nine months ended September 30, 2018 was due to the same factors impacting the quarter. The contracted conventional availability factor was lower for the nine months ended September 30, 2018 due to a longer planned outage and increased unplanned outages at Blythe.
With the addition of WGL, for the period from transaction close to September 30, 2018, U.S. retail sales volumes were 3,000 GWh.
Three Months Ended September 30
The Power segment reported normalized EBITDA of $128 million during the three months ended September 30, 2018, compared to $106 million in the same period of 2017. Normalized EBITDA increased as a result of the addition of WGL and the stronger U.S. dollar. This was partially offset by lower generation at the Northwest Hydro facilities due to unseasonably cool, dry weather and the expiry of the Ripon PPA on May 30, 2018 (partially offset by the new RA contract which began in the second quarter of 2018 and is in place until the end of 2018).
During the third quarter of 2018, AltaGas recognized pre-tax provisions of $352 million in the Power segment. The provisions are primarily related to assets classified as held for sale, including approximately $340 million for the Tracy, Hanford and Henrietta gas-fired power assets in California and $10 million for certain gas-fired peaking plants in Alberta to be sold to Birch Hill. In addition, a pre-tax provision of $2 million was recorded relating to the Pomona Repowering project.
Nine Months Ended September 30
The Power segment reported normalized EBITDA of $245 million for the nine months ended September 30, 2018, compared to $232 million in the same period of 2017. Normalized EBITDA increased as a result of the addition of WGL and higher energy sales at the Pomona battery facility, partially offset by the expiry of the Ripon PPA on May 30, 2018, expenses related to outages at Blythe, lower contributions from Craven due to unplanned outages and lower contract terms, and lower 2018 river flows and higher operating costs at the Northwest Hydro facilities due to minor repair work completed during the planned outage.
On June 22, 2018, the Power segment closed the sale of a 35 percent indirect equity interest in the Northwest Hydro facilities for cash proceeds of approximately $922 million. The sale of the minority interest in the Northwest Hydro facilities is to a joint venture company that is indirectly owned by Axium Infrastructure Inc., as manager of Axium Infrastructure Canada II Limited Partnership, and Manulife Financial Corporation. AltaGas remains the majority holder of the Northwest Hydro facilities and will continue to provide all operational, maintenance and management functions. AltaGas will continue to consolidate the entities that hold the Northwest Hydro facilities.
In the second quarter of 2017, the Power segment disposed of certain non-core development stage wind assets in Alberta for proceeds of approximately $1 million, resulting in a pre-tax gain on disposition of approximately $1 million. This was largely offset by a pre-tax provision of $1 million taken on certain non-core development stage gas-fired peaking assets in Alberta.
For the nine months ended September 30, 2018, the Power segment was also impacted by the previously mentioned provisions recorded in the third quarter of 2018.
UTILITIES
OPERATING STATISTICS
|
| Three Months Ended |
| Nine Months Ended |
| ||||
|
| 2018 |
| 2017 |
| 2018 |
| 2017 |
|
Canadian utilities |
|
|
|
|
|
|
|
|
|
Natural gas deliveries - end-use (PJ)(1) |
| 3.5 |
| 3.7 |
| 23.2 |
| 22.1 |
|
Natural gas deliveries - transportation (PJ)(1) |
| 1.1 |
| 1.3 |
| 4.3 |
| 4.7 |
|
U.S. utilities |
|
|
|
|
|
|
|
|
|
Natural gas deliveries - end-use (Bcf)(1) |
| 10.9 |
| 5.9 |
| 53.9 |
| 46.5 |
|
Natural gas deliveries - transportation (Bcf)(1) |
| 25.7 |
| 10.9 |
| 50.7 |
| 37.8 |
|
Service sites (2) |
| 1,759,154 |
| 575,602 |
| 1,759,154 |
| 575,602 |
|
Degree day variance from normal - AUI (%) (3) |
| 80.0 |
| (16.9 | ) | 13.5 |
| (4.2 | ) |
Degree day variance from normal - Heritage Gas (%) (3) |
| (16.5 | ) | (20.4 | ) | (4.6 | ) | (3.4 | ) |
Degree day variance from normal - SEMCO Gas (%) (4) |
| (17.8 | ) | 5.7 |
| 4.6 |
| (10.7 | ) |
Degree day variance from normal - ENSTAR (%) (4) |
| (31.2 | ) | (16.6 | ) | (6.9 | ) | 2.2 |
|
Degree day variance from normal - Washington Gas (%) (4) (5) |
| (4.1 | ) | — |
| (4.1 | ) | — |
|
(1) Petajoule (PJ) is one million gigajoules. Bcf is one billion cubic feet.
(2) Service sites reflect all of the service sites of AUI, PNG, Heritage Gas and U.S. utilities, including transportation and non-regulated business lines.
(3) 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 BCUC has approved a rate stabilization mechanism for its residential and small commercial customers.
(4) 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 Gas, during the prior 10 years for ENSTAR, and during the prior 30 years for Washington Gas.
(5) In certain of Washington Gas’ jurisdictions (Virginia and Maryland) there are billing mechanisms in place which are designed to eliminate the effects of variance in customer usage caused by weather and other factors such as conservation. In the District of Columbia, there is no weather normalization billing mechanism nor does it hedge to offset the effects of weather. As a result, colder or warmer weather will result in variances to financial results.
During the third quarter of 2018, AltaGas’ Utilities segment experienced colder weather compared to the same quarter of 2017 for AUI and SEMCO. Overall colder weather resulted in increased natural gas deliveries to end-use and transportation customers in the U.S. The 2018 increase in end-use and transportation represents the addition of WGL natural gas deliveries.
During the nine months ended September 30, 2018, AltaGas’ Utilities segment experienced colder weather compared to the same period in 2017. This was mainly driven by 5 percent colder than normal weather at SEMCO and 13 percent colder than normal weather at AUI, partially offset by 5 percent warmer than normal weather at Heritage Gas and 7 percent warmer than normal weather at ENSTAR. Overall colder weather resulted in increased natural gas deliveries to end-use customers in both Canada and the U.S. The 2018 increase in end-use and transportation represents the addition of WGL natural gas deliveries.
Service sites increased by approximately 1.2 million sites for the third quarter of 2018 compared to the same period in 2017 due to the addition of WGL customers and growth in customer base.
Three Months Ended September 30
The Utilities segment reported normalized EBITDA of $32 million during the three months ended September 30, 2018, compared to $38 million in the same quarter of 2017. The decrease was mainly due to the impact of the WGL Acquisition for the period after transaction close, and the 2018 revenue impact related to the federal tax reduction at the U.S. utilities, partially offset by higher rates, colder weather in Alberta, and the favourable impact of the stronger U.S. dollar.
Nine Months Ended September 30
The Utilities segment reported normalized EBITDA of $194 million during the nine months ended September 30, 2018, compared to $208 million in the same period of 2017. The decrease was mainly due to the 2018 revenue impact related to the
federal tax reduction at the U.S. utilities, one-time impacts in 2017 related to insurance proceeds received by SEMCO’s non-regulated operations of approximately $2 million and an early termination payment of approximately $2 million from one of SEMCO’s non-regulated customers moving from a fixed fee to a volumetric based contract, the impact of the WGL Acquisition closing on July 6, 2018, and the impact of the stronger Canadian dollar. Also contributing to the decrease is lower customer usage at AUI and warmer weather in Nova Scotia and Alaska. The decrease was partially offset by colder weather in Michigan and Alberta, higher rates, and growth in customer base.
Rate Cases
On May 15, 2018, Washington Gas filed an application with the PSC of MD to increase its base rates for natural gas service, generating approximately US$41 million of additional revenue. The revenue increase includes an increase in base rates of approximately US$56 million partially offset by a reduction of approximately US$15 million in annual surcharges currently paid by customers for system upgrades. Rebuttal testimony was filed in September 2018 and the hearings took place in September and October 2018 with a PSC of MD decision expected in December 2018.
On June 15, 2018, Washington Gas filed an application with the PSC of MD for approval of the second phase of its accelerated natural gas pipeline initiative. The application asks for approval of approximately US$394 million in accelerated infrastructure replacements for the 2019 to 2023 period. Rebuttal testimony was filed in September 2018. The hearings took place in September 2018, with a PSC of MD decision expected in December 2018.
On July 31, 2018, Washington Gas filed an application with the SCC of VA to increase its base rates for natural gas service. This base rate increase, if granted, would be approximately US$38 million, of which approximately US$15 million relates to costs being collected through the monthly SAVE surcharges for accelerated pipeline replacement. The new interim rates are effective January 2019. Hearings are scheduled for April 2019 with a decision expected in the first half of 2019.
On August 31, 2018, Washington Gas filed the 2019 SAVE capital expenditure application with the SCC of VA seeking approval for approximately US$70 million of SAVE capital expenditures in 2019. The decision is dependent on the procedural schedule from the SCC of VA.
For the Cook Inlet Natural Gas Storage Alaska LLC (CINGSA) advanced ruling on a redundancy project filed in April 2018 for approximately US$41 million of capital expenditures and an annual revenue requirement of approximately US$6 million, reply testimony was filed in September 2018. The hearing occurred in October 2018 with a decision expected in January 2019.
The CINGSA rate case was filed in April, 2018 based on a 2017 historical test year, reducing rates by US$4 million due to reducing rate base, lower returns on equity (ROE) and lower federal income tax. The rate case hearing is scheduled for April 2019 with a decision expected in July 2019.
CORPORATE
Three Months Ended September 30
In the Corporate segment, normalized EBITDA for the third quarter of 2018 was income of $1 million, compared to a loss of $5 million in the same quarter of 2017. The increase was mainly due to additional interest income earned on funds that were held in escrow for the WGL Acquisition, partially offset by increases to information technology related costs.
Nine Months Ended September 30
In the Corporate segment, normalized EBITDA for the nine months ended September 30, 2018 was a loss of $8 million, compared to a loss of $15 million in the same period of 2017. The decrease is mainly due to additional interest income earned on funds that were held in escrow for the WGL Acquisition, partially offset by increases to professional and consulting fees and information technology related costs.
INVESTED CAPITAL
|
| Three Months Ended |
| |||||||||||||
($ millions) |
| Gas |
| Power |
| Utilities |
| Corporate |
| Total |
| |||||
Invested capital: |
|
|
|
|
|
|
|
|
|
|
| |||||
Property, plant and equipment |
| $ | 60 |
| $ | 47 |
| $ | 259 |
| $ | 1 |
| $ | 367 |
|
Intangible assets |
| 1 |
| 11 |
| 3 |
| 1 |
| 16 |
| |||||
Long-term investments |
| 59 |
| — |
| — |
| — |
| 59 |
| |||||
Business acquisition |
| 1,525 |
| 892 |
| 4,682 |
| (1,168 | ) | 5,931 |
| |||||
Contributions from non-controlling interest |
| (12 | ) | — |
| — |
| — |
| (12 | ) | |||||
Invested capital |
| 1,633 |
| 950 |
| 4,944 |
| (1,166 | ) | 6,361 |
| |||||
Disposals: |
|
|
|
|
|
|
|
|
|
|
| |||||
Property, plant and equipment |
| — |
| — |
| — |
| — |
| — |
| |||||
Net invested capital |
| $ | 1,633 |
| $ | 950 |
| $ | 4,944 |
| $ | (1,166 | ) | $ | 6,361 |
|
|
| Three Months Ended |
| |||||||||||||
($ millions) |
| Gas |
| Power |
| Utilities |
| Corporate |
| Total |
| |||||
Invested capital: |
|
|
|
|
|
|
|
|
|
|
| |||||
Property, plant and equipment |
| $ | 113 |
| $ | 1 |
| $ | 32 |
| $ | 1 |
| $ | 147 |
|
Intangible assets |
| — |
| 11 |
| — |
| — |
| 11 |
| |||||
Long-term investments |
| 3 |
| — |
| — |
| — |
| 3 |
| |||||
Contributions from non-controlling interest |
| (6 | ) | — |
| — |
| — |
| (6 | ) | |||||
Invested capital |
| 110 |
| 12 |
| 32 |
| 1 |
| 155 |
| |||||
Disposals: |
|
|
|
|
|
|
|
|
|
|
| |||||
Property, plant and equipment |
| — |
| — |
| — |
| — |
| — |
| |||||
Net invested capital |
| $ | 110 |
| $ | 12 |
| $ | 32 |
| $ | 1 |
| $ | 155 |
|
During the third quarter of 2018, AltaGas’ invested capital was $6.4 billion, compared to $155 million in the same quarter of 2017. The increase in invested capital was primarily due to cash paid on the WGL Acquisition of $5.9 billion, higher additions to property, plant and equipment, and contributions to WGL’s investments in Central Penn and Mountain Valley, partially offset by higher contributions from non-controlling interest (representing Vopak’s share of construction costs related to RIPET).
The increase in additions to property, plant and equipment in the third quarter of 2018 was mainly due to capital expenditures related to system betterment and accelerated pipeline replacement programs at Washington Gas, construction costs at RIPET and capital expenditures related to WGL’s distributed generation projects.
The invested capital in the third quarter of 2018 included maintenance capital of $3 million (2017 - $6 million) in the Gas segment and $2 million (2017 - $1 million) in the Power segment. The decrease in maintenance capital for the Gas segment was primarily due to reduced turnaround expenditures in the third quarter. The increase in maintenance capital for the Power segment was primarily due to maintenance at the Northwest Hydro facilities.
|
| Nine Months Ended |
| |||||||||||||
($ millions) |
| Gas |
| Power |
| Utilities |
| Corporate |
| Total |
| |||||
Invested capital: |
|
|
|
|
|
|
|
|
|
|
| |||||
Property, plant and equipment |
| $ | 175 |
| $ | 59 |
| $ | 330 |
| $ | 2 |
| $ | 566 |
|
Intangible assets |
| 4 |
| 12 |
| 4 |
| 3 |
| 23 |
| |||||
Long-term investments |
| 78 |
| — |
| — |
| — |
| 78 |
| |||||
Business acquisition |
| 1,525 |
| 892 |
| 4,682 |
| (1,168 | ) | 5,931 |
| |||||
Contributions from non-controlling interest |
| (35 | ) | — |
| — |
| — |
| (35 | ) | |||||
Invested capital |
| 1,747 |
| 963 |
| 5,016 |
| (1,163 | ) | 6,563 |
| |||||
Disposals: |
|
|
|
|
|
|
|
|
|
|
| |||||
Property, plant and equipment |
| (8 | ) | (2 | ) | — |
| — |
| (10 | ) | |||||
Net invested capital |
| $ | 1,739 |
| $ | 961 |
| $ | 5,016 |
| $ | (1,163 | ) | $ | 6,553 |
|
|
| Nine Months Ended |
| |||||||||||||
($ millions) |
| Gas |
| Power |
| Utilities |
| Corporate |
| Total |
| |||||
Invested capital: |
|
|
|
|
|
|
|
|
|
|
| |||||
Property, plant and equipment |
| $ | 247 |
| $ | 16 |
| $ | 80 |
| $ | 1 |
| $ | 344 |
|
Intangible assets |
| 1 |
| 13 |
| 1 |
| 2 |
| 17 |
| |||||
Long-term investments |
| 17 |
| — |
| — |
| — |
| 17 |
| |||||
Contributions from non-controlling interest |
| (12 | ) | — |
| — |
| — |
| (12 | ) | |||||
Invested capital |
| 253 |
| 29 |
| 81 |
| 3 |
| 366 |
| |||||
Disposals: |
|
|
|
|
|
|
|
|
|
|
| |||||
Property, plant and equipment |
| (67 | ) | (2 | ) | (1 | ) | — |
| (70 | ) | |||||
Net invested capital |
| $ | 186 |
| $ | 27 |
| $ | 80 |
| $ | 3 |
| $ | 296 |
|
During the first nine months of 2018, AltaGas’ invested capital was $6.6 billion, compared to $366 million in the same period of 2017. The increase in invested capital in the first nine months of 2018 was mainly due to the same factors impacting the third quarter of 2018 as well as higher contributions to AIJVLP. The increase in additions to property, plant and equipment in the first nine months of 2018 was also due to the same factors impacting the third quarter of 2018, as well as the purchase of an office building at SEMCO. The disposals of property, plant and equipment in the first nine months of 2018 primarily related to non-core facilities in the Gas segment and a development stage wind asset in the Power segment, while in the first nine months of 2017 the disposals of property, plant and equipment related to the sale of the EDS and JFP transmission assets.
The invested capital for the nine months ended September 30, 2018 included maintenance capital of $16 million (2017 - $8 million) in the Gas segment and $12 million (2017 - $7 million) in the Power segment. The increase in maintenance capital for the first nine months of 2018 for the Gas segment was primarily due to a planned turnaround at Harmattan in the second quarter of 2018, and in the Power segment was due to costs of approximately $5 million incurred during a planned outage at the Northwest Hydro facilities in the second quarter of 2018.
RISK MANAGEMENT
AltaGas is exposed to various market risks in the normal course of operations that could impact earnings and cash flows. AltaGas enters into physical and financial derivative contracts to manage exposure to fluctuations in commodity prices and foreign exchange rates, as well as to optimize certain owned and managed natural gas assets. The Board of Directors of AltaGas has established a risk management policy for the Corporation establishing AltaGas’ risk management control framework. Derivative instruments are governed under, and subject to, this policy. In the third quarter of 2018, AltaGas implemented a new system that is designed to manage and provide additional work flow controls for the marketing and risk management processes for the NGL business. As at September 30, 2018 and December 31, 2017, the fair values of the Corporation’s derivatives were as follows:
($ millions) |
| September 30, |
| December 31, |
| ||
Natural gas |
| $ | (128 | ) | $ | 6 |
|
NGL frac spread |
| (29 | ) | (24 | ) | ||
Power |
| — |
| (1 | ) | ||
Foreign exchange |
| — |
| 2 |
| ||
Net derivative liability |
| $ | (157 | ) | $ | (17 | ) |
Commodity Price Contracts
The Corporation executes gas, power, and other physical and financial commodity contracts to serve its customers as well as manage and optimize its asset portfolio. A portion of these physical contracts are not recorded at fair value because they are either i) designated as “normal purchases and normal sales”, ii) do not qualify as derivative instruments due to the significance of their notional amount relative to the applicable liquid markets, or iii) are weather derivatives, which are not exchanged or traded and the underlying variables relate to a climactic, geological or other physical variable. The fair value of power, natural gas, and NGL contracts that qualify as derivatives was calculated using estimated forward prices based on published sources for the relevant period. AltaGas has not elected hedge accounting for any of its derivative contracts currently in place. For AltaGas’ Gas and Power segments, changes in the fair value of these derivative contracts are recorded in the Consolidated Statements of Income in the period in which the change occurs. For the Utility segment, changes in the fair value of derivative instruments recoverable or refundable to customers are recorded to regulatory assets or regulatory liabilities on the Consolidated Balance Sheets, while changes in the fair value of derivative instruments not affected by rate regulation are recorded in the Consolidated Statements of Income in the period in which the change occurs.
The Power segment has various fixed-for-floating power purchase and sale contracts in the Alberta market, which are expected to be settled over the next five years. Additionally, to serve retail electric customers, AltaGas enters into both physical and financial contracts for the purchase and sale of electricity.
The Gas segment also executes fixed-for-floating NGL frac spread swaps to manage exposure to frac spreads as the financial results of several extraction plants are affected by fluctuations in NGL frac spreads. The average indicative spot NGL frac spread for the nine months ended September 30, 2018 was approximately $23/Bbl (2017 — $17/Bbl), inclusive of basis differentials. The average NGL frac spread realized by AltaGas (based on average spot price and realized hedge price inclusive of basis differentials) for the nine months ended September 30, 2018 was approximately $16/Bbl inclusive of basis differentials (2017 - $12/Bbl). For the remainder of 2018, AltaGas currently has frac hedges in place to hedge approximately 7,500 Bbls/d at an average price of $33/Bbl, excluding basis differentials. AltaGas also entered into frac hedges to hedge approximately 6,228 Bbls/d at an average price of approximately $30/Bbl, excluding basis differentials, for calendar year 2019. Additionally, AltaGas uses physical and financial derivatives for the purchase and sale of natural gas in order to optimize owned storage and transportation capacity as well as managed transportation and storage assets on behalf of third parties. To serve retail gas customers, AltaGas enters into retail sales contracts that contain optionality as well as physical and financial contracts which qualify as derivative instruments.
The Utility segment enters into hedging contracts and other contracts that may qualify as derivative instruments related to the purchase of natural gas to manage price risk for its ratepayers. Additionally, Washington Gas executes commodity-related physical and financial contracts in the form of forward, futures, and option contracts as part of an asset optimization program. Under this program, Washington Gas realizes value from its long-term natural gas transportation and storage capacity resources when they are not being fully used to serve utility customers.
Foreign Exchange
AltaGas has foreign operations whereby the functional currency is the U.S. dollar. As a result, the Corporation’s earnings, cash flows, and other comprehensive income 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 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 September 30, 2018, management has designated US$2.4 billion of outstanding U.S. dollar denominated long-term debt to hedge against the currency translation effect of its foreign investments (December 31, 2017 - $nil). This designation has the effect of mitigating volatility on net income by offsetting foreign exchange gains and losses on U.S. dollar denominated long-term debt and foreign net investment. For the three and nine months ended September 30, 2018, AltaGas incurred after-tax unrealized gains of $37 million arising from the translation of debt in other comprehensive income (three and nine months ended September 30, 2017 - after-tax unrealized gains of $nil and $7 million, respectively).
To mitigate the foreign exchange risks associated with the cash purchase price of WGL, AltaGas entered into foreign currency option contracts with an aggregate notional value of approximately US$1.2 billion which expired in May 2018. These foreign currency option contracts did not qualify for hedge accounting. Therefore, all changes in fair value were recognized in net income. For the three and nine months ended September 30, 2018, unrealized gains of $nil and $35 million, respectively, and a realized loss of $nil and $36 million, respectively, were recognized in revenue in relation to these contracts (2017 - unrealized losses of $10 million and $32 million, respectively). In the second quarter of 2018, AltaGas entered into foreign exchange forward contracts with an aggregate notional value of $3.2 billion intended to minimize the foreign exchange risk of the WGL Acquisition, which settled in the third quarter of 2018. These foreign exchange derivatives did not qualify for hedge accounting. Therefore, all changes in fair value were recognized in net income. For the three and nine months ended September 30, 2018, unrealized losses of $2 million and $nil, respectively, and a realized gain of $1 million were recognized in income in relation to these forward contracts (2017 - $nil).
Weather
WGL Energy Services utilizes heating degree day (HDD) instruments from time to time to manage weather and price risks related to its natural gas and electricity sales during the winter heating season. WGL Energy Services also utilizes cooling degree day (CDD) instruments and other instruments to manage weather and price risks related to its electricity sales during the summer cooling season. These instruments cover a portion of estimated revenue or energy-related cost exposure to variations in HDDs or CDDs. For the period from close of the WGL Acquisition to September 30, 2018, pre-tax losses of $1 million were recorded related to these instruments (2017 - $nil).
The Effects of Derivative Instruments on the Consolidated Statements of Income
The following table presents the unrealized gains (losses) on derivative instruments as recorded in the Corporation’s Consolidated Statements of Income:
|
| Three Months Ended |
| Nine Months Ended |
| ||||||||
($ millions) |
| 2018 |
| 2017 |
| 2018 |
| 2017 |
| ||||
Natural gas |
| $ | (4 | ) | $ | (2 | ) | $ | (15 | ) | $ | (1 | ) |
NGL frac spread |
| (7 | ) | (10 | ) | (5 | ) | (1 | ) | ||||
Power |
| 2 |
| (3 | ) | (3 | ) | (12 | ) | ||||
Foreign exchange |
| (2 | ) | (10 | ) | 35 |
| (33 | ) | ||||
|
| $ | (11 | ) | $ | (25 | ) | $ | 12 |
| $ | (47 | ) |
Please refer to Note 20 of the 2017 Annual Consolidated Financial Statements and Note 15 of the unaudited condensed interim Consolidated Financial Statements as at and for the three and nine months ended September 30, 2018 for further details regarding AltaGas’ risk management activities.
LIQUIDITY
|
| Three Months Ended |
| Nine Months Ended |
| ||||||||
($ millions) |
| 2018 |
| 2017 |
| 2018 |
| 2017 |
| ||||
Cash from (used in) operations |
| $ | (355 | ) | $ | 88 |
| $ | (18 | ) | $ | 391 |
|
Investing activities |
| (6,269 | ) | (201 | ) | (6,465 | ) | (378 | ) | ||||
Financing activities |
| 5,994 |
| (15 | ) | 6,602 |
| (8 | ) | ||||
Increase (decrease) in cash and cash equivalents |
| $ | (630 | ) | $ | (128 | ) | $ | 119 |
| $ | 5 |
|
Cash from Operations
Cash from operations decreased by $409 million for the nine months ended September 30, 2018, compared to the same period in 2017, primarily due to lower net income after taxes and an unfavorable variance in the net change in operating assets and liabilities. The majority of the variance in net change in operating assets and liabilities was due to the addition of WGL’s operating assets and liabilities and decreased cash flows from changes in inventory and accounts payable and accrued liabilities related to weather at certain of the utilities, partially offset by increased cash flow from regulatory liabilities and the absence of pre-payments for long-term service agreements relating to RIPET.
Working Capital
($ millions except current ratio) |
| September 30, |
| December 31, |
| ||
Current assets |
| $ | 3,516 |
| $ | 702 |
|
Current liabilities |
| 4,576 |
| 815 |
| ||
Working deficiency |
| $ | (1,060 | ) | $ | (113 | ) |
Working capital ratio |
| 0.77 |
| 0.86 |
|
The decrease in working capital ratio was primarily due to an increase in current portion of long-term debt, increased short-term debt, an increase in accounts payable and accrued liabilities, and an increase in liabilities held for sale of $258 million, partially offset by increases to assets held for sale, accounts receivable and prepaid expenses. AltaGas’ working capital will fluctuate in the normal course of business.
Investing Activities
Cash used in investing activities for the nine months ended September 30, 2018 was $6.5 billion, compared to $378 million in the same period in 2017. Investing activities for the nine months ended September 30, 2018 primarily included the cash payment of $5.9 billion for the WGL acquisition, expenditures of approximately $522 million for property, plant, and equipment, and approximately $78 million of contributions to equity investments, partially offset by proceeds of $77 million on the disposition of investments (the majority of which related to Tidewater shares) and cash proceeds of approximately $10 million, net of transaction costs, primarily from the sale of non-core gas facilities and a wind asset. Investing activities for the nine months ended September 30, 2017 primarily included expenditures of approximately $359 million for property, plant, and equipment, approximately $36 million for derivative contracts, approximately $17 million of contributions to AltaGas’ equity investments, approximately $17 million in expenditures for intangible assets, and a $13 million loan to Petrogas under the $100 million interest bearing secured loan facility provided to Petrogas, partially offset by cash proceeds of approximately $70 million, net of transaction costs, primarily from the sale of the EDS and JFP transmission assets.
Financing Activities
Cash from financing activities for the nine months ended September 30, 2018 was $6.6 billion, compared to cash used in financing activities of $8 million in the same period in 2017. Financing activities for the nine months ended September 30, 2018 were primarily comprised of net short and long-term debt issuances of $3.2 billion, net proceeds from the issuance of common shares of $2.5 billion, net borrowings under bankers’ acceptances of $331 million, the proceeds from the sale of the non-controlling interest in the Northwest Hydro facilities of $912 million (net of transaction costs), and contributions from non-controlling interests of $53 million. Financing activities for the nine months ended September 30, 2017 were primarily
comprised of net proceeds from the issuance of preferred shares of $293 million and common shares of $179 million (mainly from common shares issued through the DRIP), borrowings under the credit facilities of $749 million, and proceeds from the sale of a non-controlling interest in RIPET to Vopak of $24 million, partially offset by repayments of long-term debt and short-term debt of $838 million and $102 million, respectively. Total dividends paid to common and preferred shareholders of AltaGas for the nine months ended September 30, 2018 were $390 million (2017 - $312 million), of which $224 million was reinvested through the DRIP (2017 - $175 million). The increase in dividends paid was due to more common shares outstanding and dividend increases on common shares declared in the fourth quarter of 2017.
CAPITAL RESOURCES
AltaGas’ objective for managing capital is to maintain its investment grade credit ratings, ensure adequate liquidity, optimize the profitability of its existing assets and grow its energy infrastructure to create long-term value and enhance returns for its investors. AltaGas’ capital structure is comprised of shareholders’ equity (including non-controlling interests), short-term and long-term debt (including the current portion) less cash and cash equivalents.
The use of debt or equity funding is based on AltaGas’ capital structure, which is determined by considering the norms and risks associated with operations and cash flow stability and sustainability.
($ millions) |
| September 30, |
| December 31, |
| ||
Short-term debt |
| $ | 866 |
| $ | 47 |
|
Current portion of long-term debt(1) |
| 1,999 |
| 189 |
| ||
Long-term debt(2) |
| 7,571 |
| 3,437 |
| ||
Total debt |
| 10,436 |
| 3,673 |
| ||
Less: cash and cash equivalents |
| (14 | ) | (27 | ) | ||
Net debt |
| $ | 10,422 |
| $ | 3,646 |
|
Shareholders’ equity |
| 6,521 |
| 4,573 |
| ||
Non-controlling interests |
| 542 |
| 66 |
| ||
Total capitalization |
| $ | 17,485 |
| $ | 8,285 |
|
|
|
|
|
|
| ||
Net debt-to-total capitalization (%) |
| 60 |
| 44 |
|
(1) The current portion of long-term debt will be reduced by approximately $1.3 billion upon receipt of the expected proceeds related to assets classified as held for sale on the Consolidated Balance Sheets as at September 30, 2018, which will be used to repay a portion of the bridge facility.
(2) Net of debt issuance costs of $35 million as at September 30, 2018 (December 31, 2017 - $14 million).
As at September 30, 2018, AltaGas’ total debt primarily consisted of outstanding MTNs of $2.7 billion (December 31, 2017 - $2.9 billion), WGL and Washington Gas long-term debt of $2.7 billion, reflecting fair value adjustments on acquisition (December 31, 2017 - $nil), SEMCO long-term debt of $470 million (December 31, 2017 - $462 million) and $3.7 billion drawn under the bank credit facilities (December 31, 2017 - $260 million). In addition, AltaGas had $241 million of letters of credit (December 31, 2017 - $120 million) outstanding.
As at September 30, 2018, AltaGas’ total market capitalization was approximately $5.5 billion based on approximately 268.9 million common shares outstanding and a closing trading price on September 30, 2018 of $20.55 per common share.
AltaGas’ earnings interest coverage for the rolling 12 months ended September 30, 2018 was (2.6) times (12 months ended September 30, 2017 — 2.0 times).
Credit Facilities
|
|
|
| Drawn at |
| Drawn at |
| |||
($ millions) |
| Borrowing |
| September 30, |
| December 31, |
| |||
Demand credit facilities |
| $ | 255 |
| $ | 146 |
| $ | 75 |
|
Extendible revolving letter of credit facility |
| 150 |
| 90 |
| 41 |
| |||
PNG operating facility |
| 25 |
| 10 |
| 13 |
| |||
PNG credit facility |
| 25 |
| — |
| — |
| |||
AltaGas Ltd. revolving credit facility (1) |
| 1,400 |
| 639 |
| 219 |
| |||
AltaGas Ltd. revolving US$300 million credit facility (1) (2) |
| 388 |
| 162 |
| — |
| |||
Bridge facility (1) (2) (3) |
| 2,914 |
| 2,914 |
| — |
| |||
SEMCO Energy US$150 million unsecured credit facility (1) (2) |
| 194 |
| 1 |
| 32 |
| |||
WGL US$650 million unsecured revolving credit facility (2) |
| 841 |
| — |
| — |
| |||
Washington Gas US$350 million unsecured revolving credit facility (2) (4) |
| 453 |
| — |
| — |
| |||
|
| $ | 6,645 |
| $ | 3,962 |
| $ | 380 |
|
(1) Amount drawn at September 30, 2018 converted at the month-end rate of 1 U.S. dollar = 1.2945 Canadian dollar (December 31, 2017 - 1 U.S. dollar = 1.2545 Canadian dollar).
(2) Borrowing capacity was converted at the September 30, 2018 U.S./Canadian dollar month-end exchange rate.
(3) The acquisition credit facility could remain in place for up to 12 to 18 months after closing of the WGL Acquisition, however AltaGas expects to fully repay the facility in the fourth quarter of 2018, subject to the close of pending asset sales and the timing of offering of term debt and hybrid securities.
(4) Washington Gas has the right to request additional borrowings of up to US$100 million with the bank’s approval, for a total of US$450 million.
WGL and Washington Gas use short-term debt in the form of commercial paper or unsecured short-term bank loans to fund seasonal cash requirements. Revolving committed credit facilities are maintained in an amount equal to or greater than the expected maximum commercial paper position. At September 30, 2018, commercial paper outstanding totaled US$588 million for WGL and Washington Gas.
All of the borrowing facilities have covenants customary for these types of facilities, which must be met at each quarter end. AltaGas and its subsidiaries have been in compliance with all financial covenants each quarter since the establishment of the facilities.
The following table summarizes the Corporation’s primary financial covenants as defined by the credit facility agreements:
Ratios |
| Debt covenant |
| As at |
|
Bank debt-to-capitalization(1) |
| not greater than 65 percent |
| 59.8 | % |
Bank EBITDA-to-interest expense (1) (2) |
| not less than 2.5x |
| 3.1 |
|
Bank debt-to-capitalization (SEMCO)(3) |
| not greater than 60 percent |
| 36.8 | % |
Bank EBITDA-to-interest expense (SEMCO)(3) |
| not less than 2.25x |
| 7.4 |
|
Bank debt-to-capitalization (WGL)(4) |
| not greater than 65 percent |
| 59.1 | % |
Bank debt-to-capitalization (Washington Gas)(4) |
| not greater than 65 percent |
| 46.9 | % |
(1) Calculated in accordance with the Corporation’s credit facility agreement, which is available on SEDAR at www.sedar.com.
(2) Estimated, subject to final adjustments.
(3) Bank EBITDA-to-interest expense (SEMCO) and Bank debt-to-capitalization (SEMCO) are calculated based on SEMCO’s consolidated financial statements and are calculated similar to Bank debt-to-capitalization and Bank EBITDA-to-interest expense.
(4) WGL’s bank debt-to-capitalization ratio is calculated based on WGL’s consolidated financial statements.
On September 7, 2017, a $5 billion base shelf prospectus was filed. The purpose of the base shelf prospectus is to facilitate timely offerings of certain types of future public debt and/or equity issuances during the 25-month period that the base shelf prospectus remains effective. As at September 30, 2018, approximately $4.6 billion was available under the base shelf prospectus.
On June 4, 2018, a US$2 billion preliminary short form prospectus for the issuance of both debt securities and preferred shares was filed in Alberta. AltaGas filed a final short form base shelf prospectus on June 13, 2018 both in Alberta and the U.S. This will
enable AltaGas to access the U.S. capital markets during the 25-month period that the base shelf prospectus remains effective. As at September 30, 2018, US$2.0 billion was available under the base shelf prospectus.
RELATED PARTY TRANSACTIONS
In the normal course of business, AltaGas transacts with its subsidiaries, affiliates and joint ventures. With the exception of additional related party transactions as a result of the WGL Acquisition, there were no significant changes in the nature of the related party transactions described in Note 27 of the 2017 Annual Consolidated Financial Statements.
SHARE INFORMATION
Subscription Receipts
In 2017, the Corporation issued approximately 84.5 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 $2.6 billion. Each subscription receipt entitled the holder to automatically receive one common share upon closing of the WGL Acquisition. During the time the subscription receipts were outstanding, holders received cash payments (Dividend Equivalent Payments) per subscription receipt that were equal to dividends declared on each common share. The funds were released from escrow on July 5, 2018. Upon closing, the subscription receipts were automatically exchanged for AltaGas common shares in accordance with the terms of the subscription receipt agreement and have subsequently been delisted from the TSX.
|
| As at October 19, 2018 |
|
Issued and outstanding |
|
|
|
Common shares |
| 270,520,996 |
|
Preferred Shares |
|
|
|
Series A |
| 5,511,220 |
|
Series B |
| 2,488,780 |
|
Series C |
| 8,000,000 |
|
Series E |
| 8,000,000 |
|
Series G |
| 8,000,000 |
|
Series I |
| 8,000,000 |
|
Series K |
| 12,000,000 |
|
WGL $4.25 series |
| 150,000 |
|
WGL $4.80 series |
| 70,600 |
|
WGL $5.00 series |
| 60,000 |
|
Issued |
|
|
|
Share options |
| 4,881,498 |
|
Share options exercisable |
| 3,489,609 |
|
DIVIDENDS
AltaGas declares and pays a monthly dividend to its common shareholders. Dividends on preferred shares are paid quarterly. Dividends are at the discretion of the Board of Directors and dividend levels are reviewed periodically, giving consideration to the ongoing sustainable cash flow from operating activities, maintenance and growth capital expenditures, and debt repayment requirements of AltaGas.
The following table summarizes AltaGas’ dividend declaration history:
Dividends
Year ended December 31 |
|
|
|
|
| ||
($ per common share) |
| 2018 |
| 2017 |
| ||
First quarter |
| $ | 0.547500 |
| $ | 0.525000 |
|
Second quarter |
| 0.547500 |
| 0.525000 |
| ||
Third quarter |
| 0.547500 |
| 0.525000 |
| ||
Fourth quarter |
| — |
| 0.540000 |
| ||
Total |
| $ | 1.642500 |
| $ | 2.115000 |
|
Series A Preferred Share Dividends
Year ended December 31 |
|
|
|
|
| ||
($ per preferred share) |
| 2018 |
| 2017 |
| ||
First quarter |
| $ | 0.211250 |
| $ | 0.211250 |
|
Second quarter |
| 0.211250 |
| 0.211250 |
| ||
Third quarter |
| 0.211250 |
| 0.211250 |
| ||
Fourth quarter |
| — |
| 0.211250 |
| ||
Total |
| $ | 0.633750 |
| $ | 0.845000 |
|
Series B Preferred Share Dividends
Year ended December 31 |
|
|
|
|
| ||
($ per preferred share) |
| 2018 |
| 2017 |
| ||
First quarter |
| $ | 0.217600 |
| $ | 0.195410 |
|
Second quarter |
| 0.238720 |
| 0.195710 |
| ||
Third quarter |
| 0.249530 |
| 0.201010 |
| ||
Fourth quarter |
| — |
| 0.214250 |
| ||
Total |
| $ | 0.705850 |
| $ | 0.806380 |
|
Series C Preferred Share Dividends
Year ended December 31 |
|
|
|
|
| ||
(US$ per preferred share) |
| 2018 |
| 2017 |
| ||
First quarter |
| $ | 0.330625 |
| $ | 0.275000 |
|
Second quarter |
| 0.330625 |
| 0.275000 |
| ||
Third quarter |
| 0.330625 |
| 0.275000 |
| ||
Fourth quarter |
| — |
| 0.330625 |
| ||
Total |
| $ | 0.991875 |
| $ | 1.155625 |
|
Series E Preferred Share Dividends
Year ended December 31 |
|
|
|
|
| ||
($ per preferred share) |
| 2018 |
| 2017 |
| ||
First quarter |
| $ | 0.312500 |
| $ | 0.312500 |
|
Second quarter |
| 0.312500 |
| 0.312500 |
| ||
Third quarter |
| 0.312500 |
| 0.312500 |
| ||
Fourth quarter |
| — |
| 0.312500 |
| ||
Total |
| $ | 0.937500 |
| $ | 1.250000 |
|
Series G Preferred Share Dividends
Year ended December 31 |
|
|
|
|
| ||
($ per preferred share) |
| 2018 |
| 2017 |
| ||
First quarter |
| $ | 0.296875 |
| $ | 0.296875 |
|
Second quarter |
| 0.296875 |
| 0.296875 |
| ||
Third quarter |
| 0.296875 |
| 0.296875 |
| ||
Fourth quarter |
| — |
| 0.296875 |
| ||
Total |
| $ | 0.890625 |
| $ | 1.187500 |
|
Series I Preferred Share Dividends
Year ended December 31 |
|
|
|
|
| ||
($ per preferred share) |
| 2018 |
| 2017 |
| ||
First quarter |
| $ | 0.328125 |
| $ | 0.328125 |
|
Second quarter |
| 0.328125 |
| 0.328125 |
| ||
Third quarter |
| 0.328125 |
| 0.328125 |
| ||
Fourth quarter |
| — |
| 0.328125 |
| ||
Total |
| $ | 0.984375 |
| $ | 1.312500 |
|
Series K Preferred Share Dividends
Year ended December 31 |
|
|
|
|
| ||
($ per preferred share) |
| 2018 |
| 2017 |
| ||
First quarter |
| $ | 0.312500 |
| $ | — |
|
Second quarter |
| 0.312500 |
| 0.438400 |
| ||
Third quarter |
| 0.312500 |
| 0.312500 |
| ||
Fourth quarter |
| — |
| 0.312500 |
| ||
Total |
| $ | 0.937500 |
| $ | 1.063400 |
|
In connection with the WGL Acquisition, AltaGas assumed Washington Gas’ preferred stock. Washington Gas has three series of cumulative preferred stock outstanding. Dividends declared from the period from closing of the WGL Acquisition to September 30, 2018 were as follows:
$4.25 series Preferred Share Dividends
Year ended December 31 |
|
|
|
|
| ||
(US$ per preferred share) |
| 2018 |
| 2017 |
| ||
First quarter |
| $ | — |
| $ | — |
|
Second quarter |
| — |
| — |
| ||
Third quarter |
| 1.062500 |
| — |
| ||
Fourth quarter |
| — |
| — |
| ||
Total |
| $ | 1.062500 |
| $ | — |
|
$4.80 series Preferred Share Dividends
Year ended December 31 |
|
|
|
|
| ||
(US$ per preferred share) |
| 2018 |
| 2017 |
| ||
First quarter |
| $ | — |
| $ | — |
|
Second quarter |
| — |
| — |
| ||
Third quarter |
| 1.200000 |
| — |
| ||
Fourth quarter |
| — |
| — |
| ||
Total |
| $ | 1.200000 |
| $ | — |
|
$5.00 series Preferred Share Dividends
Year ended December 31 |
|
|
|
|
| ||
(US$ per preferred share) |
| 2018 |
| 2017 |
| ||
First quarter |
| $ | — |
| $ | — |
|
Second quarter |
| — |
| — |
| ||
Third quarter |
| 1.250000 |
| — |
| ||
Fourth quarter |
| — |
| — |
| ||
Total |
| $ | 1.250000 |
| $ | — |
|
CRITICAL ACCOUNTING ESTIMATES
Since a determination of the value of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of AltaGas’ Consolidated Financial Statements requires the use of estimates and assumptions that have been made
using careful judgment. Other than as described below, AltaGas’ significant accounting policies have remained unchanged and are contained in the notes to the 2017 Annual Consolidated Financial Statements. Certain of these policies involve critical accounting estimates as a result of the requirement to make particularly subjective or complex judgments about matters that are inherently uncertain, and because of the likelihood that materially different amounts could be reported under different conditions or using different assumptions.
AltaGas’ critical accounting estimates continue to be revenue recognition, financial instruments, depreciation and amortization expense, asset retirement obligations and other environmental costs, asset impairment assessments, income taxes, pension plans and post-retirement benefits, regulatory assets and liabilities, and contingencies. For a full discussion of these accounting estimates, refer to the 2017 Annual Consolidated Financial Statements and MD&A.
ADOPTION OF NEW ACCOUNTING STANDARDS
Effective January 1, 2018, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU):
· ASU No. 2014-09 “Revenue from Contracts with Customers” and all related amendments (collectively “ASC 606”). AltaGas adopted ASC 606 using the modified retrospective method to contracts that have not been completed as at January 1, 2018. Under the modified retrospective method, the comparative information is not adjusted. The adoption of ASC 606 impacted the timing of revenue recognition in relation to contracts with take-or-pay or minimum volume commitments whereby the customers have make up rights for deficiency quantities. However, on adoption, no cumulative adjustments to opening retained earnings were required for this change in revenue recognition pattern as none of the customers had material deficiency quantities. Please also refer to Note 14 of the unaudited condensed interim Consolidated Financial Statements as at and for the three and nine months ended September 30, 2018 for further details. AltaGas does not expect the application of ASC 606 to have a material impact on its consolidated financial statements in 2018;
· ASU No. 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” which revised an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. It also amended certain disclosure requirements associated with the fair value of financial instruments. Upon adoption, AltaGas reclassified its equity securities with readily determinable fair values from available-for-sale to held for trading. Changes in fair value for equity securities with readily determinable fair values are now recognized through earnings instead of other comprehensive income. As a result, a cumulative-effect adjustment to retained earnings of approximately $7 million was recognized as at January 1, 2018. The remaining provisions of this ASU did not have a material impact on AltaGas’ consolidated financial statements;
· ASU No. 2016-15 “Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments”. The amendments in this ASU clarified the classification of certain cash flow transactions on the statement of cash flow. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;
· ASU No. 2016-16 “Income Taxes: Intra-Entity Transfers of Assets Other Than Inventory”. The amendments in this ASU revised the accounting for income tax consequences on intra-entity transfers of assets by requiring an entity to recognize current and deferred tax on intra-entity transfers of assets other than inventory when the transfer occurs. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;
· ASU No. 2016-18 “Statement of Cash Flows: Restricted Cash”. The amendments in this ASU required those amounts deemed to be restricted cash and restricted cash equivalents to be included in the cash and cash equivalents balance on the statement of cash flows. The change in presentation of the restricted cash balance on the statement of cash flows was applied on a retrospective basis;
· ASU No. 2017-01 “Business Combinations: Clarifying the Definition of a Business”. The amendments in this ASU changed the definition of a business to assist entities with evaluating when a set of transferred assets and activities is a business. AltaGas will apply the amendments to this ASU prospectively;
· ASU No. 2017-04 “Intangibles — Goodwill and Other: Simplifying the Test for Goodwill Impairment”. The amendments in this ASU removed Step 2 of the goodwill impairment test, eliminating the requirement to determine the fair value of individual assets and liabilities of a reporting unit to measure the goodwill impairment. AltaGas early adopted this ASU and will apply the amendments to this ASU prospectively. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;
· ASU No. 2017-05 “Other Income — Gains and Losses from the De-recognition of Nonfinancial Assets: Clarifying the Scope of Asset De-recognition Guidance and Accounting for Partial Sales of Nonfinancial Assets”. The amendments in this ASU clarified the scope of ASC 610-20 as well as the accounting for partial sales of nonfinancial assets. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;
· ASU No. 2017-07 “Compensation — Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”. The amendments in this ASU revised the presentation of net periodic pension cost and net periodic postretirement benefit cost on the income statement and limited the components that are eligible for capitalization in assets to only the service cost component. AltaGas applied the change in presentation of the current service cost and other components of net benefit cost on the income statement retrospectively. As a result, $0.4 million and $1.2 million of net benefit cost associated with other components were reclassified from the line item “Operating and administrative” to “Other lncome” on the Consolidated Statements of Income for the three and nine months ended September 30, 2017. AltaGas applied the change related to the capitalization of the service cost prospectively. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;
· ASU No. 2017-09 “Compensation — Stock Compensation: Scope of Modifications Accounting”. The amendments in this ASU provided guidance on the types of changes to the terms or conditions of share-based payment arrangements to which an entity would be required to apply modification accounting. The guidance was applied prospectively and did not have a material impact on AltaGas’ consolidated financial statements;
· ASU No. 2017-12 “Derivatives and Hedging — Targeted Improvements to Accounting for Hedging Activities”. The amendments in this ASU improved the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and made certain targeted improvements to simplify the application of hedge accounting. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;
· ASU No. 2018-02 “Income Statement — Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”. The amendments in this ASU allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and
· ASU No. 2018-03 “Technical Corrections and Improvements to Financial Instruments — Overall”. The amendments in this ASU clarified certain aspects of the guidance issued in ASU No. 2016-01. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements.
FUTURE CHANGES IN ACCOUNTING PRINCIPLES
In February 2016, FASB issued ASU No. 2016-02 “Leases”, which requires lessees to recognize on the balance sheet a right-of-use asset and a lease liability for all leases with lease terms greater than 12 months. Lessor accounting remains substantially unchanged, however, the ASU modifies what qualifies as a sales-type and direct financing lease and eliminates the
real estate-specific provisions included in ASC 840. The ASU also requires additional disclosures regarding leasing arrangements. In January 2018, FASB issued ASU No. 2018-01 “Land Easement Practical Expedient for Transition to Topic 842”, providing entities with an optional election not to evaluate existing and expired land easements not previously accounted for as leases under ASC 840 using the provisions of ASC 842. The amendments to the new leases standard are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. In July 2018, FASB issued ASU 2018-11 “Targeted Improvements”, allowing entities to report the comparative periods presented in the period of adoption under the old lease standard (ASC 840), and recognize a cumulative-effect adjustment to the opening balance of retained earnings as of January 1, 2019. The ASU also provides a practical expedient under which lessors are not required to separate out lease and non-lease components of a contract, provided certain conditions are met. The amendments to the new leases standard are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. AltaGas is currently performing a scoping exercise by gathering a complete inventory of lease contracts in order to evaluate the impact of adopting ASC 842 on its consolidated financial statements, but expects that the new standard will have an impact on the Corporation’s balance sheet as all operating leases will need to be reflected on the balance sheet upon adoption. In addition, AltaGas currently expects to utilize the transition practical expedients which allow entities to not have to reassess whether an arrangement contains a lease under the provisions of ASC 842.
In June 2016, FASB issued ASU No. 2016-13 “Financial Instruments — Credit Losses: Measurement of Credit Losses on Financial Instruments”. The amendments in this ASU replace the current “incurred loss” impairment methodology with an “expected loss” model for financial assets measured at amortized cost. The amendments in this ASU are effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted. AltaGas is currently assessing the impact of this ASU on its consolidated financial statements.
In June 2018, FASB issued ASU No. 2018-07 “Compensation — Stock Compensation: Improvements to Nonemployee Share-Based Payment Accounting”. The amendments in this ASU expand the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees, with the objective of making the measurement consistent with employee share based payment awards. The amendments in this update are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.
In August 2018, FASB issued ASU No. 2018-13 “Fair Value Measurement — Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurement”. The amendments in this ASU modify the disclosure requirements on fair value measurements. The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.
In August 2018, FASB issued ASU No. 2018-14 “Compensation — Retirement Benefits-Defined Benefit Plans — General: Disclosure Framework — Changes to the Disclosure Requirements for the Defined Benefit Plans”. The amendments in this ASU modify the disclosure requirements on defined benefit pension and other postretirement plans. The amendments in this update are effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.
In August 2018, FASB issued ASU No. 2018-15 “Intangibles-Goodwill and Other — Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement (CCA) that is a Service Contract”. The amendments in this ASU align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal use software license). The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.
OFF-BALANCE SHEET ARRANGEMENTS
With the exception of the subscription receipts and the net proceeds thereof held in escrow as described under the Share Information section of this MD&A, and certain additional commitments and contingencies associated with WGL as disclosed in Note 18 of the unaudited condensed interim Consolidated Financial Statements, AltaGas did not enter into any material off-balance sheet arrangements during the three and nine months ended September 30, 2018. Reference should be made to the audited Consolidated Financial Statements and MD&A as at and for the year ended December 31, 2017 for further information on off-balance sheet arrangements.
DISCLOSURE CONTROLS AND PROCEDURES (DCP) AND INTERNAL CONTROL OVER FINANCIAL REPORTING (ICFR)
Management, including the interim co-Chief Executive Officers and Chief Financial Officer, is responsible for establishing and maintaining DCP and ICFR, as those terms are defined in National Instrument 52-109 “Certification of Disclosure in Issuers’ Annual and Interim Filings”. The objective of this instrument is to improve the quality, reliability, and transparency of information that is filed or submitted under securities legislation.
Management, including the interim co-Chief Executive Officers and the Chief Financial Officer, have designed, or caused to be designed under their supervision, DCP and ICFR to provide reasonable assurance that information required to be disclosed by AltaGas in its annual filings, interim filings or other reports to be filed or submitted by it under securities legislation is made known to them, is reported on a timely basis, financial reporting is reliable, and financial statements prepared for external purposes are in accordance with U.S. GAAP.
The ICFR has been designed based on the framework established in the 2013 Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
AltaGas completed the WGL Acquisition effective July 6, 2018. As a result of this transaction, AltaGas is currently evaluating and integrating ICFR processes and activities related to WGL. AltaGas expects to complete these integration activities and related evaluation in 2019. Results for WGL reflected in the unaudited condensed interim Consolidated Financial Statements include total assets of approximately $13.5 billion as at September 30, 2018 and revenues of $464 million for the period since the transaction closed.
In August 2018, AltaGas implemented a new system that is designed to manage and provide additional work flow controls for the marketing and risk management processes for the NGL business. No other changes have been made to AltaGas’ ICFR during the first nine months of 2018 that materially affected, or are reasonably likely to materially effect, its ICFR.
It should be noted that a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues, including instances of fraud, if any, have been detected. The design of any system of controls is also based in part on certain assumptions about the likelihood of future events, and there can be no assurances that any design will succeed in achieving its stated goals under all potential conditions.
SUMMARY OF CONSOLIDATED RESULTS FOR THE EIGHT MOST RECENT QUARTERS (1)
($ millions) |
| Q3-18 |
| Q2-18 |
| Q1-18 |
| Q4-17 |
| Q3-17 |
| Q2-17 |
| Q1-17 |
| Q4-16 |
| Q3-16 |
|
Total revenue |
| 1,041 |
| 610 |
| 878 |
| 745 |
| 502 |
| 539 |
| 771 |
| 661 |
| 492 |
|
Normalized EBITDA(2) |
| 226 |
| 166 |
| 223 |
| 213 |
| 190 |
| 166 |
| 228 |
| 194 |
| 176 |
|
Net income (loss) applicable to common shares |
| (726 | ) | 1 |
| 49 |
| (11 | ) | 18 |
| (8 | ) | 32 |
| 38 |
| 46 |
|
($ per share) |
| Q3-18 |
| Q2-18 |
| Q1-18 |
| Q4-17 |
| Q3-17 |
| Q2-17 |
| Q1-17 |
| Q4-16 |
| Q3-16 |
|
Net income (loss) per common share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
| (2.78 | ) | 0.01 |
| 0.28 |
| (0.06 | ) | 0.10 |
| (0.05 | ) | 0.19 |
| 0.23 |
| 0.28 |
|
Diluted |
| (2.78 | ) | 0.01 |
| 0.28 |
| (0.06 | ) | 0.10 |
| (0.05 | ) | 0.19 |
| 0.23 |
| 0.28 |
|
Dividends declared |
| 0.55 |
| 0.55 |
| 0.55 |
| 0.54 |
| 0.53 |
| 0.53 |
| 0.53 |
| 0.53 |
| 0.52 |
|
(1) Amounts may not add due to rounding.
(2) Non-GAAP financial measure. See discussion in the “Non-GAAP Financial Measures” section of this MD&A.
AltaGas’ quarter-over-quarter financial results are impacted by seasonality, fluctuations in commodity prices, weather, the U.S./Canadian dollar exchange rate, planned and unplanned plant outages, timing of in-service dates of new projects, and acquisition and divestiture activities.
Revenue for the Utilities is generally the highest in the first and fourth quarters of any given year as the majority of natural gas demand occurs during the winter heating season, which typically extends from November to March. The run-of-river hydroelectric facilities in British Columbia are also impacted by seasonal precipitation and snowpack melt, which create periods of high flow during the spring and summer months.
Other significant items that impacted quarter-over-quarter revenue during the periods noted include:
· The weak NGL commodity prices throughout 2016 and the improved NGL commodity prices in 2017 and the first nine months of 2018;
· The weak Alberta power pool prices throughout 2016 and 2017;
· The stronger U.S. dollar throughout 2016 and the weaker U.S. dollar in the second half of 2017 and the first half of 2018 on translated results of the U.S. assets;
· The seasonally colder weather experienced at several of the utilities in the fourth quarter of 2017 and the first nine months of 2018;
· The commencement of commercial operations early in the third quarter of 2016 at the integrated midstream complex at Townsend in northeast British Columbia, including the Townsend Facility, gas gathering line, NGL egress pipelines and truck terminal;
· The commissioning of the Pomona Energy Storage Facility on December 31, 2016;
· The closing of the sale of the EDS and the JFP transmission assets to Nova Chemicals in March of 2017;
· The commencement of commercial operations on October 1, 2017 at Townsend 2A;
· The commencement of commercial operations at the first train of the North Pine Facility on December 1, 2017;
· Losses on risk management contracts recorded in 2017 and the first half of 2018 related to the foreign currency option contracts entered into to mitigate the foreign exchange risks associated with the cash purchase price of WGL;
· The negative impact on revenue of U.S. tax reform at the U.S. utilities in the first nine months of 2018; and
· Revenue from WGL after the acquisition closed in the third quarter of 2018.
Net income (loss) applicable to common shares is also affected by non-cash items such as deferred income tax, depreciation and amortization expense, accretion expense, provisions on assets, gains or losses on investments, and gains or losses on the sale of assets. In addition, net income (loss) applicable to common shares is also impacted by preferred share dividends. For these reasons, the net income (loss) may not necessarily reflect the same trends as revenue. Net income (loss) applicable to common shares during the periods noted was impacted by:
· Higher depreciation and amortization expense due to new assets placed into service;
· Higher interest expense since the first quarter of 2017 mainly due to higher financing costs associated with the bridge facility;
· The unrealized loss of approximately $8 million recognized upon ceasing to account for the Tidewater investment using the equity method in the second quarter of 2017;
· After-tax provisions totaling $84 million recognized in the fourth quarter of 2017 related to the Hanford and Henrietta gas-fired peaking facilities, a non-core gas processing facility in Alberta, and a non-core development stage peaking project in California;
· Impact of the U.S. tax reform resulting in a decrease in tax expense of approximately $34 million in the fourth quarter of 2017;
· After-tax transaction costs incurred throughout 2017 (totaling $53 million) and in the first nine months of 2018 ($41 million) predominantly due to the WGL Acquisition;
· After-tax merger commitment costs of $135 million associated with the WGL Acquisition recorded in the third quarter of 2018;
· The impact of WGL loss for the period after the close of the acquisition on July 6, 2018; and
· After-tax provisions of approximately $539 million recognized in the third quarter of 2018 primarily related to assets held for sale.