CALGARY, ALBERTA–(Marketwired – April 26, 2017) –
(all financial figures are unaudited and in Canadian dollars unless otherwise noted)
- Achieved record normalized EBITDA1 of $228 million in the first quarter of 2017, a 28 percent increase compared to the same quarter of 2016;
- Increased normalized funds from operations1 by approximately 29 percent to $170 million in the first quarter of 2017;
- Announced transformational $8.4 billion pending acquisition of WGL Holdings, Inc. (WGL Acquisition) on January 25, 2017, and submitted regulatory applications to the public utility commissions in Maryland, Virginia and Washington D.C. on April 24, 2017;
- Commenced construction of the 99 Mmcf/d Townsend 2a shallow-cut processing facility and continue to advance discussions with other producers to backstop the second train of Townsend Phase 2;
- Made significant progress on the first train of the North Pine NGL Separation Facility, accelerating the expected in-service date of the facility to the first quarter of 2018; and
- Announced a positive Final Investment Decision (FID) on the Ridley Island Propane Export Terminal on January 3, 2017. Site preparation and pre-construction activities are underway, construction is expected to begin in the second quarter of 2017 and the terminal is being designed to ship 40,000 Bbls/d of propane to global markets off the west coast of Canada.
AltaGas Ltd. (AltaGas) (TSX:ALA) today reported that normalized EBITDA in the first quarter of 2017 increased $50 million to $228 million, compared to the same quarter in 2016. Normalized funds from operations were $170 million ($1.01 per share) for the first quarter of 2017, compared to $132 million ($0.90 per share) in the same period of 2016. On a U.S. GAAP basis, net income applicable to common shares for the first quarter of 2017 was $32 million ($0.19 per share) compared to $55 million ($0.38 per share) in the first quarter of 2016. Normalized net income1 was $65 million ($0.39 per share) for the first quarter of 2017, compared to $38 million ($0.26 per share) in the same period of 2016.
“During the first quarter of 2017, we realized substantial growth in normalized EBITDA and funds from operations, showcasing our diversified and highly contracted asset base and putting us on track to achieve high single digit percentage growth over 2016. We also started construction on over $750 million of strategic projects, including pre-construction activities on our Ridley Island Propane Export Terminal, as part of our northeast B.C. and energy export strategies,” said David Harris, President and Chief Executive Officer of AltaGas. “We are also very excited about the pending acquisition of WGL that will provide us with a robust, complementary set of high quality, low-risk, long-lived assets that complement each of our energy segments and greatly increase our scale and diversity. Both companies are working diligently toward closing the acquisition with the submission of the local and federal regulatory filings having been completed on April 24. This marks an important step toward an exciting future with WGL where we expect to have approximately $22 billion in combined assets and over $7 billion of highly attractive organic growth opportunities upon closing.”
The first quarter of 2017 was driven by strong performance across AltaGas’ three business segments. Normalized EBITDA in the quarter increased 28 percent to $228 million as compared to $178 million for the same quarter of 2016. The Gas segment benefitted from the commencement of commercial operations at the Townsend Facility in the third quarter of 2016, higher earnings from Petrogas Energy Corp. (Petrogas) including the dividend income from the Petrogas Preferred Shares, higher revenue from NGL marketing, higher realized frac spreads and processed volumes, and higher natural gas storage margins. Results for the Utilities were positively impacted by colder weather experienced at certain of the Utilities and the interim and refundable rate increases at ENSTAR. The Power segment benefitted from a full quarter of contributions from the Pomona Energy Storage Facility which commenced commercial operations on December 31, 2016, and the absence of equity losses from the Sundance B PPAs. These increases were partially offset by the weaker U.S. dollar on reported results of the U.S. assets.
Normalized funds from operations were $170 million ($1.01 per share) in the first quarter of 2017, up from $132 million ($0.90 per share) in the first quarter of 2016. The increase was driven by the increase in normalized EBITDA, partially offset by higher interest expense and lower common share dividends from Petrogas.
For the first quarter of 2017, AltaGas recorded income tax expense of $21 million compared to $6 million in the same quarter of 2016. The increase was primarily due to the $10 million tax recovery related to the Tidewater Gas Asset Disposition in the first quarter of 2016 and a portion of transaction costs incurred on the pending WGL Acquisition in the first quarter of 2017 not being tax deductible.
On a U.S. GAAP basis, net income applicable to common shares for the first quarter of 2017 was $32 million ($0.19 per share) compared to $55 million ($0.38 per share) for the same quarter in 2016. The decrease was mainly due to the transaction costs incurred on the pending WGL Acquisition and higher income tax, interest, depreciation and amortization expense, partially offset by the previously referenced factors resulting in the increase in normalized EBITDA. In addition, net income per common share decreased for the three months ended March 31, 2017, compared to the same period in 2016, as a result of the same factors impacting net income, as well as a higher number of common shares outstanding in 2017.
Normalized net income was $65 million ($0.39 per share) for the first quarter of 2017, compared to $38 million ($0.26 per share) reported for the same quarter in 2016. The increase was driven by the same factors impacting normalized EBITDA, partially offset by higher income tax, interest, and depreciation and amortization expense. Normalizing items in the first quarter of 2017 included after-tax amounts related to transaction costs on acquisitions, unrealized gains on risk management contracts, loss on sale of assets, and amortization of financing costs associated with the bridge facility. In the first quarter of 2016, normalizing items included after-tax amounts related to transaction costs incurred on acquisitions, unrealized gains on risk management contracts, gains on sale of assets and related tax recovery, provision on investment accounted for by the equity method, and dilution loss recognized on investment accounted for by the equity method.
1 Non-GAAP measure; see discussion in the advisories of this news release
Pending Acquisition of WGL Holdings, Inc.
On January 25, 2017, AltaGas entered into a definitive agreement to indirectly acquire WGL Holdings, Inc. (WGL). Pursuant to the Merger Agreement, following the consummation of the WGL Acquisition, WGL common shareholders will receive US$88.25 per common share in cash, which represents a total enterprise value of US$6.8 billion, including the assumption of approximately US$2.1 billion of debt as at December 31, 2016.
WGL is a diversified energy infrastructure company and the sole common shareholder of Washington Gas Light Company (Washington Gas), a regulated natural gas utility headquartered in Washington, D.C., serving more than 1.1 million customers in Maryland, Virginia, and the District of Columbia. WGL has a growing midstream business with investments in natural gas gathering infrastructure and regulated gas pipelines in the Marcellus/Utica gas formation located in the northeast United States with capabilities for connections to marine-based energy export opportunities via the North American Atlantic coast through the proposed Cove Point LNG terminal in Maryland being developed by a third party, currently expected to be operational in late 2017. WGL also owns contracted clean power assets, with a focus on distributed generation and energy efficiency assets throughout the United States. In addition, WGL has a retail gas and power marketing business with approximately 260,000 customers in Maryland, Virginia, Delaware, Pennsylvania and the District of Columbia. Upon completion of the WGL Acquisition, AltaGas will have over $22 billion of assets and more than 1.7 million rate regulated gas customers.
“Our success has been driven by our commitment to clean energy infrastructure assets in Midstream, Power and Utilities, and by maintaining a balance over the long-term in these three segments,” said Harris. “WGL also has significant investments in Midstream, Power and Utilities and is a highly diversified business. This is why WGL is attractive to AltaGas.”
The WGL Acquisition is not subject to any financing contingency. AltaGas expects that cash to close the WGL Acquisition will be provided from a combination of the net proceeds from the $400 million private placement of subscription receipts and the $2.2 billion bought deal subscription receipt offering (including the partially exercised over-allotment option) for total gross proceeds of approximately $2.6 billion, subsequent offerings of senior debt, hybrid securities, equity or equity-linked securities (including Preferred Shares or convertible debentures), selected AltaGas asset sales and through a fully committed approximately US$3.0 billion bridge facility, which would be available for 12 to 18 months following closing of the WGL Acquisition. AltaGas believes there are a number of attractive, actionable opportunities to monetize certain of its assets in a manner which supports the Corporation’s long term strategy of growing in attractive areas and maintaining a long term, balanced mix of energy infrastructure assets across its Gas, Power and Utility business segments. The timing of these subsequent offerings and asset sales is subject to prevailing market conditions, but are generally expected to be completed prior to the closing of the WGL Acquisition.
The WGL Acquisition is subject to certain closing conditions, including approval of WGL common shareholders and certain regulatory and government review and/or approvals, including the Public Service Commission of the District of Columbia (PSC of DC), the Maryland Public Service Commission (PSC of MD), the Commonwealth of Virginia State Corporation Commission (SCC of VA), the United States Federal Energy Regulatory Commission (FERC), and the Committee on Foreign Investment in the United States (CFIUS), as well as expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.
The special meeting of WGL common shareholders to approve the WGL Acquisition is scheduled for May 10, 2017. In addition, regulatory applications were filed with the PSC of DC, the PSC of MD, the SCC of VA, FERC and CFIUS on April 24, 2017. All decisions are expected to be received in the first half of 2018.
Based on projects currently under review, development or construction, AltaGas expects capital expenditures in the range of $600 to $650 million for 2017. AltaGas’ Gas segment will account for approximately 65 to 75 percent of total capital expenditures, while AltaGas’ Utility segment will account for approximately 20 to 25 percent and the Power segment will account for approximately 5 to 10 percent. Gas and Power maintenance capital is expected to be approximately $25 to $35 million of total capital expenditures in 2017. The majority of AltaGas’ capital expenditures relating to its Gas segment will be allocated towards AltaGas’ growth projects including the Ridley Island Propane Export Terminal, the first train of Townsend Phase 2, the North Pine Facility, and the North Pine Pipelines.
AltaGas’ 2017 committed capital program is expected to be funded through internally-generated cash flow and the Premium Dividend™, Dividend Reinvestment and Optional Cash Purchase Plan (DRIP). If required, the Corporation also has approximately $1.9 billion available under its credit facilities as at March 31, 2017, as well as access to capital markets.
™ denotes trademark of Canaccord Genuity Corp.
Townsend Gas Processing Facility Expansion (Townsend Phase 2)
On February 22, 2017, the Board of Directors approved a positive FID for the first train of Townsend Phase 2 (Townsend 2A). Townsend 2A will be a 99 Mmcf/d shallow-cut gas processing facility to be located on the existing Townsend site, adjacent to the currently operating Townsend Facility. The estimated cost of Townsend 2A is expected to be approximately $80 million and with the addition of incremental field compression equipment to move raw gas production from the Blair Creek area to Townsend, the estimated total cost is expected to be approximately $120 to $140 million. NGL produced from Townsend Phase 2 is expected to be transported to AltaGas’ North Pine Facility via existing and planned pipelines owned by AltaGas. Fabrication is underway on several components of Townsend 2A as well as on the incremental field compression equipment. Commercial operation for Townsend 2A is expected to begin in October 2017. AltaGas and Painted Pony Petroleum Ltd. (Painted Pony) have entered into 20-year take-or-pay agreements in respect of Townsend 2A and the incremental field compression equipment, subject to the satisfaction of certain conditions contained in the agreements.
North Pine NGL Project
On October 19, 2016, the Board of Directors approved a positive FID for the construction, ownership and operation of the North Pine Facility to be located approximately 40 km northwest of Fort St. John, British Columbia. The North Pine Facility will be connected to existing AltaGas infrastructure in the region and will have access to the CN rail network, allowing for the transportation of propane from the North Pine Facility to the Ridley Island Propane Export Terminal. AltaGas will be constructing the North Pine Facility with two separate NGL separation trains, each capable of processing up to 10,000 Bbls/d of propane plus NGL mix (C3+), for a total of 20,000 Bbls/d. The first phase will also include 6,000 Bbls/d of condensate (C5+) terminalling capacity, with ultimate capacity for up to 20,000 Bbls/d. The second 10,000 Bbls/d NGL separation train is expected to follow after completion of the first train, subject to sufficient commercial support from area producers.
Two eight inch diameter NGL supply pipelines (the North Pine Pipelines), each approximately 40 km in length, will also be constructed to connect AltaGas’ existing Alaska Highway truck terminal (the Truck Terminal) to the North Pine Facility. One supply line will carry C3+ with the other carrying C5+. The existing Townsend NGL Egress Pipelines currently delivering product from AltaGas’ Townsend Facility will be connected to the North Pine Pipelines to enable shipment of NGL produced at the Townsend Facility directly to the North Pine Facility via the Truck Terminal. Logging, clearing and mulching activities have been completed and civil construction activities will commence in the second quarter of 2017. The target commercial on-stream date for the North Pine Facility and the North Pine Pipelines is expected in the first quarter of 2018, up from the second quarter of 2018.
The capital cost of the first train and associated pipelines is estimated to be approximately $125 to $135 million. This investment will be backstopped by long-term supply agreements with Painted Pony for a portion of the total capacity, and will include dedication of all of Painted Pony’s NGL produced at the Townsend and Blair Creek facilities.
Ridley Island Propane Export Terminal
On January 3, 2017, AltaGas reached a positive FID on the Ridley Island Propane Export Terminal, having received approval from federal regulators. AltaGas has executed long-term agreements securing land tenure along with rail and marine infrastructure on Ridley Island.
The Ridley Island Propane Export Terminal is expected to be the first propane export facility off the west coast of Canada. The site is near Prince Rupert, British Columbia, on a section of land leased by Ridley Terminals Inc. (RTI) from the Prince Rupert Port Authority (PRPA). The site has a locational advantage given very short shipping distances to markets in Asia, notably a 10-day shipping time compared to 25-days from the U.S. Gulf Coast. The brownfield site also benefits from excellent railway access and ample deep water access to the Pacific Ocean. AltaGas’ arrangements with RTI give AltaGas access to extensive land and water rights and a world class marine jetty which allows for the efficient loading of Very Large Gas Carriers that can access key global markets. Propane from British Columbia and Alberta will be transported to the facility using the existing CN rail network. The Ridley Island Propane Export Terminal is estimated to cost approximately $450 to $500 million and is to be designed to ship 1.2 million tonnes of propane per annum. AltaGas has offered a third party the option to take an equity position of up to 30 percent in the Ridley Island Propane Export Terminal. A decision from the third party is expected in the second quarter of 2017.
Based on production from its existing facilities and forecasts from new plants under construction and in active development, AltaGas anticipates having physical volumes equal to approximately 50 percent of the 1.2 million tonnes. The remaining 50 percent is expected to be supplied by producers and aggregators in western Canada. AltaGas expects to underpin at least 40 percent of the Ridley Island Propane Export Terminal throughput under tolling arrangements with producers and other suppliers.
On May 24, 2016, AltaGas LPG Limited Partnership, a wholly owned subsidiary, entered into a Memorandum of Understanding with Astomos Energy Corporation (Astomos) contemplating a multi-year agreement, for the purchase of at least 50 percent of the 1.2 million tonnes of propane available to be shipped from the Ridley Island Propane Export Terminal each year, the key commercial terms of which have been settled. Commercial discussions with Astomos and several other third party off-takers for further capacity commitments are proceeding.
AltaGas began the formal environmental review process in early 2016, which included submission of the Environmental Evaluation Document, review and final determination by federal regulators under terms and conditions that will allow the project to proceed. AltaGas has engaged and worked closely with First Nations throughout the process and will continue to do so as it moves forward with the Ridley Island Propane Export Terminal.
Site preparation and pre-construction activities are underway, and construction is expected to begin in the second quarter of 2017 and will proceed under the self-perform model successfully used by AltaGas to build its other projects on time and on budget. The Ridley Island Propane Export Terminal is expected to be in service by the first quarter of 2019.
In January 2017, AltaGas entered into a non-binding letter of intent with a significant Montney producer to construct a 120 Mmcf/d deep-cut natural gas processing facility and a NGL separation train, capable of processing up to 10,000 Bbls/d of NGL mix, and a rail terminal. Negotiation of definitive agreements is currently on hold. AltaGas continues to have discussions with other producers in the Montney.
Early Stage Deep Basin NGL Facility
AltaGas is in the early stages of development of a site in the Deep Basin region of northwest Alberta. AltaGas plans to develop NGL facilities that would serve producers in this region. The NGL facilities will have access to existing rail and can be connected to AltaGas’ Ridley Island Propane Export Terminal. Active discussions with producers to contractually underpin the facility are continuing, and engagement with First Nations and key stakeholders is underway. FID is subject to completing commercial arrangements, stakeholder engagement, and regulatory approvals. Depending upon the final designs and components, the facility is expected to cost approximately $30 to $80 million.
Marquette Connector Pipeline
On December 15, 2016, SEMCO Gas filed an application with the Michigan Public Service Commission (MPSC) seeking approval to construct, own, and operate the Marquette Connector Pipeline (MCP). The MCP is a proposed new pipeline that will connect the Great Lakes Gas Transmission pipeline to the Northern Natural Gas pipeline in Marquette, Michigan, which will provide system redundancy and increase deliverability, reliability and diversity of supply to SEMCO Gas’ approximately 35,000 customers in Michigan’s Western Upper Peninsula. A MPSC decision is expected in the fourth quarter of 2017. The MCP is estimated to cost between US$135 to $140 million with an anticipated in service date in 2020.
Blythe Energy Center (Blythe)
The Blythe Facility, and the Blythe II Facility (Sonoran) currently under development, are well situated to serve a larger western regional transmission organization comprised of several western U.S. states. AltaGas expects that the California market will experience continued supply reductions through the remaining planned retirement of once-through cooling gas plants and nuclear facilities over the next decade. As Publicly Owned Utilities (POUs) and Community Choice Aggregators (CCAs) continue to determine their future resource needs while meeting California’s 50 percent renewable portfolio standard, the role of flexible, efficient and dispatchable gas fired generation is expected to change from historical base load supply to supporting the reliability of the electrical system and backstopping the increased intermittent renewable generation. In order to address these needs, AltaGas continues to add flexibility to the existing Blythe facility with increased operating ranges, reduced minimum run and down times, and increased ramp rates as well as securing a second source of gas supply to increase market flexibility. As it relates to both Blythe, following its PPA expiration in July 2020, and the current development project Sonoran, AltaGas continues to have bilateral discussions with POUs, CCAs, municipalities, and corporations for multi-year agreements, while also considering resource adequacy market pricing, potential energy and ancillary service offerings, and alternative configurations (gas, combined with solar and energy storage) using the multiple transmission options and capacity available to best serve AltaGas’ potential customers in the desert southwest.
Following the 2016 commissioning of the Pomona Energy Storage Facility in response to Southern California Edison’s (SCE) Aliso Canyon Emergency request for proposals (RFPs), in the first quarter of 2017 AltaGas received California Independent System Operator (CAISO) certification for participation in the ancillary services market which has expanded the flexibility of the facility to include participation in the regulation market. AltaGas continues to evaluate a future expansion based on SCE’s need for additional energy storage at the current site which could readily accommodate a similar size lithium-ion battery project. Separately, and mutually exclusive to the future expansion of the energy storage facility, AltaGas is continuing to evaluate reconfiguring the existing Pomona gas fired facility. In the first quarter of 2016, AltaGas, through its subsidiary AltaGas Pomona Energy Inc., submitted an application with the California Energy Commission (CEC) to repower the Pomona facility to a flexible, fast ramping peaking facility under the small power plant exemption process. It is anticipated that the CEC will complete the application review process, which will be followed by the City of Pomona and local air district permitting processes. Following approval, AltaGas will be ready to bid the proposed reconfigured gas fired facility into upcoming RFPs or enter into other bilateral contract arrangements. Dependent on prospective customer needs for the peaking unit, AltaGas is considering joint configurations including additional battery storage that would allow for a flexible peaking facility with a zero start-time which is well suited to complement an increasingly large contribution from intermittent renewables.
Energy Storage Development
In October of 2013, the California Public Utilities Commission (CPUC) approved an energy storage procurement target for load serving entities of 1,325 MW of viable and cost effective energy storage by 2020. Pacific Gas & Electric Company, SCE and San Diego Gas & Electric were allocated procurement targets, divided into sub categories of transmission-connected, distribution level and behind the meter applications. AltaGas’ success with the Pomona Energy Storage Facility has increased the Corporation’s focus on additional energy storage needs of the load serving entities where AltaGas is well suited to develop additional brownfield and greenfield sites in load constrained areas.
AltaGas continues to expect to deliver approximately high single digit percentage normalized EBITDA growth in 2017 compared to 2016. All three business segments are expected to drive the annual growth in 2017, with the Gas segment expecting to generate the highest normalized EBITDA growth percentage, followed by the Power segment and the Utilities segment. The Power and Utilities segments are expected to generate approximately 75 percent of 2017 normalized EBITDA. The Gas segment is expected to increase from 23 percent of total 2016 normalized EBITDA to approximately 25 percent of total 2017 normalized EBITDA. The following are the key drivers contributing to the expected normalized EBITDA growth in 2017:
- First full year of commercial operations at the Townsend Facility;
- Higher earnings from frac exposed volumes as a result of the expected recovery in commodity prices;
- Higher expected earnings from the Northwest Hydro Facilities due to continual improvements in operational efficiency and expected contractual price increases;
- Higher expected earnings from Petrogas, including a full year of income from the Petrogas Preferred Share dividends;
- Normal seasonal weather in 2017 compared to unfavorable weather in 2016;
- Contributions from the Pomona Energy Storage Facility, which entered commercial operation on December 31, 2016;
- Decrease in operating and administrative expenses as a result of various cost savings initiatives, including the savings from the Workforce Restructuring that occurred in 2016; and
- Partial contributions from the first train of Townsend Phase 2 entering commercial operations in the fourth quarter of 2017.
The overall forecasted EBITDA growth in 2017 includes the impact from the sale of the EDS and JFP transmission assets to Nova Chemicals, which was completed in March 2017, and scheduled turnarounds at the Edmonton Ethane Extraction Plant (EEEP) and the Turin facility in mid-2017.
Normalized funds from operations are also expected to grow by approximately a high single digit percentage driven by the same factors noted above for normalized EBITDA growth, partially offset by higher current tax expenses and lower common share dividends from Petrogas, as Petrogas is expected to retain a portion of its cash to fund its capital program and for general corporate purposes.
The Corporation continues to focus on enhancing productivity and streamlining businesses, including the disposition of smaller non-core assets. As part of the financing strategy for the WGL Acquisition, larger asset sales may be undertaken in 2017, subject to market conditions. Any such asset sales, if undertaken, may adversely impact the 2017 outlook for normalized EBITDA and normalized funds from operations, depending on when such sales close during the year.
In the Gas segment, additional earnings in 2017 are expected to be driven by a full year of contributions from the Townsend Facility, higher frac exposed volumes and commodity prices, higher earnings from Petrogas due to improved profitability in the base business, higher volumes expected at the Ferndale Terminal, a full year of income from the Petrogas Preferred Share dividends, and a partial year contribution from the first train of Townsend Phase 2 entering commercial operations in the fourth quarter of 2017. The additional earnings are expected to be offset by the closing of the sale of the EDS and JFP transmission pipelines in the first quarter of 2017 and scheduled turnarounds at EEEP and the Turin facility in mid-2017. Based on current commodity prices, AltaGas estimates an average of approximately 9,500 Bbls/d will be exposed to frac spreads prior to hedging activities. For the remainder of 2017, AltaGas has frac hedges in place for approximately 5,500 Bbls/d at an average price of approximately $23/Bbl excluding basis differentials.
In the Power segment, increased earnings are expected to be driven by higher expected earnings from the Northwest Hydro Facilities as improvements in productivity continue and contractual price increases take effect, contributions from a full year of operations at the Pomona Energy Storage Facility, and lower planned outages expected at Blythe. The earnings and cash flows from the Northwest Hydro Facilities are expected to be seasonally stronger beginning in the second quarter through the end of the third quarter and are expected to decline in the fourth quarter based on seasonal water flow patterns. Actual seasonal water flow will vary with regional temperatures and precipitation levels.
In the Utilities segment, AltaGas expects to continue to benefit from the normal seasonally strong fourth quarter due to the winter heating season. The Utilities segment is expected to report increased earnings in 2017 mainly driven by the significantly warmer than normal weather experienced at all of the Utilities in 2016, whereas the outlook for 2017 assumes normal weather, and higher customer usage at certain of the Utilities, partially offset by lower interruptible storage service revenue at CINGSA. Earnings at all of the Utilities (except PNG) are affected by weather in their franchise areas, with colder weather generally benefiting earnings. If the weather varies from normal weather, earnings at the utilities would be affected. In addition, earnings from the Utilities segment are impacted by regulatory decisions and the timing of these decisions. In 2017, ENSTAR expects EBITDA to increase by approximately $3 million as a result of the interim refundable rate increase approved in 2016 by the Regulatory Commission of Alaska (RCA), with final rates expected to be set in the third quarter of 2017.
Earnings generated from AltaGas’ U.S. assets are exposed to fluctuations in the U.S./Canadian dollar exchange rate, with the strengthening of the U.S. dollar having a positive impact on earnings. However, some of this benefit will be offset by AltaGas’ U.S. dollar denominated debt and preferred shares.
Monthly Common Share Dividend and Quarterly Preferred Share Dividends
- The Board of Directors approved a dividend of $0.175 per common share. The dividend will be paid on June 15, 2017, to common shareholders of record on May 25, 2017. The ex-dividend date is May 23, 2017. This dividend is an eligible dividend for Canadian income tax purposes;
- The Board of Directors approved a dividend of $0.21125 per share for the period commencing March 31, 2017 and ending June 29, 2017, on AltaGas’ outstanding Series A Preferred Shares. The dividend will be paid on June 30, 2017 to shareholders of record on June 16, 2017. The ex-dividend date is June 14, 2017;
- The Board of Directors approved a dividend of $0.19571 per share for the period commencing March 31, 2017 and ending June 29, 2017, on AltaGas’ outstanding Series B Preferred Shares. The dividend will be paid on June 30, 2017 to shareholders of record on June 16, 2017. The ex-dividend date is June 14, 2017;
- The Board of Directors approved a dividend of US$0.275 per share for the period commencing March 31, 2017 and ending June 29, 2017, on AltaGas’ outstanding Series C Preferred Shares. The dividend will be paid on June 30, 2017 to shareholders of record on June 16, 2017. The ex-dividend date is June 14, 2017;
- The Board of Directors approved a dividend of $0.3125 per share for the period commencing March 31, 2017, and ending June 29, 2017, on AltaGas’ outstanding Series E Preferred Shares. The dividend will be paid on June 30, 2017 to shareholders of record on June 16, 2017. The ex-dividend date is June 14, 2017;
- The Board of Directors approved a dividend of $0.296875 per share for the period commencing March 31, 2017, and ending June 29, 2017, on AltaGas’ outstanding Series G Preferred Shares. The dividend will be paid on June 30, 2017 to shareholders of record on June 16, 2017. The ex-dividend date is June 14, 2017;
- The Board of Directors approved a dividend of $0.328125 per share for the period commencing March 31, 2017, and ending June 29, 2017, on AltaGas’ outstanding Series I Preferred Shares. The dividend will be paid on June 30, 2017 to shareholders of record on June 16, 2017. The ex-dividend date is June 14, 2017; and
- The Board of Directors approved a dividend of $0.4384 per share for the period commencing March 31, 2017, and ending June 29, 2017, on AltaGas’ outstanding Series K Preferred Shares. The dividend will be paid on June 30, 2017 to shareholders of record on June 16, 2017. The ex-dividend date is June 14, 2017.
Consolidated Financial Review
|Three Months Ended
|Net income applicable to common shares||32||55|
|Normalized net income(1)||65||38|
|Total long-term liabilities||4,358||4,770|
|Net additions to property, plant and equipment||2||80|
|Normalized funds from operations(1)||170||132|
|Three Months Ended
|($ per share, except shares outstanding)||2017||2016|
|Net income per common share – basic||0.19||0.38|
|Net income per common share – diluted||0.19||0.38|
|Normalized net income – basic(1)||0.39||0.26|
|Normalized funds from operations(1)||1.01||0.90|
|Shares outstanding – basic (millions)|
|During the period(3)||168||147|
|End of period||169|
|(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: $0.165 beginning on October 26, 2015 and $0.175 beginning on August 25, 2016.|
CONFERENCE CALL AND WEBCAST DETAILS:
AltaGas will hold a conference call today at 9:00 a.m. MT (11:00 a.m. ET) to discuss 2017 first quarter results, progress on construction projects and other corporate developments.
Members of the investment community and other interested parties may dial 1-703-318-2220 or call toll free at 1-844-543-5238. The passcode is 91150065. Please note that the conference call will also be webcast. To listen, please go to http://www.altagas.ca/invest/events-and-presentations. The webcast will be archived for one year.
Shortly after the conclusion of the call, a replay will be available by dialing 1-404-537-3406 or 1-855-859-2056. The passcode is 91150065. The replay will expire at 2:00 p.m. (Eastern) on April 28, 2017.
Additional information relating to AltaGas’ results can be found in the Management’s Discussion and Analysis and unaudited condensed interim consolidated financial statements for the three months ended March 31, 2017 available through AltaGas’ website at www.altagas.ca or through SEDAR at www.sedar.com.
AltaGas is an energy infrastructure company with a focus on natural gas, power and regulated utilities. AltaGas creates value by acquiring, growing and optimizing its energy infrastructure, including a focus on clean energy sources. For more information visit: www.altagas.ca
™ denotes trademark of Canaccord Genuity Corp.
This news release contains forward-looking statements. When used in this news release the words “may”, “would”, “could”, “should”, “will”, “intend”, “plan”, “anticipate”, “further”, “believe”, “achieve”, “aim”, “advance”, “seek”, “propose”, “position”, “estimate”, “forecast”, “expect”, “project”, “target”, “on track”, “potential” 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 news release contains forward-looking statements with respect to, among other things, business objectives; expected growth and drivers of growth; capital expenditures (including in respect of the 2017 capital program; expected allocation per business segment and project and anticipated sources of financing thereof); results of operations; operational and financial performance; business projects; opportunities and financial results, expectations regarding 2017 normalized EBITDA (including expected contributions per business segment and sources of generation); projected growth in normalized EBITDA and normalized funds from operations (including per business segment); AltaGas’ continuation of advancement of its strategic initiatives; AltaGas’ ability to acquire, grow and optimize energy infrastructure, AltaGas’ focus on clean energy sources; AltaGas’ commitment to clean energy infrastructure, expectations with respect to the WGL Acquisition including the expected closing date, date of shareholders’ meeting, ability to obtain, and timeline for obtaining, regulatory and other approvals, the aggregate cash consideration including the anticipated sources of financing thereof and anticipated indebtedness under the bridge facility, planned asset divestitures (including AltaGas’ ability to execute planned asset divestitures in a manner supporting strategy of growing in attractive areas and maintaining long term balanced mix of energy infrastructure),
anticipated benefits of the WGL Acquisition including the portfolio of assets of the combined entity, nature, number, value and timing of growth and investment opportunities available to AltaGas, the quality and growth potential of the assets, the strategic focus of the business, strength of the combined entity, complimentary nature of businesses, robustness of assets, ability to increase scale and provide diversity, the combined assets, rate base, customers and rate base growth, and expectations for the Cove Point LNG Terminal including anticipated completion timing; expected use of proceeds from the issuance of subscription receipts; expectations regarding availability of bridge facility; AltaGas’ ability to achieve a balanced mix of energy infrastructure and expected timeframe to reach such balance; expectations with respect to the Townsend Facility including, expected earnings and impact on earnings; expectations with respect to Townsend Phase 2 and related infrastructure including design specifications, phased development or development in trains, location, capacity, cost, commitment, take or pay arrangements and expected gas volumes from Painted Pony, compression requirements and cost of compression, connection capability to North Pine Facility, plans for transport including new NGL pipelines, ability to backstop and expected timeline for commercial operations and contribution on earnings;
expectations with respect to the proposed Ridley Island Propane Export Terminal including costs, propane transport capability, locational benefits, initial shipment capacity, connection capability, land and water access, quality of transport options, sources of propane supply, AltaGas’ ability to construct new plants and develop new projects, expectations regarding tolling arrangements, expectations of being the first propane export terminal off the west coast of British Columbia, sale and purchase of liquefied petroleum gas from the terminal, entering into a multi-year agreement with Astomos, relations with First Nations and Astomos, potential for third party investment, offtake opportunities, expectations of global access, expectations with respect to AltaGas’ in-house construction expertise and ability to build on time and on budget, and timing of third party investment, construction and commercial operations; expectations relating to the North Pine Facility and North Pine Pipelines including, construction plans, phased development, connection capability to rail, existing AltaGas infrastructure, the proposed Ridley Island Propane Export Terminal and Alaska highway truck terminal, facility specifications, location, handling capability, service area, cost, product mix, timeline for site preparation, construction and commercial operation and expectations regarding Painted Pony’s gas volumes, commitment and contract;
expectations with respect to the Montney Facilities including design specifications, capacity, negotiation of definitive agreements and continuation of discussions with other producers; expectations with respect to the development of the Deep Basin NGL facility including stage of development, facility specifications, location, cost, access to rail, connection capability to the proposed Ridley Island Propane Export Terminal, ability to underpin and target for final investment decision, completion of studies and permitting; expectations relating to the Marquette Connector Pipeline including timeline for MPSC approval, construction and in-service date; cost, location, connection capability to existing pipelines and gas supply opportunities; expectations relating to AltaGas’ ability to fund its projects and business; expectations with respect to the California power market and energy needs of California including expectations regarding the decommissioning of nuclear and coal-fired generation, expected magnitude and timeline for decommissioning and retirement, expectations regarding power supply and the nature of natural-gas fired power generation and future role thereof; expectations regarding expansion, re-contracting, re-configuring opportunities for Blythe and Blythe II (Sonoran) and ability to offer resource adequacy, energy and ancillary services, use multiple transmission options, serve several western U.S. states, develop Sonoran, enter into multi-year agreements and pursue other opportunities through bilateral discussions or otherwise; expectations regarding the locational benefits of the site for Blythe and Sonoran;
expectations relating to the AltaGas Pomona Energy Storage Project including potential expansion opportunities, potential size of expansion, expected energy storage capacity and available resource adequacy, and impact successful commercial operations has on AltaGas, on earnings and potential future development opportunities; expectations with respect to the existing Pomona facility including ability to repower, increase capacity, reconfigure, application review process and timeline, ability to bid into future RFPs and pursue other bilateral arrangements or opportunities; expectations relating to the Northwest Hydro Facilities including expected generation and contributions to earnings and seasonality impacts (including water flow patterns); expected impact on earnings of the Tidewater Gas Asset Disposition; expectations regarding gas processing volumes and disposition of smaller non-core assets; expectations regarding Petrogas including earnings and dividends from Petrogas, Petrogas’ retention of cash and contributions to growth of AltaGas; expectations regarding volumes at Ferndale; expectations regarding the U.S. dollar exchange rate, foreign exchange forward contracts, commodity hedge gains, frac spread exposure, recovery in commodity prices, normal seasonal weather and operating and administrative costs; expectations regarding the impact on earnings of the sale of EDS and JFP pipelines; impact of facility turnarounds and outages on earnings and timing of turnarounds and outages; expected earnings from the utilities segment including from rate base and customer growth and higher customer usage and impact on earnings from lower interruptible storage service revenue from CINGSA and regulatory decisions and timing of regulatory decisions (including in respect of ENSTAR’s 2016 rate case and expected decision date and expected revenue increase; AltaGas ability to focus on enhancing productivity and streamlining businesses; expectations regarding the payment of dividends and expectations regarding timing of the conference call.
These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward looking statements. Such statements reflect AltaGas’ current views with respect to future events based on certain material factors and assumptions and are subject to certain risks and uncertainties including, without limitation, changes in market competition, governmental, aboriginal or regulatory developments, changes in tax legislation, fluctuations in commodity prices, interest or foreign exchange rates, access to capital markets, general economic conditions, changes in the political environment, changes to environmental and other laws and regulations, cost for labour, equipment and materials and other factors set out in AltaGas’ continuous disclosure documents, including the Annual Information Form and the MD&A as at and for the year ended December 31, 2016.
Many factors could cause AltaGas’ actual results, performance or achievements to vary from those described in this news release, including, without limitation, those listed above. 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 news release as intended, planned, anticipated, believed, sought, proposed, estimated or expected, and such forward-looking statements included in, or incorporated by reference in this news release, should not be unduly relied upon. Such statements speak only as of the date of this news release. AltaGas does not intend, and does not assume any obligation, to update these forward-looking statements. The forward-looking statements contained in this news release are expressly qualified by this cautionary statement.
Financial outlook information contained in this news release 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 management’s assessment of the relevant information currently available. Readers are cautioned that such financial outlook information contained in this news release should not be used for purposes other than for which it is disclosed herein.
This news release contains references to certain financial measures that do not have a standardized meaning prescribed by GAAP and may not be comparable to similar measures presented by other entities. The non-GAAP measures and their reconciliation to GAAP financial measures are shown in AltaGas’ Management’s Discussion and Analysis (MD&A) as at and for the three months ended March 31, 2017. These non-GAAP measures provide additional information that management believes is meaningful regarding 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 in AltaGas’ MD&A as at and for the three months ended March 31, 2017. 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.
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