MANAGEMENT’S DISCUSSION AND ANALYSIS
This Management’s Discussion and Analysis (MD&A) dated July 31, 2019 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 six months ended June 30, 2019. 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 six months ended June 30, 2019 and the audited Consolidated Financial Statements and MD&A as at and for the year ended December 31, 2018.
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, 2018 or the Annual Information Form for the year ended December 31, 2018.
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: anticipated closing date for sale of distributed generation assets; anticipated asset sales for the remainder of 2019, conditions to closing and EBITDA impact of pending asset dispositions; RIPET as an expected catalyst for growth in the Midstream business; expected normalized EBITDA and expected normalized funds from operations for the full year 2019; growth levels and drivers expected in the three business segments; expectation that Utilities will have the largest contribution to EBITDA anticipated effect of commodity prices, exchange rates and weather on 2019 normalized EBITDA; exposure to frac spreads prior to hedging activities; exposure to propane price differential; anticipated tolling arrangements; expected net invested capital expenditures; anticipated segment allocation of capital expenditures in 2019; expected funding sources for 2019 capital expenditure program; estimated costs of growth capital projects; expected in-service dates for growth projects; expected timing of additional expenditures at RIPET; expected on-stream date of Nig Creek; expected date of construction at Townsend 2B, North Pine expansion, Mountain Valley Pipeline, MVP Southgate Project and Central Penn Pipeline; anticipated timing of applications, hearings and decisions before Utilities regulators; expected closing date of the sale of two biomass plants in the United States; expected funding sources for working capital deficiency; future changes in accounting policies and adoption of new accounting standards; and AltaGas’ long term strategy. 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: assumptions regarding asset sales anticipated to close in 2019, the U.S/Canadian dollar exchange rate, financing initiatives, the performance of the businesses underlying each sector; impacts of the hedging program; commodity prices; weather; frac spread; access to capital; timing and receipt of regulatory approvals; timing of regulatory approvals related to Utilities projects; seasonality; planned and unplanned plant outages; timing of in-service dates of new projects and acquisition and divestiture activities; taxes; operational expenses; returns on investments; dividend levels; and transaction costs.
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: capital market and liquidity risks; general economic conditions; consumption risk; market risk; internal credit risk; foreign exchange risk; debt service risk; financing and refinancing risk; market value of common shares and other securities; variability of dividends; commitments associated with the regulatory approval of the WGL Acquisition; integration of WGL; growth strategy risk; planned asset sales in 2019; potential sale of additional shares; volume throughput;
counterparty credit risk; dependence on certain partners; natural gas supply risk; operating risk; changes in laws; risk management costs and limitations; regulatory; climate change and carbon tax; construction and development; RIPET rail and marine transportation; litigation; infrastructure; cybersecurity, information and control systems risk; external stakeholder relations; composition risk; electricity and resource adequacy prices; interest rates; collateral; indigenous land and rights claims; duty to consult; underinsured and uninsured losses; weather data; service interruptions; rep agreements; Cook Inlet gas supply; health and safety; non-controlling interests in investments; decommissioning, abandonment and reclamation costs; cost of providing retirement plan benefits; labour relations; key personnel; failure of service providers; technical systems and processes incidents; securities class action suits and derivative suits; return on investments in renewable energy projects; competition; compliance with applicable law; and the other factors discussed under the heading “Risk Factors” in the Corporation’s Annual Information Form for the year ended December 31, 2018 (AIF) 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.
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., WGL Holdings, Inc. (WGL), Wrangler 1 LLC, Wrangler SPE LLC, Washington Gas Resources Corporation, WGL Energy Services, Inc. (WGL Energy Services), and SEMCO Holding Corporation; in regards to the Midstream business, AltaGas Extraction and Transmission Limited Partnership, AltaGas Pipeline Partnership, AltaGas Processing Partnership, AltaGas Northwest Processing Limited Partnership, Harmattan Gas Processing Limited Partnership, Ridley Island LPG Export Limited Partnership, and WGL Midstream Inc. (WGL Midstream); in regards to the Power business, AltaGas Power Holdings (U.S.) Inc., WGSW, Inc., WGL Energy Systems, Inc. (WGL Energy Systems), and Blythe Energy Inc. (Blythe); and, in regards to the Utilities business, Washington Gas Light Company (Washington Gas), Hampshire Gas Company, and SEMCO Energy, Inc. (SEMCO). SEMCO conducts its Michigan natural gas distribution business under the name SEMCO Energy Gas Company (SEMCO Gas), its Alaska natural gas distribution business under the name ENSTAR Natural Gas Company (ENSTAR) and its 65 percent interest in an Alaska regulated gas storage utility under the name Cook Inlet Natural Gas Storage Alaska LLC (CINGSA).
Second Quarter Highlights
(Normalized EBITDA, normalized funds from operations, normalized net income (loss), 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.)
· In the second quarter of 2019, the Ridley Island Propane Export Terminal (RIPET) was completed, with its first shipment of propane to Asia departing on May 23, 2019. RIPET is the first propane marine export facility in Canada and its completion is expected to be a catalyst for further growth within AltaGas’ Midstream business;
· On May 2, 2019, AltaGas announced that it reached an agreement for the sale of WGL Midstream’s entire interest in the Stonewall Gas Gathering System (Stonewall) to a wholly-owned subsidiary of DTE Energy Company for total gross proceeds of approximately $379 million (US$280 million). This sale, which closed on May 31, 2019, represents a portion of the planned 2019 asset sales and serves to advance AltaGas’ overall strategy to de-lever the Corporation and focus on core assets;
· On May 27, 2019, AltaGas announced the appointment of D. James Harbilas as Executive Vice President and Chief Financial Officer of AltaGas, effective June 10, 2019. Mr. Harbilas replaced Timothy Watson, who served as Executive Vice President and Chief Financial Officer until June 9, 2019;
· Normalized EBITDA was $203 million compared to $166 million in the second quarter of 2018;
· Cash from operations was $203 million ($0.74 per share) compared to $147 million ($0.82 per share) in the second quarter of 2018;
· Normalized funds from operations were $120 million ($0.43 per share) compared to $121 million ($0.67 per share) in the second quarter of 2018;
· Net income applicable to common shares was $41 million ($0.15 per share) compared to $1 million ($0.01 per share) in the second quarter of 2018;
· Normalized net loss was $5 million ($0.02 per share) compared to normalized net income of $23 million ($0.13 per share) in the second quarter of 2018;
· Net debt was $8.1 billion as at June 30, 2019, compared to $10.1 billion at December 31, 2018; and
· Net debt-to-total capitalization ratio was 51 percent as at June 30, 2019, compared to 57 percent as at December 31, 2018.
Highlights Subsequent to Quarter End
· On July 22, 2019, AltaGas announced that it has entered into a definitive agreement for the sale of its portfolio of U.S. distributed generation assets held by its subsidiaries WGL Energy Systems, Inc. and WGSW, Inc., to TerraForm Power, Inc., an affiliate of Brookfield Asset Management, for total gross proceeds of approximately US$720 million, subject to customary closing conditions. The transaction is expected to close in the third quarter of 2019. The estimated annual decrease in EBITDA resulting from the disposition of these assets is approximately $70 to $80 million.
Consolidated Financial Review
|
| Three Months Ended |
| Six Months Ended |
| ||||
($ millions) |
| 2019 |
| 2018 |
| 2019 |
| 2018 |
|
Revenue |
| 1,174 |
| 610 |
| 3,072 |
| 1,488 |
|
Normalized EBITDA(1) |
| 203 |
| 166 |
| 669 |
| 388 |
|
Net income applicable to common shares |
| 41 |
| 1 |
| 850 |
| 50 |
|
Normalized net income (loss) (1) |
| (5 | ) | 23 |
| 196 |
| 93 |
|
Total assets |
| 21,000 |
| 10,876 |
| 21,000 |
| 10,876 |
|
Total long-term liabilities |
| 9,494 |
| 4,602 |
| 9,494 |
| 4,602 |
|
Net additions (dispositions) of property, plant and equipment |
| 371 |
| 124 |
| (829 | ) | 190 |
|
Dividends declared(2) |
| 66 |
| 98 |
| 133 |
| 195 |
|
Cash from operations |
| 203 |
| 147 |
| 630 |
| 336 |
|
Normalized funds from operations(1) |
| 120 |
| 121 |
| 496 |
| 290 |
|
Normalized adjusted funds from operations(1) |
| 102 |
| 94 |
| 469 |
| 254 |
|
Normalized utility adjusted funds from operations(1) |
| 34 |
| 73 |
| 335 |
| 213 |
|
|
| Three Months Ended |
| Six Months Ended |
| ||||
($ per share, except shares outstanding) |
| 2019 |
| 2018 |
| 2019 |
| 2018 |
|
Net income per common share - basic |
| 0.15 |
| 0.01 |
| 3.08 |
| 0.28 |
|
Net income per common share - diluted |
| 0.15 |
| 0.01 |
| 3.08 |
| 0.28 |
|
Normalized net income (loss) - basic(1) |
| (0.02 | ) | 0.13 |
| 0.71 |
| 0.52 |
|
Normalized net income (loss) - diluted(1) |
| (0.02 | ) | 0.13 |
| 0.71 |
| 0.52 |
|
Dividends declared(2) |
| 0.24 |
| 0.55 |
| 0.48 |
| 1.10 |
|
Cash from operations |
| 0.74 |
| 0.82 |
| 2.28 |
| 1.89 |
|
Normalized funds from operations(1) |
| 0.43 |
| 0.67 |
| 1.80 |
| 1.63 |
|
Normalized adjusted funds from operations(1) |
| 0.37 |
| 0.52 |
| 1.70 |
| 1.43 |
|
Normalized utility adjusted funds from operations(1) |
| 0.12 |
| 0.41 |
| 1.21 |
| 1.20 |
|
Shares outstanding - basic (millions) |
|
|
|
|
|
|
|
|
|
During the period(3) |
| 276 |
| 179 |
| 276 |
| 178 |
|
End of period |
| 277 |
| 181 |
| 277 |
| 181 |
|
(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: $0.1825 beginning on November 27, 2017, and $0.08 beginning on December 27, 2018.
(3) Weighted average.
Three Months Ended June 30
Normalized EBITDA for the second quarter of 2019 was $203 million, compared to $166 million for the same quarter in 2018. Factors positively impacting normalized EBITDA included contributions from the WGL Acquisition, contributions from RIPET which was placed into service in May 2019, higher realized frac spreads, and higher equity earnings from Petrogas. These were partially offset by the impact of the sale of the Northwest Hydro Electric facilities (Northwest Hydro) in January 2019, the impact of the sale of the San Joaquin facilities in the fourth quarter of 2018, the impact of the initial public offering (IPO) of AltaGas Canada Inc. (ACI) in October 2018, and the impact of the sale of non-core Midstream and Power assets in February 2019. For the three months ended June 30, 2019, the average Canadian/U.S. dollar exchange rate increased to 1.34 from an average of 1.29 in the same quarter of 2018, resulting in an increase in normalized EBITDA of approximately $2 million.
Normalized funds from operations for the second quarter of 2019 were $120 million ($0.43 per share), compared to $121 million ($0.67 per share) for the same quarter in 2018. The decrease was mainly due to higher interest expense, partially offset by the
same factors impacting normalized EBITDA. In the second quarter of 2019, AltaGas received $3 million of dividend income from the Petrogas Preferred Shares (2018 - $3 million) and $2 million of common share dividends from Petrogas (2018 - $1 million).
Normalized adjusted funds from operations (AFFO) for the second quarter of 2019 were $102 million ($0.37 per share), compared to $94 million ($0.52 per share) for the same quarter in 2018. Factors impacting AFFO in the second quarter of 2019 included the same drivers as normalized funds from operations and higher cash received from non-controlling interests. In the second quarter of 2019, AltaGas paid $17 million of preferred share dividends (2018 - $16 million).
Normalized utility adjusted funds from operations (UAFFO) for the second quarter of 2019 were $34 million ($0.12 per share), compared to $73 million ($0.41 per share) for the same quarter in 2018. The decrease was due to higher utilities depreciation and the same drivers as normalized adjusted funds from operations.
Operating and administrative expenses for the second quarter of 2019 were $309 million, compared to $146 million for the same quarter in 2018. The increase was mainly due to the addition of WGL’s operating and administrative expenses, partially offset by the impact of asset sales completed in 2018 and early 2019. Depreciation and amortization expense for the second quarter of 2019 was $107 million, compared to $73 million for the same quarter in 2018. The increase was mainly due to depreciation and amortization expense on assets acquired in the WGL Acquisition, partially offset by the impact of asset sales completed in 2018 and the first quarter of 2019. Interest expense for the second quarter of 2019 was $83 million, compared to $43 million for the same quarter in 2018. The increase was predominantly due to interest on debt assumed in the WGL Acquisition and higher average debt balances.
AltaGas recorded an income tax recovery of $33 million for the second quarter of 2019 compared to income tax expense of $2 million in the same quarter of 2018. The increase in tax recovery was mainly due to tax rate adjustments related to the Alberta Job Creation Tax Cut, as well as the inclusion of tax at WGL.
Net income applicable to common shares for the second quarter of 2019 was $41 million ($0.15 per share), compared to $1 million ($0.01 per share) for the same quarter in 2018. The increase was mainly due to the same previously referenced factors impacting normalized EBITDA, gains on sale of assets, and lower income tax expense, partially offset by higher unrealized losses on risk management contracts, higher interest expense, and higher depreciation and amortization expense.
Normalized net loss was $5 million ($0.02 per share) for the second quarter of 2019, compared to normalized net income of $23 million ($0.13 per share) reported for the same quarter in 2018. The decrease was mainly due to higher interest expense and higher depreciation and amortization expense, partially offset by the same previously referenced factors impacting normalized EBITDA. Normalizing items in the second quarter of 2019 reduced normalized net income (loss) by $46 million and included after-tax amounts related to gains on sale of assets, changes in fair value of natural gas optimization inventory, transaction costs related to acquisitions and dispositions, unrealized losses on risk management contracts, losses on investments, provisions on assets, a statutory tax rate change in Alberta, and provisions on investments accounted for by the equity method. Normalizing items in the second quarter of 2018 increased normalized net income by $22 million and included after-tax amounts related to transaction costs on acquisitions, unrealized gains on risk management contracts, amortization of financing costs associated with the bridge facility of $2 million, realized losses on foreign exchange derivatives, and losses on investments. Please refer to the Non-GAAP Financial Measures section of this MD&A for further details on normalization adjustments.
Six Months Ended June 30
Normalized EBITDA for the first half of 2019 was $669 million, compared to $388 million for the same period in 2018. Factors positively impacting normalized EBITDA included contributions from the WGL Acquisition, contributions from RIPET which was placed into service in May 2019, higher realized frac spreads, and higher equity earnings from Petrogas. These were partially offset by the impact of the sale of the San Joaquin facilities in the fourth quarter of 2018, the impact of the IPO of ACI in October 2018, the impact of the sale of the Northwest Hydro facilities in January 2019, and the impact of the sale of non-core Midstream and Power assets in February 2019. For the first half of 2019, the average Canadian/U.S. dollar exchange rate increased to 1.33 from an average of 1.28 in the same period of 2018, resulting in an increase in normalized EBITDA of approximately $7 million.
Normalized funds from operations for the first half of 2019 were $496 million ($1.80 per share), compared to $290 million ($1.63 per share) for the same period in 2018. The increase was mainly due to the same drivers as normalized EBITDA and lower current tax expense, partially offset by higher interest expense. In the first half of 2019, AltaGas received $6 million of dividend income from the Petrogas Preferred Shares (2018 - $6 million) and $3 million of common share dividends from Petrogas (2018 - $2 million).
Normalized adjusted funds from operations for the first half of 2019 were $469 million ($1.70 per share), compared to $254 million ($1.43 per share) for the same period in 2018. The increase was mainly due to the same drivers as normalized funds from operations and higher cash received from non-controlling interests. In the first half of 2019, AltaGas paid $35 million of preferred share dividends (2018 - $33 million).
Normalized utility adjusted funds from operations for the first half of 2019 were $335 million ($1.21 per share), compared to $213 million ($1.20 per share) for the same period in 2018. The increase was due to the same drivers as normalized adjusted funds from operations partially offset by higher utilities depreciation. The decrease in the per share amount is due to a higher number of shares outstanding during the first half of 2019 compared to the first half of 2018.
Operating and administrative expenses for the first half of 2019 were $659 million, compared to $287 million for the same period in 2018. The increase was mainly due to the addition of WGL’s operating and administrative expenses, partially offset by the impact of the ACI IPO in 2018. Depreciation and amortization expense for the first half of 2019 was $226 million, compared to $145 million for the same period in 2018. The increase was mainly due to depreciation and amortization expense on assets acquired in the WGL Acquisition, partially offset by the impact of asset sales completed in 2018 and the first quarter of 2019. Interest expense for the first half of 2019 was $176 million, compared to $86 million for the same period in 2018. The increase was predominantly due to interest on debt assumed in the WGL Acquisition and higher average debt balances.
AltaGas recorded income tax expense of $94 million for the first half of 2019 compared to $21 million in the same period of 2018. The increase in tax expense was mainly due to tax expense incurred on the sale of the remaining interest in the Northwest Hydro facilities and tax on WGL’s earnings, partially offset by tax recoveries due to a one-time unitary tax rate adjustment related to the WGL Acquisition and a tax rate adjustment related to the Alberta Job Creation Tax Cut.
Net income applicable to common shares for the first half of 2019 was $850 million ($3.08 per share), compared to $50 million ($0.28 per share) for the same period in 2018. The increase was mainly due to the gain on the sale of AltaGas’ remaining interest in the Northwest Hydro facilities and the same previously referenced factors impacting normalized EBITDA, partially offset by higher deferred income tax expense, higher interest expense, higher depreciation and amortization expense, and lower unrealized gains on risk management contracts.
Normalized net income was $196 million ($0.71 per share) for the first half of 2019, compared to normalized net income of $93 million ($0.52 per share) reported for the same period in 2018. The increase was mainly due to the same previously referenced factors impacting normalized EBITDA, partially offset by higher income tax expense, higher interest expense, and higher depreciation and amortization expense. Normalizing items in the first half of 2019 reduced normalized net income by $654 million and included after-tax amounts related to gains on sale of assets, changes in fair value of natural gas optimization inventory,
merger commitment cost recovery due to a change in timing related to certain WGL merger commitments, transaction costs related to acquisitions and dispositions, unrealized gains on risk management contracts, losses on investments, provisions on assets, provisions on investments accounted for by the equity method, and the impact of a statutory tax rate change in Alberta. Normalizing items in the first half of 2018 increased normalized net income by $43 million and included after-tax amounts related to transaction costs on acquisitions, losses on investments, amortization of financing costs associated with the bridge facility of $5 million, unrealized gains on risk management contracts, realized loss on foreign exchange derivatives, and gains on sale of assets. Please refer to the Non-GAAP Financial Measures section of this MD&A for further details on normalization adjustments.
2019 Outlook
With 2019 being the first full year of operations including WGL, AltaGas expects to achieve annual consolidated normalized EBITDA of approximately $1.2 to $1.3 billion, and normalized funds from operations of approximately $850 to $950 million. This range is net of asset sales which have closed or are anticipated to close in 2019, including the remaining 55 percent interest in the Northwest Hydro facilities which closed in January 2019, the interest in Stonewall which closed in May 2019, and the pending sale of WGL’s distributed generation portfolio. To date this year, AltaGas has announced or completed approximately $1.3 billion of the planned $1.5 to $2.0 billion asset sales program targeted for 2019.
Growth is expected in 2019 in the Utilities and Midstream segments, and in the Power segment excluding the impact of asset sales. The Utilities segment is expected to have the largest contribution to EBITDA, followed by the Midstream and Power segments. Specifically for Utilities, a full year of WGL results will be the largest contributor to growth, along with new capital and rate base growth. Growth in the Midstream segment will largely be driven by a full year of WGL results, contributions from RIPET, and higher equity earnings from Petrogas. Recent agreements with Black Swan and other producers are expected to result in increased use of AltaGas’ integrated infrastructure in Northeastern British Columbia, including the North Pine facility (North Pine). Finally, the Power segment is expected to be impacted by the non-core Power sales completed in 2018, as well as the sale of the remaining 55 percent interest in the Northwest Hydro facilities which was completed in January 2019. This will be partially offset by contributions from WGL’s existing contracted renewable power business (prior to disposal) and power marketing business.
The overall forecasted normalized EBITDA and funds from operations include assumptions around asset sales anticipated to close in 2019, the U.S./Canadian dollar exchange rate, and other financing initiatives. Within each segment, the performance of the underlying businesses has the potential to vary. Any variance from AltaGas’ current assumptions could impact the forecasted normalized EBITDA and funds from operations.
AltaGas estimates an average of approximately 10,000 Bbls/d of NGL will be exposed to frac spreads prior to hedging activities. For 2019, AltaGas has frac hedges in place for approximately 6,200 Bbls/d at an average price of approximately $40/Bbl excluding basis differentials. At RIPET, AltaGas is exposed to the propane price differential between North American Indices and the Far East Index for contracts not under tolling arrangements. AltaGas estimates an average of approximately 29,000 Bbls/d will be exposed to these price differentials for the remainder of 2019. AltaGas has hedges in place for approximately 66 percent of these exposed propane volumes at an average FEI to Mont Belvieu spread of US$129/MT. AltaGas plans to manage the facility such that a majority of annual capacity will be underpinned by tolling arrangements, and expects to reach this objective over the next several years.
Sensitivity Analysis
AltaGas’ financial performance is affected by factors such as changes in commodity prices, exchange rates and weather. The following table illustrates the approximate effect of these key variables on AltaGas’ expected normalized EBITDA for 2019:
Factor |
| Increase or |
| Approximate impact |
|
Natural gas liquids fractionation spread (1) |
| $1/Bbl |
| 1 |
|
Degree day variance from normal - Utilities (2) |
| 5 percent |
| 7 |
|
Change in CAD per US$ exchange rate |
| 0.05 |
| 35 |
|
FG&P and extraction inlet volumes |
| 10 percent |
| 13 |
|
RIPET Propane Far East Index to Mont Belvieu spread (3) |
| US$0.02/gal |
| 3 |
|
(1) Based on approximately 63 percent of frac spread exposed NGL volumes being hedged.
(2) Degree days — Utilities relate to SEMCO Gas, ENSTAR, and Washington Gas service areas. Degree days are a measure of coldness determined daily as the numbers of degrees the average temperature during the day in question is below 65 degrees Fahrenheit. 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.
(3) The impact on EBITDA due to changes in the spread will vary and is being managed through an active hedging program.
Growth Capital
Based on projects currently under review, development or construction, AltaGas expects net invested capital expenditures of approximately $1.3 billion in 2019. The focused and strategic approach to capital expenditures in 2019 will target projects that provide ongoing growth potential, favorable risk profiles, and the strongest risk-adjusted returns with immediate payback, as AltaGas continues to strengthen its balance sheet. The Utilities segment is expected to account for approximately 60 to 65 percent of total capital expenditures, while the Midstream segment is expected to account for approximately 35 to 40 percent and the Power segment is expected to account for any remainder. Midstream and Power maintenance capital is expected to be approximately $30 to $40 million of the total capital expenditures in 2019. AltaGas’ capital expenditures for the Utilities segment will focus on accelerated pipe replacement programs in Virginia, Maryland, the District of Columbia and Michigan, new customer additions, and the construction of the Marquette Connector Pipeline. In the Midstream segment, capital expenditures are anticipated to primarily relate to the completion of RIPET, the Townsend expansion, the Aitken Creek integrated development project, the second train of North Pine, and WGL’s investment in the Mountain Valley gas pipeline development. The Power segment continues to pursue a capital-light strategy. The Corporation continues to focus on enhancing productivity and streamlining businesses.
AltaGas’ 2019 committed capital program is expected to be funded through internally-generated cash flow, asset sales, the Dividend Reinvestment and Optional Cash Purchase Plan (DRIP), and normal course borrowings on existing committed credit facilities.
Growth Capital Project Updates
The following table summarizes the status of AltaGas’ significant growth projects. A full description of growth capital projects is provided in the MD&A for the year ended December 31, 2018.
Project |
| AltaGas’ |
| Estimated |
| Expenditures |
| Status |
| Expected |
Midstream Projects | ||||||||||
Ridley Island Propane Export Terminal |
| 70% |
| $276 million (net of partner recoveries) (5) |
| $248 million (net of partner recoveries) |
| RIPET commenced operations in the second quarter of 2019, with the introduction of feedstock in mid-April and the first shipment departing with propane destined for Asia on May 23, 2019. Additional expenditures, primarily related to close-out of construction activities, are expected to be incurred in the third quarter of 2019. |
| RIPET was placed into service in May 2019. |
Nig Creek Plant |
| 50% |
| $100 million |
| $50 million |
| Construction of Nig Creek, the second plant in the Aitken Creek development, is progressing and is expected to be on stream in the fourth quarter of 2019. |
| Q4 2019 |
Northeast B.C. Pipeline Projects |
| 33% to 100% |
| $68 million |
| $16 million |
| The Northeast B.C. Pipeline projects consists of three pipelines; the Inga gas gathering pipeline (33% ownership), the Aitken Creek natural gas liquids (NGL) pipeline (100% ownership) which will connect the Aitken Creek facilities to the Townsend Complex, and the Gundy lateral pipeline (100% ownership). Construction of all segments is underway or expected to begin in the third quarter of 2019. |
| Q4 2019, pending regulatory approvals. |
Townsend 2B Expansion and Mercaptan Treating |
| 100% |
| $165 million |
| $59 million |
| Construction activities commenced in the second quarter of 2019. The expected completion date is the first quarter of 2020. |
| Q1 2020 |
North Pine Expansion |
| 100% |
| $58 million |
| $9 million |
| Detailed design is complete. All major long lead equipment has been ordered and fabrication is in progress. Construction activities are expected to commence in the third quarter of 2019. |
| Q1 2020 |
Mountain Valley Pipeline |
| 10% |
| US$350 million |
| US$332 million |
| Construction is underway. As at June 30, 2019, approximately 80 percent of the project is complete, which includes construction of five compressor stations and related facilities. In the second quarter of 2019, the estimated completion date was moved to mid-2020 from Q4 2019 due to ongoing legal and regulatory challenges. Despite the delays, AltaGas’ exposure is contractually capped to the original estimated contributions of US$350 million. |
| Mid-2020 due to ongoing legal and regulatory challenges |
MVP Southgate Project |
| 5% |
| US$20 million |
| US$2 million |
| Construction is expected to begin late in the first quarter of 2020. Expenditures to date relate to land surveys, land acquisition, and obtaining permits and regulatory approvals. |
| Late 2020 |
Central Penn Expansion (Leidy South) |
| 22% |
| US$50 million |
| US$1 million |
| Regulatory approvals are expected in the fourth quarter of 2020 with construction anticipated to begin in early 2021. |
| Q4 2021 |
Project |
| AltaGas’ |
| Estimated |
| Expenditures |
| Status |
| Expected |
Utilities Projects | ||||||||||
Accelerated Utility Pipe Replacement Programs — District of Columbia |
| 100% |
| Estimated US$305 million over the five year period from October 2019 to December 2024, plus additional expenditures in subsequent periods. |
| $nil(3)(4) |
| Washington Gas has submitted an application for the second phase of PROJECTpipes to the Public Service Commission of the District of Columbia (PSC of DC). The PSC of DC is finalizing its procedural schedule related to this application. |
| Individual assets are placed into service throughout the program. |
Accelerated Utility Pipe Replacement Programs — Maryland |
| 100% |
| Estimated US$350 million over the five year period from January 2019 to December 2023, plus additional expenditures in subsequent periods. |
| US$21 million(3) |
| The second phase of the accelerated utility pipe replacement programs in Maryland (STRIDE 2.0) began in January 2019. |
| Individual assets are placed into service throughout the program. |
Accelerated Utility Pipe Replacement Programs — Virginia |
| 100% |
| Estimated US$500 million over the five year period from January 2018 to December 2022, plus additional expenditures in subsequent periods. |
| US$118 million(3) |
| The second phase of the accelerated pipe replacement programs in Virginia (SAVE 2.0) began in January 2018. |
| Individual assets are placed into service throughout the program. |
Accelerated Main Replacement Programs — Michigan |
| 100% |
| Estimated US$50 million over five year period from 2015 to 2020. |
| US$33 million(3) |
| The third phase of the Accelerated Main Replacement Program (MRP3) in Michigan expires in May 2020. SEMCO’s May 2019 rate case included the request for a new five year plan beyond 2020, similar to the current spend of approximately US$10 million annually. Settlement discussions are expected to begin in Q3 2019. The MPSC is required to rule in the case no later than March 31, 2020. |
| Individual assets are placed into service throughout the program. |
Marquette Connector Pipeline |
| 100% |
| US$154 million |
| US$55 million |
| Construction is well underway with over 300 contract employees currently working on the project. All permanent Right-of-Way and associated construction easements have been secured. Community engagement, interaction, and media coverage continue to be positive. The pipeline in-service date is scheduled for November 2019. |
| Late Q4 2019 |
(1) These amounts are estimates and are subject to change based on various factors. Where appropriate, the amounts reflect AltaGas’ share of the various projects.
(2) Expenditures to date reflect total cumulative expenditures incurred from inception of the projects to June 30, 2019. For WGL projects, this also includes any expenditures prior to the close of the WGL Acquisition on July 6, 2018.
(3) The utility accelerated replacement programs are long-term projects with multiple phases for which expenditures are approved by the regulators and managed in five year increments. Expenditures to date only include amounts for the current programs described above, and exclude any expenditures made under prior increments of the programs. Actual regulatory filings may differ from reported amounts.
(4) Program is expected to commence in October 2019.
(5) AltaGas’ share of the original budgeted costs for RIPET (net of partner recoveries) was approximately $290 million.
With the pending sale of the WGL distributed generation portfolio, the investment in SFGF II, LLC is no longer included in AltaGas’ growth capital projects.
Non-GAAP Financial Measures
This MD&A contains references to certain financial measures used by AltaGas that do not have a standardized meaning prescribed by GAAP and may not be comparable to similar measures presented by other entities. Readers are cautioned that these non-GAAP
measures should not be construed as alternatives to other measures of financial performance calculated in accordance with GAAP. The non-GAAP measures and their reconciliation to GAAP financial measures are shown below. These non-GAAP measures provide additional information that management believes is meaningful in describing AltaGas’ operational performance, liquidity and capacity to fund dividends, capital expenditures, and other investing activities. The specific rationale for, and incremental information associated with, each non-GAAP measure is discussed below.
References to normalized EBITDA, normalized net income (loss), normalized funds from operations, normalized adjusted funds from operations, normalized utility adjusted funds from operations, net debt, and net debt to total capitalization throughout this MD&A have the meanings as set out in this section.
Normalized EBITDA
|
| Three Months Ended |
| Six Months Ended |
| ||||||||
($ millions) |
| 2019 |
| 2018 |
| 2019 |
| 2018 |
| ||||
Normalized EBITDA |
| $ | 203 |
| $ | 166 |
| $ | 669 |
| $ | 388 |
|
Add (deduct): |
|
|
|
|
|
|
|
|
| ||||
Transaction costs related to acquisitions and dispositions |
| (1 | ) | (7 | ) | (13 | ) | (17 | ) | ||||
Merger commitment cost recovery |
| — |
| — |
| 5 |
| — |
| ||||
Unrealized gains (losses) on risk management contracts |
| (15 | ) | 22 |
| 16 |
| 23 |
| ||||
Changes in fair value of natural gas optimization inventory |
| 10 |
| — |
| 4 |
| — |
| ||||
Non-controlling interest related to HLBV investments |
| (3 | ) | — |
| (8 | ) | — |
| ||||
Realized losses on foreign exchange derivatives |
| — |
| (36 | ) | — |
| (36 | ) | ||||
Losses on investments |
| (4 | ) | (5 | ) | (3 | ) | (15 | ) | ||||
Gain on sale of assets |
| 34 |
| — |
| 720 |
| 1 |
| ||||
Provisions on assets |
| (1 | ) | — |
| (1 | ) | — |
| ||||
Provisions on investments accounted for by the equity method |
| (2 | ) | — |
| (2 | ) | — |
| ||||
Development costs |
| — |
| — |
| — |
| 1 |
| ||||
Investment tax credits related to distributed generation assets |
| (2 | ) | — |
| (5 | ) | — |
| ||||
Accretion expenses |
| (1 | ) | (3 | ) | (3 | ) | (6 | ) | ||||
Foreign exchange gains (losses) |
| (1 | ) | 1 |
| (1 | ) | 1 |
| ||||
EBITDA |
| $ | 217 |
| $ | 138 |
| $ | 1,378 |
| $ | 340 |
|
Add (deduct): |
|
|
|
|
|
|
|
|
| ||||
Depreciation and amortization |
| (107 | ) | (73 | ) | (226 | ) | (145 | ) | ||||
Interest expense |
| (83 | ) | (43 | ) | (176 | ) | (86 | ) | ||||
Income tax recovery (expense) |
| 33 |
| (2 | ) | (94 | ) | (21 | ) | ||||
Net income after taxes (GAAP financial measure) |
| $ | 60 |
| $ | 20 |
| $ | 882 |
| $ | 88 |
|
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, losses on investments, transaction costs related to acquisitions and dispositions, merger commitment cost recovery due to a change in timing related to certain WGL merger commitments, gains on the sale of assets, accretion expenses related to asset retirement obligations, realized losses on foreign exchange derivatives, provisions on assets, provisions on investments accounted for by the equity method, development costs, foreign exchange gains (losses), 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 |
| Six Months Ended |
| ||||||||
($ millions) |
| 2019 |
| 2018 |
| 2019 |
| 2018 |
| ||||
Normalized net income (loss) |
| $ | (5 | ) | $ | 23 |
| $ | 196 |
| $ | 93 |
|
Add (deduct) after-tax: |
|
|
|
|
|
|
|
|
| ||||
Transaction costs related to acquisitions and dispositions |
| (1 | ) | (5 | ) | (10 | ) | (16 | ) | ||||
Merger commitment cost recovery |
| — |
| — |
| 5 |
| — |
| ||||
Unrealized gains (losses) on risk management contracts |
| (11 | ) | 26 |
| 12 |
| 26 |
| ||||
Changes in fair value of natural gas optimization inventory |
| 8 |
| — |
| 3 |
| — |
| ||||
Realized loss on foreign exchange derivatives |
| — |
| (36 | ) | — |
| (36 | ) | ||||
Losses on investments |
| (4 | ) | (5 | ) | (3 | ) | (13 | ) | ||||
Gain on sale of assets |
| 46 |
| — |
| 639 |
| 1 |
| ||||
Provisions on assets |
| (1 | ) | — |
| (1 | ) | — |
| ||||
Provisions on investments accounted for by the equity method |
| (2 | ) | — |
| (2 | ) | — |
| ||||
Statutory tax rate change |
| 11 |
| — |
| 11 |
| — |
| ||||
Financing costs associated with the bridge facility |
| — |
| (2 | ) | — |
| (5 | ) | ||||
Net income applicable to common shares (GAAP financial measure) |
| $ | 41 |
| $ | 1 |
| $ | 850 |
| $ | 50 |
|
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, losses on investments, transaction costs related to acquisitions and dispositions, merger commitment cost recovery due to a change in timing related to certain WGL merger commitments, gains on the sale of assets, financing costs associated with the bridge facility for the WGL Acquisition, realized loss on foreign exchange derivatives, provisions on investments accounted for by the equity method, provisions on assets, statutory tax rate change, 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, AFFO and UAFFO
|
| Three Months Ended |
| Six Months Ended |
| ||||||||
($ millions) |
| 2019 |
| 2018 |
| 2019 |
| 2018 |
| ||||
Normalized utility adjusted funds from operations |
| $ | 34 |
| $ | 73 |
| $ | 335 |
| $ | 213 |
|
Add (deduct): |
|
|
|
|
|
|
|
|
| ||||
Utilities depreciation and amortization |
| 68 |
| 21 |
| 134 |
| 41 |
| ||||
Normalized adjusted funds from operations |
| $ | 102 |
| $ | 94 |
| $ | 469 |
| $ | 254 |
|
Add (deduct): |
|
|
|
|
|
|
|
|
| ||||
Net cash received from non-controlling interests |
| (16 | ) | (6 | ) | (32 | ) | (19 | ) | ||||
Midstream and Power maintenance capital |
| 17 |
| 17 |
| 24 |
| 22 |
| ||||
Preferred dividends paid |
| 17 |
| 16 |
| 35 |
| 33 |
| ||||
Normalized funds from operations |
| $ | 120 |
| $ | 121 |
| $ | 496 |
| $ | 290 |
|
Add (deduct): |
|
|
|
|
|
|
|
|
| ||||
Transaction and financing costs related to acquisitions and dispositions |
| (1 | ) | (7 | ) | (13 | ) | (20 | ) | ||||
Merger commitment cost recovery |
| — |
| — |
| 5 |
| — |
| ||||
Funds from operations |
| $ | 119 |
| $ | 114 |
| $ | 488 |
| $ | 270 |
|
Add (deduct): |
|
|
|
|
|
|
|
|
| ||||
Net change in operating assets and liabilities |
| 85 |
| 34 |
| 148 |
| 68 |
| ||||
Asset retirement obligations settled |
| (1 | ) | (1 | ) | (6 | ) | (2 | ) | ||||
Cash from operations (GAAP financial measure) |
| $ | 203 |
| $ | 147 |
| $ | 630 |
| $ | 336 |
|
Normalized funds from operations, normalized adjusted funds from operations, and normalized utility adjusted funds from operations are used to assist management and investors in analyzing the liquidity of the Corporation. Management uses these measures to understand the ability to generate funds for capital investments, debt repayment, dividend payments and other investing activities.
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. Normalized funds from operations is calculated based on cash from operations and adjusted for 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 and merger commitments. Normalized adjusted funds from operations is based on normalized funds from operations, further adjusted to remove the impact of cash transactions with non-controlling interests, Midstream and Power maintenance capital, and preferred share dividends paid. Normalized utility adjusted funds from operations is based on normalized adjusted funds from operations, further adjusted for Utilities segment depreciation and amortization.
Funds from operations, normalized funds from operations, normalized adjusted funds from operations, and normalized utility adjusted 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 Capital Resources section of this MD&A.
Supplemental Reconciliation
Reconciliation of Normalized EBITDA to Normalized Net Income (Loss)
The below table provides a supplemental reconciliation of normalized EBITDA to normalized net income (loss). Both of these non-GAAP measures have been previously reconciled to the relevant GAAP financial measures in the section above. This supplemental information is provided as additional information to assist analysts and investors in comparing normalized EBITDA to normalized net income (loss) and is not intended as a substitute for the reconciliations to the nearest comparable GAAP measures. Readers should not place undue reliance on this supplemental reconciliation.
|
| Three Months Ended |
| Six Months Ended |
| ||||||||
($ millions) |
| 2019 |
| 2018 |
| 2019 |
| 2018 |
| ||||
Normalized EBITDA |
| $ | 203 |
| $ | 166 |
| $ | 669 |
| $ | 388 |
|
Add (deduct): |
|
|
|
|
|
|
|
|
| ||||
Depreciation and amortization |
| (107 | ) | (73 | ) | (226 | ) | (145 | ) | ||||
Interest expense |
| (83 | ) | (43 | ) | (176 | ) | (86 | ) | ||||
Normalizing items impacting interest expense |
| — |
| 4 |
| — |
| 9 |
| ||||
Income tax recovery (expense) |
| 33 |
| (2 | ) | (94 | ) | (21 | ) | ||||
Normalizing items impacting tax expense |
| (28 | ) | (9 | ) | 66 |
| (9 | ) | ||||
Accretion expenses |
| (1 | ) | (3 | ) | (3 | ) | (6 | ) | ||||
Foreign exchange gains (losses) |
| (1 | ) | 1 |
| (1 | ) | 1 |
| ||||
Non-controlling interest related to HLBV investments |
| (3 | ) | — |
| (8 | ) | — |
| ||||
Net (income) loss applicable to non-controlling interests |
| (1 | ) | (2 | ) | 3 |
| (5 | ) | ||||
Preferred share dividends |
| (17 | ) | (16 | ) | (34 | ) | (33 | ) | ||||
Normalized net income (loss) |
| $ | (5 | ) | $ | 23 |
| $ | 196 |
| $ | 93 |
|
Results of Operations by Reporting Segment
Normalized EBITDA (1) |
| Three Months Ended |
| Six Months Ended |
| ||||||||
($ millions) |
| 2019 |
| 2018 |
| 2019 |
| 2018 |
| ||||
Utilities |
| $ | 81 |
| $ | 50 |
| $ | 422 |
| $ | 162 |
|
Midstream |
| 97 |
| 48 |
| 204 |
| 119 |
| ||||
Power |
| 34 |
| 75 |
| 61 |
| 116 |
| ||||
Sub-total: Operating Segments |
| $ | 212 |
| $ | 173 |
| $ | 687 |
| $ | 397 |
|
Corporate |
| (9 | ) | (7 | ) | (18 | ) | (9 | ) | ||||
|
| $ | 203 |
| $ | 166 |
| $ | 669 |
| $ | 388 |
|
(1) Non-GAAP financial measure; See discussion in Non-GAAP Financial Measures section of this MD&A.
Revenue |
| Three Months Ended |
| Six Months Ended |
| ||||||||
($ millions) |
| 2019 |
| 2018 |
| 2019 |
| 2018 |
| ||||
Utilities |
| $ | 417 |
| $ | 212 |
| $ | 1,524 |
| $ | 634 |
|
Midstream |
| 414 |
| 262 |
| 865 |
| 633 |
| ||||
Power |
| 351 |
| 167 |
| 710 |
| 315 |
| ||||
Sub-total: Operating Segments |
| $ | 1,182 |
| $ | 641 |
| $ | 3,099 |
| $ | 1,582 |
|
Corporate |
| — |
| (15 | ) | — |
| (15 | ) | ||||
Intersegment eliminations |
| (8 | ) | (16 | ) | (27 | ) | (79 | ) | ||||
|
| $ | 1,174 |
| $ | 610 |
| $ | 3,072 |
| $ | 1,488 |
|
Utilities
Operating Statistics
|
| Three Months Ended |
| Six Months Ended |
| ||||
|
| 2019 |
| 2018 |
| 2019 |
| 2018 |
|
Natural gas deliveries - end-use (Bcf)(1) |
| 20.7 |
| 12.0 |
| 96.1 |
| 43.0 |
|
Natural gas deliveries - transportation (Bcf)(1) |
| 25.2 |
| 10.9 |
| 72.8 |
| 24.3 |
|
Service sites (thousands)(2) |
| 1,648 |
| 581 |
| 1,648 |
| 581 |
|
Degree day variance from normal - SEMCO Gas (%) (3) |
| 14.5 |
| 14.8 |
| 7.5 |
| 5.5 |
|
Degree day variance from normal - ENSTAR (%) (3) |
| (16.1 | ) | (6.1 | ) | (11.4 | ) | (3.0 | ) |
Degree day variance from normal - Washington Gas (%) (3) (4) |
| (44.5 | ) | — |
| (6.3 | ) | — |
|
(1) Bcf is one billion cubic feet.
(2) Service sites reflect all of the service sites of the utilities, including transportation and non-regulated business lines. Service sites at June 30, 2018 also include service sites of the Canadian utilities, which were included in the ACI IPO in October 2018.
(3) A degree day 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.
(4) 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 Washington Gas hedge to offset the effects of weather. As a result, colder or warmer weather will result in variances to financial results.
During the second quarter of 2019, AltaGas’ Utilities segment experienced similar weather at SEMCO and warmer weather at ENSTAR compared to the same quarter of 2018. Washington Gas experienced warmer than normal weather. The 2019 increase in customers and transportation represents the addition of Washington Gas natural gas deliveries.
During the first half of 2019, AltaGas’ Utilities segment experienced colder weather at SEMCO and warmer weather at ENSTAR compared to the same period of 2018. Washington Gas experienced warmer than normal weather. The 2019 increase in customers and transportation represents the addition of Washington Gas natural gas deliveries.
Service sites at June 30, 2019 increased by approximately 1.1 million sites compared to June 30, 2018 due to the addition of Washington Gas customers and growth in customer base, partially offset by service sites relating to the Canadian utilities which were included in the ACI IPO in the fourth quarter of 2018.
Three Months Ended June 30
The Utilities segment reported normalized EBITDA of $81 million in the second quarter of 2019, compared to $50 million in the same quarter in 2018. The increase in normalized EBITDA was mainly due to the addition of WGL ($41 million), the favorable impact of the stronger U.S. dollar, and lower operating expenses. The increase was partially offset by the impact of the ACI IPO in 2018 and warmer weather in Alaska.
Six Months Ended June 30
The Utilities segment reported normalized EBITDA of $422 million in the first half of 2019, compared to $162 million in the same period of 2018. The increase in normalized EBITDA was mainly due to the addition of WGL ($295 million), the favorable impact of the stronger U.S. dollar, growth in customer base, and colder weather in Michigan. The increase was partially offset by the impact of the ACI IPO in 2018, lower storage revenue at CINGSA, the 2019 revenue impact related to the federal tax reduction at the U.S. utilities, and warmer weather in Alaska.
Rate Case Updates
On May 15, 2018, Washington Gas filed an application with the Maryland Public Service Commission (PSC of MD) to increase its base rates for natural gas service for approximately US$56 million including approximately US$15 million in annual surcharges currently paid by customers for system upgrades. On December 11, 2018, the PSC of MD approved US$29 million in new revenues and increased the return on equity to 9.7 percent. The difference between the net amount requested of US$41 million and the amount approved of US$29 million was due to the disallowance of certain items. On January 10, 2019, Washington Gas requested a rehearing, alleging two errors in the agency’s final order. On June 25, 2019, the PSC of MD issued an order granting in part and denying in part Washington Gas’ application for a rehearing. Washington Gas is directed to file revised tariffs with an effective date of December 11, 2018, subject to acceptance by the PSC of MD.
On April 22, 2019, Washington Gas filed an application with the PSC of MD to increase base rates and charges for natural gas service for its Maryland customers. The change in proposed rates and charges includes an increase in base rates of approximately US$36 million, of which approximately US$5 million relates to costs being collected through the monthly STRIDE surcharges for system upgrades. Evidentiary hearing will take place at the end of August 2019 and a final decision from the PSC of MD is expected in November 2019.
On July 31, 2018, Washington Gas filed an application with the Virginia State Corporation Commission (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, subject to refund, in January 2019. Hearings occurred in the second quarter of 2019 with a decision expected in late 2019.
On December 7, 2018, Washington Gas filed an application with the PSC of DC for the phase 2 PROJECTpipes program requesting approval, by end of the third quarter of 2019, of approximately US$305 million in accelerated infrastructure replacement in the District of Columbia during the 2019 to 2024 period. In June 2019, in response to interveners petition for an extension of time to file testimony, the PSC of DC requested parties to submit scheduling proposals. In view of the expiry of the phase 1 PROJECTpipes program by the end of the third quarter of 2019, Washington Gas filed a proposed schedule that would allow for a PSC of DC decision by the end of 2019, and requested an extension of the phase 1 PROJECTpipes program until the requested date for final PSC of DC order approving the phase 2 PROJECTpipes program. Parties are waiting for a PSC of DC decision on process schedule.
The CINGSA rate case was filed in April 2018 based on a 2017 historical test year, reducing rates by US$4 million due to a lower rate base, lower returns on equity (ROE) and lower federal income tax. The rate case hearing occurred in May 2019 with a decision expected in the third quarter of 2019.
On May 31, 2019, SEMCO Gas filed a request with the Michigan Public Service Commission (MPSC) seeking authority to increase SEMCO Gas’s base rates by approximately US$38 million on an annual basis established with a forecasted test year of 2020. The increase in rates requested captures the inflation of operations and maintenance costs from the last rate case in 2010 as well as the investment in the Marquette Connector Pipeline. With the upcoming sunset of the Main Replacement Program (MRP) in 2020, this case includes the addition of a new MRP and the introduction of an Infrastructure Reliability Improvement Program (IRIP) to recover the capital costs associated with the replacement of certain mains, services, and other infrastructure through surcharges similar to the currently-enacted MRP program. The MPSC has a 10-month statutory requirement to rule in this case and as a result, the case is expected to be completed no later than March 31, 2020.
Midstream
Operating Statistics
|
| Three Months Ended |
| Six Months Ended |
| ||||
|
| 2019 |
| 2018 |
| 2019 |
| 2018 |
|
Extraction inlet gas processed (Mmcf/d)(1) |
| 980 |
| 769 |
| 979 |
| 926 |
|
FG&P inlet gas processed (Mmcf/d)(1) |
| 437 |
| 458 |
| 470 |
| 463 |
|
Total inlet gas processed (Mmcf/d)(1) |
| 1,417 |
| 1,227 |
| 1,449 |
| 1,389 |
|
Extraction ethane volumes (Bbls/d)(1) |
| 23,046 |
| 16,527 |
| 23,238 |
| 20,955 |
|
Extraction NGL volumes (Bbls/d)(1) (2) |
| 33,944 |
| 33,201 |
| 36,409 |
| 38,354 |
|
Total extraction volumes (Bbls/d)(1) (3) |
| 56,990 |
| 49,728 |
| 59,647 |
| 59,309 |
|
Frac spread - realized ($/Bbl)(1) (4) |
| 19.50 |
| 14.98 |
| 18.18 |
| 17.20 |
|
Frac spread - average spot price ($/Bbl)(1) (5) |
| 15.27 |
| 22.19 |
| 13.55 |
| 22.22 |
|
RIPET export volumes (MT)(6) |
| 109,966 |
| — |
| 109,966 |
| — |
|
Propane Far East Index (FEI) to Mont Belvieu spread (US$/MT)(7) |
| 177 |
| — |
| 177 |
| — |
|
Natural gas optimization inventory (Bcf) |
| 31.9 |
| — |
| 31.9 |
| — |
|
WGL retail energy marketing - gas sales volumes (Mmcf) |
| 9,360 |
| — |
| 36,770 |
| — |
|
(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, before accounting for hedges, divided by the respective frac exposed volumes for the period.
(6) Energy export volumes represents propane volumes exported at RIPET since facility was placed into service in May 2019.
(7) Average propane price spread between Argus Far East Index and Mont Belvieu TET commercial index for May and June 2019.
Inlet gas volumes processed at the extraction facilities for the second quarter of 2019 increased by 211 Mmcf/d compared to the same quarter of 2018. The increase was primarily due to plant turnarounds at Harmattan in May 2018 and at Joffre Ethane Extraction Plant (JEEP) and Pembina Empress Extraction Plant (PEEP) in June 2018, partially offset by reduced ownership at Younger effective April 2018. Inlet gas volumes processed at the field gathering and processing (FG&P) facilities for the second quarter of 2019 decreased by 21 Mmcf/d primarily due to the disposition of certain non-core facilities in the first quarter of 2019, partially offset by the recently acquired Aitken Creek North facility.
Inlet gas volumes processed at the extraction facilities for the first half of 2019 increased by 53 Mmcf/d compared to the same period of 2018. The increase was primarily due to plant turnarounds at Harmattan in May 2018 and at JEEP and PEEP in June 2018, partially offset by Younger due to operational issues upstream and reduced ownership effective April 2018. Inlet gas volumes processed at the FG&P facilities for the first half of 2019 increased by 7 Mmcf/d primarily due to higher volumes received at the Townsend facilities and the Aitken Creek North facility, partially offset by the disposition of certain non-core facilities in the first quarter of 2019.
Average ethane volumes for the second quarter of 2019 increased by 6,519 Bbls/d, while average NGL volumes increased by 743 Bbls/d compared to the same period in 2018. Higher ethane volumes were a result of plant turnarounds at Harmattan, JEEP and PEEP in second quarter of 2018, partially offset by rejecting production at Younger due to uneconomic pricing. Higher NGL volumes were a result of additional volumes available from the Townsend complex and plant turnarounds at Harmattan, JEEP and PEEP in the second quarter of 2018, partially offset by a lower ownership interest at Younger, the disposition of certain non-core facilities in the first quarter of 2019 and lower volumes at Gordondale.
Average ethane volumes for the first half of 2019 increased by 2,283 Bbls/d, while average NGL volumes decreased by 1,945 Bbls/d compared to the same period in 2018. Higher ethane volumes were a result of plant turnarounds at Harmattan, JEEP and PEEP in second quarter of 2018, partially offset by rejecting production at Younger due to uneconomic pricing. Lower NGL volumes were a result of a lower ownership interest at Younger, the disposition of certain non-core facilities in the first quarter of 2019 and lower volumes at Gordondale, partially offset by additional volumes available from the Townsend complex and plant turnarounds at Harmattan, JEEP and PEEP in the second quarter of 2018.
With RIPET commencing operations in the late May 2019, total propane volumes exported to Asia for the three and six months ended June 30, 2019 were 109,966 MT.
With the addition of WGL, for the three and six months ended June 30, 2019, U.S. retail sales volumes were 9,360 Mmcf and 36,770 Mmcf, respectively. Natural gas optimization inventory as at June 30, 2019 was 31.9 Bcf (December 31, 2018 - 35.9 Bcf).
Three Months Ended June 30
The Midstream segment reported normalized EBITDA of $97 million in the second quarter of 2019, compared to $48 million in the same quarter of 2018. The increase was mainly due to contributions from WGL Midstream assets of $21 million, contributions from RIPET which was placed in-service in May 2019, the acquisition of 50 percent ownership in Black Swan’s Aitken Creek North gas processing facility in the fourth quarter of 2018, higher realized frac spreads, and higher revenues at Harmattan due to increased NGL activities, partly offset by the disposition of certain non-core facilities in the first quarter of 2019, a one-time payment received in 2018 related to reduced ownership at Younger, and lower NGL marketing margins. During the second quarter of 2019, AltaGas recorded equity earnings of $11 million from Petrogas, compared to $1 million in the same quarter of 2018 mainly due to expanded activity levels in Petrogas’ core business units.
During the second quarter of 2019, AltaGas hedged approximately 6,228 Bbls/d of NGL volumes at an average price of $40/Bbl excluding basis differentials. During the second quarter of 2018, AltaGas hedged 7,500 Bbls/d of NGL at an average price of $33/Bbl, excluding basis differentials. The average indicative spot NGL frac spread for the second quarter of 2019 was approximately $15/Bbl, compared to $22/Bbl in the same quarter of 2018 inclusive of basis differentials. The realized frac spread of approximately $20/Bbl in the second quarter of 2019 (2018 - $15/Bbl) was higher than the same period in 2018 due to frac hedge gains. For RIPET, during the second quarter of 2019, AltaGas hedged approximately 58,676 MT of propane export volumes at the FEI to Mont Belvieu spread of US$137/MT.
During the second quarter of 2019. the Midstream segment recognized a pre-tax gain of $35 million on the disposition of the equity investment in Stonewall.
Six Months Ended June 30
The Midstream segment reported normalized EBITDA of $204 million in the first half of 2019, compared to $119 million in the same period of 2018. The increase in normalized EBITDA was due to contributions from WGL Midstream assets of $56 million, contributions from RIPET which was placed in-service in May 2019, the acquisition of 50 percent ownership in Black Swan’s Aitken Creek North gas processing facility in the fourth quarter of 2018, higher realized frac spreads (inclusive of hedges), and higher revenues at Harmattan due to increased NGL activities, partly offset by the disposition of certain non-core facilities in the first quarter of 2019, and lower frac exposed volumes primarily due to reduced ownership at Younger and lower marketing margins due to a weak spot market. During the first half of 2019, AltaGas recorded equity earnings of $34 million from Petrogas, compared to $11 million in the same period in 2018. The increase in Petrogas earnings was due to higher export volumes at Ferndale as a result of higher activity levels, a planned turnaround in the first quarter of 2018, and improved margins.
During the first half of 2019, AltaGas hedged approximately 6,228 Bbls/d of NGL volumes at an average price of $40/Bbl, excluding basis differentials. During the first half of 2018, AltaGas hedged 7,500 Bbls/d of NGL at an average price of $33/Bbl, excluding basis differentials. The average indicative spot NGL frac spread for first half of 2019 was approximately $14/Bbl compared to $22/Bbl in the same period of 2018. The realized frac spread of $18/Bbl in the first half of 2019 (2018 - $17/Bbl) was higher than the same period in 2018 due to frac hedge gains. For RIPET, during the first half of 2019, AltaGas hedged approximately 58,676 MT of propane export volumes at the FEI to Mont Belvieu spread of US$137/MT.
During the first half of 2019, AltaGas recognized a pre-tax gain of $5 million on the sale of remaining non-core Midstream processing facilities, and was also impacted by the previously mentioned gains recorded in the second quarter of 2019. In the first half of 2018, AltaGas recognized a pre-tax gain of $1 million on the sale of a non-core Midstream processing facility.
Power
Operating Statistics
|
| Three Months Ended |
| Six Months Ended |
| ||||
|
| 2019 |
| 2018 |
| 2019 |
| 2018 |
|
Renewable power sold (GWh) |
| 150 |
| 504 |
| 316 |
| 630 |
|
Conventional power sold (GWh) |
| 361 |
| 642 |
| 625 |
| 1,484 |
|
Renewable capacity factor (%) |
| 22.3 |
| 51.7 |
| 16.3 |
| 30.0 |
|
Contracted conventional equivalent availability factor (%) (1) |
| 66.7 |
| 97.7 |
| 54.9 |
| 96.6 |
|
WGL retail energy marketing - electricity sales volumes (GWh) |
| 3,125 |
| — |
| 6,205 |
| — |
|
(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 second quarter of 2019, the volume of renewable power sold decreased by 354 GWh and the volume of conventional power sold decreased by 281 GWh, compared to the same quarter in 2018. The decrease in renewable volumes was due to the January 2019 sale of the Northwest Hydro facilities and the October 2018 sale of the Bear Mountain wind facility to ACI, partially offset by the addition of WGL power generation. The decrease in conventional volumes sold was due to the November 2018 sale of the San Joaquin facilities and an extended planned outage at the Blythe facility.
The contracted conventional equivalent availability factor was lower for the second quarter of 2019 as a result of the extended planned outage at Blythe. The renewable capacity factor was lower for the second quarter of 2019 due to the sale of the Northwest Hydro facilities and the sale of the Bear Mountain wind facility, partially offset by the addition of WGL power generation.
During the first half of 2019, the volume of renewable power sold decreased by 314 GWh and the volume of conventional power sold decreased by 859 GWh. The change in volumes was due to the same reasons as noted above for the second quarter of 2019.
The variances related to the renewable capacity factor and contracted conventional availability factor for the first half of 2019 were due to the same factors as noted above for the second quarter of 2019.
For the three and six months ended June 30, 2019, U.S. retail sales volumes were 3,125 GWh and 6,205 GWh, respectively.
Three Months Ended June 30
The Power segment reported normalized EBITDA of $34 million during the second quarter of 2019, compared to $75 million in the same period of 2018. Normalized EBITDA decreased as a result of the impact of the January 2019 sale of the Northwest Hydro facilities, the impact of the sale of the San Joaquin facilities in November 2018, the impact of the ACI IPO, and the extended planned spring outage at the Blythe facility, partially offset by the addition of WGL ($15 million).
In the second quarter of 2019, AltaGas signed an agreement for the sale of its equity ownership interest in two biomass plants in the United States for proceeds of approximately US$20 million. The sale is expected to close in the third quarter of 2019, subject to regulatory approval. A provision of $2 million was recorded on these equity investments in the second quarter of 2019.
Also in the second quarter of 2019, a pre-tax provision of $1 million was recorded related to a capital spare turbine in storage which was classified as held for sale as at June 30, 2019. There were no provisions recorded in the Power segment in the second quarter of 2018.
Six Months Ended June 30
The Power segment reported normalized EBITDA of $61 million in the first half of 2019, compared to $116 million in the same period of 2018. Normalized EBITDA decreased as a result of the impact of the sale of the San Joaquin facilities in November 2018, the impact of the January 2019 sale of the Northwest Hydro facilities, the impact of the ACI IPO, and the extended planned outage at the Blythe facility, partially offset by the addition of WGL ($28 million).
During the first half of 2019, AltaGas recognized a pre-tax gain of $688 million on the sale of the remaining interest in the Northwest Hydro facilities. In addition, during the first half of 2019, the sale of Canadian non-core Power assets was completed resulting in a pre-tax loss of $6 million, and the sale of a WGL Energy Systems financing receivable was completed resulting in a pre-tax loss of $1 million.
In the first half of 2019, the Power segment was impacted by the previously mentioned provision recorded in the second quarter of 2019. There were no provisions recorded in the Power segment in the first half of 2018.
Corporate
Three Months Ended June 30
In the Corporate segment, normalized EBITDA for the second quarter of 2019 was a loss of $9 million, compared to a loss of $7 million in the same quarter of 2018. The increased loss was mainly due to higher information technology related costs.
Six Months ended June 30
In the Corporate segment, normalized EBITDA for the first half of 2019 was a loss of $18 million, compared to a loss of $9 million in the same period of 2018. The increased loss was a result of a number of factors including higher expenses related to employee incentive plans as a result of the increasing share price in the first half of 2019 and higher information technology related costs.
Invested Capital
|
| Three Months Ended |
| |||||||||||||
($ millions) |
| Utilities |
| Midstream |
| Power |
| Corporate |
| Total |
| |||||
Invested capital: |
|
|
|
|
|
|
|
|
|
|
| |||||
Property, plant and equipment |
| $ | 243 |
| $ | 107 |
| $ | 21 |
| $ | — |
| $ | 371 |
|
Intangible assets |
| 1 |
| 1 |
| — |
| 2 |
| 4 |
| |||||
Long-term investments |
| — |
| 50 |
| — |
| — |
| 50 |
| |||||
Contributions from non-controlling interest |
| — |
| (13 | ) | — |
| — |
| (13 | ) | |||||
Invested capital |
| 244 |
| 145 |
| 21 |
| 2 |
| 412 |
| |||||
Disposals: |
|
|
|
|
|
|
|
|
|
|
| |||||
Equity method investments |
| — |
| (379 | ) | — |
| — |
| (379 | ) | |||||
Net invested capital |
| $ | 244 |
| (234 | ) | $ | 21 |
| $ | 2 |
| $ | 33 |
| |
|
| Three Months Ended |
| |||||||||||||
($ millions) |
| Utilities |
| Midstream |
| Power |
| Corporate |
| Total |
| |||||
Invested capital: |
|
|
|
|
|
|
|
|
|
|
| |||||
Property, plant and equipment |
| $ | 54 |
| $ | 61 |
| $ | 9 |
| $ | 1 |
| $ | 125 |
|
Intangible assets |
| 1 |
| 2 |
| — |
| 1 |
| 4 |
| |||||
Contributions from non-controlling interest |
| — |
| (9 | ) | — |
| — |
| (9 | ) | |||||
Invested capital |
| 55 |
| 54 |
| 9 |
| 2 |
| 120 |
| |||||
Disposals: |
|
|
|
|
|
|
|
|
|
|
| |||||
Property, plant and equipment |
| — |
| (1 | ) | — |
| — |
| (1 | ) | |||||
Net invested capital |
| $ | 55 |
| $ | 53 |
| $ | 9 |
| $ | 2 |
| $ | 119 |
|
During the second quarter of 2019, AltaGas’ invested capital was $412 million, compared to $120 million in the same quarter of 2018. The increase in invested capital was primarily due to higher additions to property, plant and equipment and contributions to WGL’s investments in the Central Penn and Mountain Valley pipelines, partially offset by higher contributions from non-controlling interest (representing Vopak Development Canada Inc.’s share of construction costs related to RIPET).
The increase in additions to property, plant and equipment in the second quarter of 2019 was mainly due to capital expenditures related to system betterment and accelerated pipeline replacement programs at Washington Gas, construction costs at RIPET and Townsend 2B, and capital expenditures related to WGL’s distributed generation projects. The disposal of equity method investments related to the disposition of Stonewall in May 2019.
The invested capital in the second quarter of 2019 included maintenance capital of $1 million (2018 - $10 million) in the Midstream segment and $16 million (2018 - $7 million) in the Power segment. The decrease in maintenance capital for the Midstream segment was primarily due to reduced turnaround expenditures. The increase in maintenance capital for the Power segment was primarily due to planned turnaround maintenance capital at the Blythe facility.
|
| Six Months Ended |
| |||||||||||||
($ millions) |
| Utilities |
| Midstream |
| Power |
| Corporate |
| Total |
| |||||
Invested capital: |
|
|
|
|
|
|
|
|
|
|
| |||||
Property, plant and equipment |
| $ | 383 |
| $ | 181 |
| $ | 35 |
| $ | 1 |
| $ | 600 |
|
Intangible assets |
| 1 |
| 3 |
| — |
| 5 |
| 9 |
| |||||
Long-term investments |
| — |
| 135 |
| — |
| — |
| 135 |
| |||||
Contributions from non-controlling interest |
| — |
| (30 | ) | — |
| — |
| (30 | ) | |||||
Invested capital |
| 384 |
| 289 |
| 35 |
| 6 |
| 714 |
| |||||
Disposals: |
|
|
|
|
|
|
|
|
|
|
| |||||
Property, plant and equipment |
| — |
| (88 | ) | (1,341 | ) | — |
| (1,429 | ) | |||||
Equity method investments |
| — |
| (379 | ) | — |
| — |
| (379 | ) | |||||
Net invested capital |
| $ | 384 |
| $ | (178 | ) | $ | (1,306 | ) | $ | 6 |
| $ | (1,094 | ) |
|
| Six Months Ended |
| |||||||||||||
($ millions) |
| Utilities |
| Midstream |
| Power |
| Corporate |
| Total |
| |||||
Invested capital: |
|
|
|
|
|
|
|
|
|
|
| |||||
Property, plant and equipment |
| $ | 71 |
| $ | 115 |
| $ | 13 |
| $ | 1 |
| $ | 200 |
|
Intangible assets |
| 1 |
| 2 |
| 1 |
| 2 |
| 6 |
| |||||
Long-term investments |
| — |
| 19 |
| — |
| — |
| 19 |
| |||||
Contributions from non-controlling interest |
| — |
| (23 | ) | — |
| — |
| (23 | ) | |||||
Invested capital |
| 72 |
| 113 |
| 14 |
| 3 |
| 202 |
| |||||
Disposals: |
|
|
|
|
|
|
|
|
|
|
| |||||
Property, plant and equipment |
| — |
| (8 | ) | (2 | ) | — |
| (10 | ) | |||||
Net invested capital |
| $ | 72 |
| $ | 105 |
| $ | 12 |
| $ | 3 |
| $ | 192 |
|
During the first half of 2019, AltaGas’ invested capital was $714 million, compared to $202 million in the same period of 2018. The increase in invested capital in the first half of 2019 was mainly due to higher additions to property, plant and equipment and contributions to WGL’s investments in the Central Penn and Mountain Valley pipelines, partially offset by higher contributions from non-controlling interest (representing Vopak Development Canada Inc.’s share of construction costs related to RIPET).
The increase in additions to property, plant and equipment in the first half of 2019 was mainly due to capital expenditures related to system betterment and accelerated pipeline replacement programs at Washington Gas, construction costs at RIPET and Townsend 2B, and capital expenditures related to WGL’s distributed generation projects. The disposals of property, plant and equipment in the first half of 2019 primarily related to the Northwest Hydro facilities and non-core Canadian Midstream and Power assets, while in the first half of 2018 the disposals of property, plant and equipment related to non-core facilities in the Midstream segment and a development stage wind asset in the Power segment. The disposal of equity method investments related to the disposition of Stonewall in May 2019.
The invested capital in the first half of 2019 included maintenance capital of $1 million (2018 - $13 million) in the Midstream segment and $23 million (2018 - $9 million) in the Power segment. The variances in maintenance capital for the first half of 2019 was primarily due to the same factors impacting maintenance capital in the second quarter of 2019.
Risk Management
AltaGas is exposed to various market risks in the normal course of operations that could impact earnings and cash flows. AltaGas enters into physical and financial derivative contracts to manage exposure to fluctuations in commodity prices and foreign exchange rates, as well as to optimize certain owned and managed natural gas assets. The Board of Directors of AltaGas has established a risk management policy for the Corporation establishing AltaGas’ risk management control framework. Derivative
instruments are governed under, and subject to, this policy. As at June 30, 2019 and December 31, 2018, the fair values of the Corporation’s derivatives were as follows:
($ millions) |
| June 30, |
| December 31, |
| ||
Natural gas |
| $ | (94 | ) | $ | (137 | ) |
Energy exports |
| 8 |
| — |
| ||
NGL frac spread |
| 11 |
| 16 |
| ||
Power |
| (2 | ) | (9 | ) | ||
Foreign exchange |
| — |
| (1 | ) | ||
Net derivative liability |
| $ | (77 | ) | $ | (131 | ) |
Summary of Risk Management Contracts
Commodity Price Contracts
· The average indicative spot NGL frac spread for the six months ended June 30, 2019 was approximately $14/Bbl (2018 — $22/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 six months ended June 30, 2019 was approximately $18/Bbl inclusive of basis differentials (2018 - $17/Bbl).
· For 2019, AltaGas currently has frac hedges in place to hedge approximately 6,200 Bbls/d out of a total of approximately 10,000 Bbls/d at an average price of $40/Bbl, excluding basis differentials.
· At RIPET, AltaGas is exposed to the propane price differential between North American Indices and the Far East Index for contracts not under tolling arrangements. AltaGas estimates an average of approximately 29,000 Bbls/d will be exposed to these price differentials for the remainder of 2019. AltaGas has hedges in place for approximately 66 percent of these exposed propane volumes at an average FEI to Mont Belvieu spread of US$129/MT.
Foreign Exchange Contracts
· As at June 30, 2019, management has designated US$1.2 billion of outstanding U.S. dollar denominated long-term debt to hedge against the currency translation effect of its foreign investments (December 31, 2018 - US$1.5 billion).
· For the six months ended June 30, 2019, AltaGas incurred after-tax unrealized gains of $69 million arising from the translation of debt in other comprehensive income (2018 - nil).
Weather Instruments
· For the six months ended June 30, 2019, pre-tax gains of $1 million (2018 - nil) were recorded related to heating degree day (HDD) and cooling degree day (CDD) instruments.
The Effects of Derivative Instruments on the Consolidated Statements of Income
The following table presents the unrealized gains (losses) on derivative instruments as recorded in the Corporation’s Consolidated Statements of Income:
|
| Three Months Ended |
| Six Months Ended |
| ||||||||
($ millions) |
| 2019 |
| 2018 |
| 2019 |
| 2018 |
| ||||
Natural gas |
| $ | (5 | ) | $ | (5 | ) | $ | 8 |
| $ | (11 | ) |
Energy exports |
| (5 | ) | — |
| (7 | ) | — |
| ||||
NGL frac spread |
| 5 |
| (8 | ) | (5 | ) | 3 |
| ||||
Power |
| (8 | ) | (2 | ) | (3 | ) | (5 | ) | ||||
Foreign exchange |
| — |
| 37 |
| 1 |
| 36 |
| ||||
|
| $ | (13 | ) | $ | 22 |
| $ | (6 | ) | $ | 23 |
|
Please refer to Note 22 of the 2018 Annual Consolidated Financial Statements and Note 14 of the unaudited condensed interim Consolidated Financial Statements as at and for the three and six months ended June 30, 2019 for further details regarding AltaGas’ risk management activities.
Liquidity
As a result of certain commitments made to the PSC of DC, the PSC of MD, and the SCC of VA in respect of the WGL Acquisition, Washington Gas is subject to certain restrictions when paying dividends to AltaGas. However, AltaGas does not expect that this will have an impact on AltaGas’ ability to meet its obligations.
In addition, Wrangler SPE LLC and Washington Gas made certain ring fencing commitments to the PSC of DC, the PSC of MD and the SCC of VA with the intention of removing Washington Gas from the bankruptcy estate of AltaGas and its affiliates, other than Washington Gas and Wrangler SPE LLC (together, the “Ring Fenced Entities”). Because of these ring fencing measures, none of the assets of the Ring Fenced Entities would be available to satisfy the debt or contractual obligations of AltaGas or any non-Ring Fenced Entity Affiliate, including any indebtedness or other contractual obligations of AltaGas, and the Ring Fenced Entities do not bear any liability for indebtedness or other contractual obligations of any non-Ring Fenced Entity, and vice versa.
|
| Three Months Ended |
| Six Months Ended |
| ||||||||
($ millions) |
| 2019 |
| 2018 |
| 2019 |
| 2018 |
| ||||
Cash from operations |
| $ | 203 |
| $ | 147 |
| $ | 630 |
| $ | 336 |
|
Investing activities |
| 7 |
| (107 | ) | 1,187 |
| (196 | ) | ||||
Financing activities |
| (271 | ) | 642 |
| (1,898 | ) | 609 |
| ||||
Increase (decrease) in cash and cash equivalents |
| $ | (61 | ) | $ | 682 |
| $ | (81 | ) | $ | 749 |
|
Cash from Operations
Cash from operations increased by $294 million for the six months ended June 30, 2019 compared to the same period in 2018, primarily due to higher net income after taxes and a favorable variance in the net change in operating assets and liabilities. The majority of the variance in net change in operating assets and liabilities was due to increased cash flows from changes in accounts receivable due to seasonality at the Utilities, the lower price of gas, and asset sales completed in the first quarter of 2019, partially offset by decreased cash flows from accounts payable and accrued liabilities due to lower rates and volumes at the Utilities.
Working Capital
($ millions except current ratio) |
| June 30, |
| December 31, |
| ||
Current assets |
| $ | 2,656 |
| $ | 4,033 |
|
Current liabilities |
| 3,866 |
| 4,102 |
| ||
Working deficiency |
| $ | (1,210 | ) | $ | (69 | ) |
Working capital ratio (1) |
| 0.69 |
| 0.98 |
|
(1) Calculated as current assets divided by current liabilities.
The decrease in the working capital ratio was primarily due to decreases in assets held for sale, accounts receivable, inventory, and cash, and increases in the current portion of long-term debt, partially offset by decreases in accounts payable and accrued liabilities, short-term debt, and liabilities associated with assets held for sale. AltaGas’ working capital will fluctuate in the normal course of business. The working capital deficiency is expected to be funded using cash flow from operations, proceeds from asset sales, and available credit facilities as required.
Investing Activities
Cash from investing activities for the six months ended June 30, 2019 was $1.2 billion, compared to cash used in investing activities of $196 million in the same period in 2018. Investing activities for the six months ended June 30, 2019 primarily included proceeds of $1.8 billion from asset sales completed in the first half of 2019 (including the Northwest Hydro facilities, Stonewall, and non-core Canadian Midstream and Power assets) and proceeds of $74 million from the sale of a WGL Energy Systems financing receivable, partially offset by expenditures of approximately $561 million for property, plant, and equipment and intangible assets, and approximately $134 million of contributions to equity investments. Investing activities for the six months ended June 30, 2018 primarily included expenditures of approximately $195 million for property, plant, and equipment and approximately $19 million of contributions to AltaGas’ equity investments, partially offset by cash proceeds of approximately $23 million, net of transaction costs, primarily from the sale of non-core Midstream facilities and a wind asset, as well as the sale of an investment.
Financing Activities
Cash used in financing activities for the six months ended June 30, 2019 was $1.9 billion, compared to cash from financing activities of $609 million in the same period in 2018. Financing activities for the six months ended June 30, 2019 were primarily comprised of net repayments of short and long-term debt of $1.9 billion, net repayments under bankers’ acceptances of $0.5 billion, and dividends of $167 million, partially offset by draws on credit facilities of $0.6 billion, contributions from non-controlling interests of $36 million, and net proceeds from the issuance of common shares of $28 million (mainly from common shares issued through the DRIP). Financing activities for the six months ended June 30, 2018 were primarily comprised of proceeds from the sale of a non-controlling interest in the Northwest Hydro facilities of $921 million (net of transaction costs), net proceeds from the issuance of common shares of $135 million (mainly from shares issued through the DRIP), contributions from non-controlling interests of $23 million and net borrowings under bankers’ acceptances of $8 million, partially offset by repayments of long-term debt and short-term debt of $205 million and $48 million, respectively. Total dividends paid to common and preferred shareholders of AltaGas for the six months ended June 30, 2019 were $167 million (2018 - $227 million), of which $28 million was reinvested through the DRIP (2018 - $134 million). The decrease in dividends paid was due to the reduction in dividends on common shares declared in the fourth quarter of 2018, partially offset by more common shares outstanding.
Capital Resources
AltaGas’ objective for managing capital is to maintain its investment grade credit ratings, ensure adequate liquidity, optimize the profitability of its existing assets and grow its energy infrastructure to create long-term value and enhance returns for its investors. AltaGas’ capital structure is comprised of shareholders’ equity (including non-controlling interests), short-term and long-term debt (including the current portion) less cash and cash equivalents.
The use of debt or equity funding is based on AltaGas’ capital structure, which is determined by considering the norms and risks associated with operations and cash flow stability and sustainability.
($ millions) |
| June 30, |
| December 31, |
| ||
Short-term debt |
| $ | 738 |
| $ | 1,210 |
|
Current portion of long-term debt |
| 1,516 |
| 890 |
| ||
Long-term debt(1) |
| 5,864 |
| 8,067 |
| ||
Total debt |
| 8,118 |
| 10,167 |
| ||
Less: cash and cash equivalents |
| (46 | ) | (102 | ) | ||
Net debt |
| $ | 8,072 |
| $ | 10,065 |
|
Shareholders’ equity |
| 7,480 |
| 7,020 |
| ||
Non-controlling interests |
| 160 |
| 621 |
| ||
Total capitalization |
| $ | 15,712 |
| $ | 17,706 |
|
|
|
|
|
|
| ||
Net debt-to-total capitalization (%) |
| 51 |
| 57 |
|
(1) Net of debt issuance costs of $33 million as at June 30, 2019 (December 31, 2018 - $35 million).
As at June 30, 2019, AltaGas’ total debt primarily consisted of outstanding MTNs of $2.5 billion (December 31, 2018 - $2.7 billion), WGL and Washington Gas long-term debt of $2.6 billion, reflecting fair value adjustments on acquisition (December 31, 2018 - $2.7 billion), SEMCO long-term debt of $472 million (December 31, 2018 - $496 million), $1.8 billion drawn under the bank credit facilities (December 31, 2018 - $3.0 billion) and short-term debt of $0.7 billion (December 31, 2018 - $1.2 billion). In addition, AltaGas had $305 million of letters of credit outstanding (December 31, 2018 - $271 million).
As at June 30, 2019, AltaGas’ total market capitalization was approximately $5.5 billion based on approximately 277 million common shares outstanding and a closing trading price on June 30, 2019 of $19.81 per common share.
AltaGas’ earnings interest coverage for the rolling 12 months ended June 30, 2019 was 1.4 times (12 months ended June 30, 2018 — 1.4 times).
Credit Facilities
|
|
|
| Drawn at |
| Drawn at |
| |||
($ millions) |
| Borrowing |
| June 30, |
| December 31, |
| |||
AltaGas unsecured demand credit facilities (1) (2) |
| $ | 332 |
| $ | 134 |
| $ | 153 |
|
AltaGas unsecured extendible revolving letter of credit facilities (1) (2) |
| 543 |
| 162 |
| 117 |
| |||
AltaGas unsecured revolving credit facilities (1) (2) |
| 3,363 |
| 1,425 |
| 2,890 |
| |||
AltaGas bridge facility (1) (3) |
| — |
| — |
| 113 |
| |||
AltaGas unsecured term credit facility (1) (2) |
| 393 |
| 393 |
| — |
| |||
SEMCO Energy US$200 million unsecured credit facilities (1) (2) |
| 262 |
| 9 |
| 1 |
| |||
WGL US$650 million unsecured revolving credit facility (2) |
| 851 |
| — |
| — |
| |||
Washington Gas US$350 million unsecured revolving credit facility (2) (4) |
| 458 |
| — |
| — |
| |||
|
| $ | 6,202 |
| $ | 2,123 |
| $ | 3,274 |
|
(1) Amount drawn at June 30, 2019 converted at the month-end rate of 1 U.S. dollar = 1.3087 Canadian dollar (December 31, 2018 - 1 U.S. dollar = 1.3462 Canadian dollar).
(2) All US$ borrowing capacity was converted at the June 30, 2019 U.S./Canadian dollar month-end exchange rate.
(3) The remaining balance on the bridge facility was paid in full on February 1, 2019.
(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 June 30, 2019, commercial paper outstanding totaled US$510 million for WGL and Washington Gas (December 31, 2018 — US$840 million).
Effective July 19, 2019, WGL and Washington Gas amended and restated their unsecured, revolving credit facilities. The WGL facility was reduced from US$650 million to US$250 million for a period of three years. The Washington Gas facility was increased from US$350 million to US$450 million for a period of five years. The facilities both have a US$100 million accordion option and there were no changes to the financial covenants. The commercial paper programs supported by these facilities have been revised to match the new facility amounts.
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 |
| 51.3 | % |
Bank EBITDA-to-interest expense (1) (2) |
| not less than 2.5x |
| 2.7 |
|
Bank debt-to-capitalization (SEMCO)(3) |
| not greater than 60 percent |
| 35.6 | % |
Bank EBITDA-to-interest expense (SEMCO)(3) |
| not less than 2.25x |
| 7.3 |
|
Bank debt-to-capitalization (WGL)(4) |
| not greater than 65 percent |
| 54.0 | % |
Bank debt-to-capitalization (Washington Gas)(4) |
| not greater than 65 percent |
| 44.3 | % |
(1) Calculated in accordance with the Corporation’s US$1.2 billion credit facility agreement, which is available on SEDAR at www.sedar.com. The covenants are equivalent and applicable to all the Corporation’s committed credit facilities.
(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 $5.0 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 June 30, 2019, approximately $4.6 billion was available under the base shelf prospectus.
On June 4, 2018, a US$2.0 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 June 30, 2019, 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. There were no significant changes in the nature of the related party transactions described in Note 30 of the 2018 Annual Consolidated Financial Statements.
Share Information
|
| As at July 26, 2019 |
|
Issued and outstanding |
|
|
|
Common shares |
| 277,214,345 |
|
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 |
|
Washington Gas US$4.25 series |
| 150,000 |
|
Washington Gas US$4.80 series |
| 70,600 |
|
Washington Gas US$5.00 series |
| 60,000 |
|
Issued |
|
|
|
Share options |
| 7,701,091 |
|
Share options exercisable |
| 2,738,863 |
|
Dividends
AltaGas declares and pays a monthly dividend to its common shareholders. Dividends on preferred shares are paid quarterly. Dividends are at the discretion of the Board of Directors and dividend levels are reviewed periodically, giving consideration to the ongoing sustainable cash flow from operating activities, maintenance and growth capital expenditures, and debt repayment requirements of AltaGas.
The following table summarizes AltaGas’ dividend declaration history:
Dividends
Year ended December 31 |
|
|
|
|
| ||
($ per common share) |
| 2019 |
| 2018 |
| ||
First quarter |
| $ | 0.240000 |
| $ | 0.547500 |
|
Second quarter |
| 0.240000 |
| 0.547500 |
| ||
Third quarter |
| — |
| 0.547500 |
| ||
Fourth quarter |
| — |
| 0.445000 |
| ||
Total |
| $ | 0.480000 |
| $ | 2.087500 |
|
Series A Preferred Share Dividends
Year ended December 31 |
|
|
|
|
| ||
($ per preferred share) |
| 2019 |
| 2018 |
| ||
First quarter |
| $ | 0.211250 |
| $ | 0.211250 |
|
Second quarter |
| 0.211250 |
| 0.211250 |
| ||
Third quarter |
| — |
| 0.211250 |
| ||
Fourth quarter |
| — |
| 0.211250 |
| ||
Total |
| $ | 0.422500 |
| $ | 0.845000 |
|
Series B Preferred Share Dividends
Year ended December 31 |
|
|
|
|
| ||
($ per preferred share) |
| 2019 |
| 2018 |
| ||
First quarter |
| $ | 0.269380 |
| $ | 0.217600 |
|
Second quarter |
| 0.270510 |
| 0.238720 |
| ||
Third quarter |
| — |
| 0.249530 |
| ||
Fourth quarter |
| — |
| 0.262770 |
| ||
Total |
| $ | 0.539890 |
| $ | 0.968620 |
|
Series C Preferred Share Dividends
Year ended December 31 |
|
|
|
|
| ||
(US$ per preferred share) |
| 2019 |
| 2018 |
| ||
First quarter |
| $ | 0.330625 |
| $ | 0.330625 |
|
Second quarter |
| 0.330625 |
| 0.330625 |
| ||
Third quarter |
| — |
| 0.330625 |
| ||
Fourth quarter |
| — |
| 0.330625 |
| ||
Total |
| $ | 0.661250 |
| $ | 1.322500 |
|
Series E Preferred Share Dividends
Year ended December 31 |
|
|
|
|
| ||
($ per preferred share) |
| 2019 |
| 2018 |
| ||
First quarter |
| $ | 0.337063 |
| $ | 0.312500 |
|
Second quarter |
| 0.337063 |
| 0.312500 |
| ||
Third quarter |
| — |
| 0.312500 |
| ||
Fourth quarter |
| — |
| 0.312500 |
| ||
Total |
| $ | 0.674126 |
| $ | 1.250000 |
|
Series G Preferred Share Dividends
Year ended December 31 |
|
|
|
|
| ||
($ per preferred share) |
| 2019 |
| 2018 |
| ||
First quarter |
| $ | 0.296875 |
| $ | 0.296875 |
|
Second quarter |
| 0.296875 |
| 0.296875 |
| ||
Third quarter |
| — |
| 0.296875 |
| ||
Fourth quarter |
| — |
| 0.296875 |
| ||
Total |
| $ | 0.593750 |
| $ | 1.187500 |
|
Series I Preferred Share Dividends
Year ended December 31 |
|
|
|
|
| ||
($ per preferred share) |
| 2019 |
| 2018 |
| ||
First quarter |
| $ | 0.328125 |
| $ | 0.328125 |
|
Second quarter |
| 0.328125 |
| 0.328125 |
| ||
Third quarter |
| — |
| 0.328125 |
| ||
Fourth quarter |
| — |
| 0.328125 |
| ||
Total |
| $ | 0.656250 |
| $ | 1.312500 |
|
Series K Preferred Share Dividends
Year ended December 31 |
|
|
|
|
| ||
($ per preferred share) |
| 2019 |
| 2018 |
| ||
First quarter |
| $ | 0.312500 |
| $ | 0.312500 |
|
Second quarter |
| 0.312500 |
| 0.312500 |
| ||
Third quarter |
| — |
| 0.312500 |
| ||
Fourth quarter |
| — |
| 0.312500 |
| ||
Total |
| $ | 0.625000 |
| $ | 1.250000 |
|
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 June 30, 2019 were as follows:
US$4.25 series Preferred Share Dividends
Year ended December 31 |
|
|
|
|
| ||
(US$ per preferred share) |
| 2019 |
| 2018 |
| ||
First quarter |
| $ | 1.062500 |
| $ | — |
|
Second quarter |
| 1.062500 |
| — |
| ||
Third quarter |
| — |
| 1.062500 |
| ||
Fourth quarter |
| — |
| 1.062500 |
| ||
Total |
| $ | 2.125000 |
| $ | 2.125000 |
|
US$4.80 series Preferred Share Dividends
Year ended December 31 |
|
|
|
|
| ||
(US$ per preferred share) |
| 2019 |
| 2018 |
| ||
First quarter |
| $ | 1.200000 |
| $ | — |
|
Second quarter |
| 1.200000 |
| — |
| ||
Third quarter |
| — |
| 1.200000 |
| ||
Fourth quarter |
| — |
| 1.200000 |
| ||
Total |
| $ | 2.400000 |
| $ | 2.400000 |
|
US$5.00 series Preferred Share Dividends
Year ended December 31 |
|
|
|
|
| ||
(US$ per preferred share) |
| 2019 |
| 2018 |
| ||
First quarter |
| $ | 1.250000 |
| $ | — |
|
Second quarter |
| 1.250000 |
| — |
| ||
Third quarter |
| — |
| 1.250000 |
| ||
Fourth quarter |
| — |
| 1.250000 |
| ||
Total |
| $ | 2.500000 |
| $ | 2.500000 |
|
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 2018 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 relate to revenue recognition, financial instruments, depreciation and amortization expense, accounting for leases, 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 2018 Annual Consolidated Financial Statements and MD&A and Note 2 of the unaudited condensed interim Consolidated Financial Statements as at and for the three and six months ended June 30, 2019.
Adoption of New Accounting Standards
Effective January 1, 2019, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU):
· ASU No. 2016-02 “Leases” and all related amendments (collectively “ASC 842”). AltaGas has applied ASC 842 using the modified retrospective approach as of the effective date of the new standard. Comparative information has not been restated and continues to be reported under the previous lease guidance ASC 840. AltaGas has applied the package of transition practical expedients which permitted the Corporation to not reassess (a) whether any expired or existing contracts contain leases, (b) lease classifications for any expired or existing leases, and (c) initial direct costs for any existing leases. In addition, AltaGas applied the transition practical expedient that permitted the Corporation to grandfather its accounting policy for land easements that existed as of, or expired, before January 1, 2019. The transition practical expedient to not separate lease and non-lease components for its building, office equipment, transportation equipment and vehicle leases has been elected for lessee arrangements. The transition practical expedient to not separate lease and non-lease components for its lessor arrangements related to Power assets and Midstream processing facilities has also been elected. AltaGas has applied the short term lease recognition exemption under which lease arrangements with a term of twelve months or less, including extension options that are reasonably certain of being exercised, are exempt from the recognition of a right of use asset and lease liability and recorded as an expense over the term of the lease. This exemption applies to all classes of assets.
On adoption of ASC 842, all operating leases were recognized on the balance sheet. The adoption resulted in an increase to long-term assets of approximately $181.0 million and an increase to long-term liabilities of approximately $170.5 million (net of the current portion that is recorded in current liabilities of approximately $23.3 million). The lease related liabilities were measured using the present value of the remaining minimum lease payments for existing leases discounted using the Corporation’s incremental borrowing rate as of January 1, 2019. For operating leases, the associated right-of-use assets were measured at the amount equal to the lease liabilities on January 1, 2019, adjusted for any prepaid or accrued lease payments and the remaining balance of any lease incentives received. The adoption of ASC 842 did not impact lessor accounting, the consolidated statement of income, or the consolidated statement of cash flow.
Please also refer to Note 15 of the unaudited condensed interim Consolidated Financial Statements as at and for the six months ended June 30, 2019 for further details;
· ASU No. 2017-08 “Receivables — Nonrefundable Fees and Other Costs: Premium Amortization on Purchased Callable Debt Securities. The amendments in this ASU shorten the amortization period for certain callable debt securities held at a premium. Specifically, the amendments require the premium to be amortized to the earliest call date. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;
· ASU No. 2017-11 “Earnings per Share and Derivatives and Hedging — Distinguishing Liabilities from Equity: Accounting for Certain Financial Instruments with Down Round Features, Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Non-controlling
Interests with a Scope Exception”. The amendments in this ASU simplify the accounting for certain equity-linked financial instruments and embedded features with down round features that reduce the exercise price when pricing of a future round of financing is lower. The amendments in this ASU also require entities that present EPS under ASC 260 to recognize the effect of a down round feature in a freestanding equity-classified financial instrument only when it is triggered. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;
· 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 adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;
· ASU No. 2018-08 “Not-for-Profit-Entities — Clarifying the Scope and the Accounting Guidance for Contributions Received and Contributions Made”. The amendments in this ASU clarify whether a transfer of assets is a contribution or an exchange transaction. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;
· 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 adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;
· ASU No. 2018-16 “Derivatives and Hedging: Inclusion of the Second Overnight Financing Rate (SOFR) Overnight Index Swap (OIS) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes”. The amendments in this ASU permit the use of Overhead Index Swap (OIS) rate based on SOFR as a U.S. benchmark interest rate for hedge accounting purposes. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements.
Future Changes in Accounting Principles
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 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 post-retirement 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 October 2018, FASB issued ASU No. 2018-17 “Consolidation: Targeted Improvements to Related Party Guidance for Variable Interest Entities”. The amendments in this ASU provide a private-company scope exception to the VIE guidance for certain entities and clarify that indirect interest held through related parties under common control will be considered on a proportional basis when determining whether fees paid to decision makers and service providers are variable interests. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. An entity should apply the amendments retrospectively with a cumulative-effect adjustment to retained earnings at the beginning of the earliest period presented. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.
In March 2019, FASB issued ASU No. 2019-01 “Leases: Codification Improvements”. The amendments in this ASU provide a fair value exception for lessors that are not manufacturers or dealers, clarify the presentation of principal payments received under sales-type and direct finance leases on the statements of cash flows, and clarify transition disclosure requirements for the adoption of ASC 842. The amendments on the fair value exception and on the presentation on the statement of cash flows are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted. The amendment on the transition disclosure requirement is effective upon adoption of ASC 842. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.
In April 2019, FASB issued ASU No. 2019-04 “Financial Instruments - Credit Losses, Derivatives and Hedging, and Codification Improvements”. The amendments in this ASU provide clarification and improve the codification in recently issued accounting standards on credit losses (ASU 2016-13), hedging (ASU 2017-12), and recognizing and measuring financial instruments (ASU 2016-01). The amendments related to credit losses have the same effective date and transition requirements as ASU 2016-13, the amendments related to hedge accounting are effective as of the beginning of the first annual period beginning after issuance of this ASU and may be applied retrospectively to the date ASU 2017-12 was adopted or prospectively with some exceptions, and the amendments related to financial instruments are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.
In May 2019, FASB issued ASU No. 2019-05 “Financial Instruments - Credit Losses: Targeted Transition Relief”. The amendments in this ASU provide entities that have certain instruments within the scope of Subtopic 326-20 - Financial Instruments - Credit Losses - Measured at Amortized Cost (other than held-to-maturity debt securities) a one-time irrevocable option to elect fair value treatment on an eligible instrument-by-instrument basis. The effective date and transition methodology for the amendments in this ASU are the same as ASU 2016-13. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.
Off-Balance Sheet Arrangements
AltaGas did not enter into any material off-balance sheet arrangements during the six months ended June 30, 2019. Reference should be made to the audited Consolidated Financial Statements and MD&A as at and for the year ended December 31, 2018 for further information on off-balance sheet arrangements.
Disclosure Controls and Procedures (DCP) and Internal Control Over Financial Reporting (ICFR)
Management, including the Chief Executive Officer 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 Chief Executive Officer 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).
During the second quarter of 2019, there were no changes made to AltaGas’ ICFR 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.
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 Utilities and Midstream business segments seeking optimal capital deployment. In the Midstream 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 invest in U.S. utilities located in strong growth markets with increasing capital deployment to support customer additions, system improvement and accelerated replacement programs. AltaGas has three business segments:
· Utilities, which serves approximately 1.6 million customers with a rate base of approximately US$3.6 billion through ownership of regulated natural gas distribution utilities across five jurisdictions in the United States and two regulated natural gas storage utilities in the United States, delivering clean and affordable natural gas to homes and businesses. The Utilities business also includes storage facilities and contracts for interstate natural gas transportation and storage services;
· Midstream, which includes a 70 percent interest in the recently completed Ridley Island Propane Export Terminal, allowing AltaGas to leverage its assets along the energy value chain in Western Canada including natural gas gathering and processing, natural gas liquids (NGL) extraction and fractionation, and natural gas and NGL marketing. The Midstream segment also includes transmission, storage, an interest in three regulated pipelines in the Marcellus/Utica gas formation in the northeastern United States, WGL’s retail gas marketing business, the Corporation’s 50 percent interest in AltaGas Idemitsu Joint Venture Limited Partnership (AIJVLP), and an indirectly held one-third ownership investment in Petrogas Energy Corp. (Petrogas), through which AltaGas’ interest in the Ferndale Terminal is held; and
· Power, which includes 1,102 MW of operational gross capacity from natural gas-fired, biomass, solar, other distributed generation and energy storage assets, certain of which are pending sale, located in Alberta, Canada and 20 states and the District of Columbia in the United States. The Power business also includes energy efficiency contracting and WGL’s retail power marketing business.
Summary of Consolidated Results for the Eight Most Recent Quarters (1)
($ millions) |
| Q2-19 |
| Q1-19 |
| Q4-18 |
| Q3-18 |
| Q2-18 |
| Q1-18 |
| Q4-17 |
| Q3-17 |
|
Total revenue |
| 1,174 |
| 1,898 |
| 1,727 |
| 1,041 |
| 610 |
| 878 |
| 745 |
| 502 |
|
Normalized EBITDA(2) |
| 203 |
| 466 |
| 394 |
| 226 |
| 166 |
| 223 |
| 213 |
| 190 |
|
Net income (loss) applicable to common shares |
| 41 |
| 809 |
| 174 |
| (726 | ) | 1 |
| 49 |
| (11 | ) | 18 |
|
($ per share) |
| Q2-19 |
| Q1-19 |
| Q4-18 |
| Q3-18 |
| Q2-18 |
| Q1-18 |
| Q4-17 |
| Q3-17 |
|
Net income (loss) per common share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
| 0.15 |
| 2.93 |
| 0.64 |
| (2.78 | ) | 0.01 |
| 0.28 |
| (0.06 | ) | 0.10 |
|
Diluted |
| 0.15 |
| 2.93 |
| 0.64 |
| (2.78 | ) | 0.01 |
| 0.28 |
| (0.06 | ) | 0.10 |
|
Dividends declared |
| 0.24 |
| 0.24 |
| 0.45 |
| 0.55 |
| 0.55 |
| 0.55 |
| 0.54 |
| 0.53 |
|
(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.
Other significant items that impacted quarter-over-quarter revenue during the periods noted include:
· Revenue from WGL after the acquisition closed in the third quarter of 2018;
· The weak Alberta power pool prices throughout 2017;
· 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, throughout 2018, and the first quarter of 2019;
· 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 the Tax Cuts and Jobs Act (TCJA) at the U.S. utilities throughout 2018 and the first half of 2019;
· The impact of the sale of non-core U.S. Power assets in the fourth quarter of 2018;
· The impact of the sale of the Canadian utilities to ACI in the fourth quarter of 2018;
· The impact of the sale of the Northwest Hydro facilities and non-core Canadian Midstream and Power assets in the first quarter of 2019; and
· RIPET entering commercial service in the second quarter of 2019.
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 long-term 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:
· The impact of WGL income for the period after the close of the acquisition on July 6, 2018;
· Higher depreciation and amortization expense due to new assets placed into service;
· 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 Midstream processing facility in Alberta, and a non-core development stage peaking project in California;
· Impact of the TCJA 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 2018 ($50 million) predominantly due to the WGL Acquisition;
· After-tax merger commitment costs of $135 million associated with the WGL Acquisition recorded in the second half of 2018;
· After-tax provisions of approximately $562 million recognized in 2018 primarily related to assets held for sale;
· An income tax recovery of approximately $104 million related to the Northwest Hydro facilities held for sale classification at December 31, 2018;
· The impact of the sale of non-core U.S. Power assets in the fourth quarter of 2018;
· The impact of the sale of the Canadian utilities to ACI in the fourth quarter of 2018; and
· The impact of the sale of the Northwest Hydro facilities and non-core Canadian Midstream and Power assets in the first quarter of 2019.