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AltaGas Ltd. Reports 2016 Fourth Quarter and Year End ResultsFebruary 23, 2017 08:03 ET AltaGas Ltd. Reports 2016 Fourth Quarter and Year End ResultsCALGARY, ALBERTA--(Marketwired - Feb. 23, 2017) - Highlights (all financial figures are unaudited and in Canadian dollars unless otherwise noted)
AltaGas Ltd. (AltaGas) (TSX:ALA) today reported normalized EBITDA in 2016 increased $119 million to $701 million, compared to 2015. Normalized funds from operations were $554 million ($3.52 per share) for 2016, compared to $470 million ($3.41 per share) in 2015. On a U.S. GAAP basis, net income applicable to common shares for 2016 was $155 million ($0.99 per share) compared to $10 million ($0.07 per share) for 2015. Normalized net income(1) was $153 million ($0.98 per share) for 2016, compared to $140 million ($1.02 per share) in 2015. "We achieved significant growth in normalized EBITDA and FFO in 2016 and we furthered our competitive position as a leading 2016 was driven by strong performance in AltaGas' Power and Utility segments. Power benefited from full year contributions from the McLymont Creek Hydroelectric Facility, lower equity losses from the Sundance B PPAs, and the addition of the San Joaquin Facilities. The Utilities segment benefited from continued rate and customer growth and a full-year of SEMCO Gas' Main Replacement Program (MRP). Earnings also benefited from favourable foreign exchange rates on U.S. business results. These increases were partially offset by the expiration of the Pomona PPA, warmer weather experienced at all Utilities, and the impact of the approved Customer Retention Program at Heritage Gas. Results in the Gas segment were lower due to realized hedging gains in 2015, the impact of the Tidewater Gas Asset Disposition, and lower incremental fee-for-service revenue at the Gordondale facility due to lower volumes delivered in excess of take-or-pay levels, partially offset by the addition of the Townsend Facility, the completion of major turnarounds at the Younger and Harmattan facilities during the second quarter of 2015 and higher Petrogas Energy Corp. (Petrogas) earnings. (1) Non-GAAP measure; see discussion in the advisories of this news release Fourth quarter 2016 normalized EBITDA was $194 million, compared to $173 million in the fourth quarter of 2015, driven by a full quarter contribution from the San Joaquin Facilities, commencement of commercial operations at the Townsend Facility in the third quarter of 2016, the absence of equity losses from the Sundance B PPAs, colder weather experienced at all Utilities, higher earnings from Petrogas including the dividend income from the Petrogas Preferred Shares, and the interim refundable rate increases at ENSTAR. These increases were partially offset by lower contributions from the Northwest Hydro Facilities due to unfavorable weather conditions leading to lower river flows, lower gains from frac hedges, higher incentive compensation expense as a result of the Corporation achieving key strategic objectives for 2016, the impact of the Tidewater Gas Asset Disposition, and lower incremental fee-for-service revenue at the Gordondale facility due to lower volumes delivered in excess of take-or-pay levels. Normalized funds from operations were $172 million ($1.04 per share) in the fourth quarter of 2016, up from $159 million ($1.09 per share) in the fourth quarter of 2015. The increase was driven by the increase in normalized EBITDA, as well as lower current income tax expense, partially offset by higher interest expense and lower common share dividends from Petrogas. For the fourth quarter of 2016, AltaGas recorded income tax expense of $6 million compared to $3 million in the same quarter of 2015. The increase was mainly due to higher taxable earnings in the fourth quarter of 2016, including higher taxable earnings from U.S. operations which bear higher corporate income tax rates, partially offset by an $8 million tax recovery recorded on the dissolution of ASTC Power Partnership. On a U.S. GAAP basis, net income applicable to common shares for the fourth quarter of 2016 was $38 million ($0.23 per share) compared to a net loss of $54 million ($0.37 per share) for the same quarter in 2015. Normalized net income was $48 million ($0.29 per share) for the fourth quarter of 2016, compared to $56 million ($0.38 per share) reported for the same quarter in 2015. The decrease was driven by higher depreciation and amortization expense, interest expense, income tax expense, partially offset by the same previously referenced factors resulting in the increase in normalized EBITDA in the fourth quarter of 2016. Normalizing items in the fourth quarter of 2016 included after-tax amounts related to transaction costs on acquisitions, unrealized losses on risk management contracts, losses on long-term investments, the Sundance B PPAs termination costs and the tax recovery on the dissolution of ASTC Power Partnership. In the fourth quarter of 2015, normalizing items included after-tax amounts related to transaction costs incurred on acquisitions, development costs related to energy exports, provisions on assets and on investments accounted for by the equity method, unrealized gains on risk management contracts, and losses on long-term investments. 2016 normalized EBITDA was $701 million, compared to $582 million in 2015, driven by a full year contribution from the San Joaquin Facilities, commencement of commercial operations at the Townsend Facility, rate and customer growth at the Utilities, higher contributions from the Northwest Hydro Facilities resulting from a full year of operations from McLymont, the absence of turnarounds at the Younger and Harmattan facilities, lower equity losses from the Sundance B PPAs, and higher earnings from Petrogas including the dividend income from the Petrogas Preferred Shares. The stronger US dollar also benefited results. These increases were partially offset by lower gains from frac hedges, the impact of warmer weather experienced at all of the Utilities during the first quarter of 2016, the impact from the Tidewater Gas Asset Disposition, lower incremental fee-for-service revenue at the Gordondale facility due to lower volumes delivered in excess of take-or-pay levels, higher incentive compensation expense as a result of the Corporation achieving key strategic objectives for 2016, and the impact from the expiration of the Pomona PPA at the end of 2015. Normalized funds from operations for 2016 were $554 million ($3.52 per share), an increase of approximately 18 percent as comparable to $470 million ($3.41 per share) in 2015, driven by the same factors impacting normalized EBITDA as well as higher common share dividends from Petrogas, partially offset by higher interest expense. In 2016, AltaGas received $24 million in common share dividends from Petrogas compared to $11 million received in 2015. For 2016, AltaGas recorded income tax expense of $33 million compared to $48 million in 2015. The decrease was mainly due to the absence of the one-time, non-cash $14 million charge recorded in the second quarter of 2015 related to the increase in the Alberta corporate income tax rate, 2015 charges to income that did not attract tax recoveries, the $10 million tax recovery related to the Tidewater Gas Asset Disposition recorded in the first quarter of 2016 and the $8 million tax recovery related to the dissolution of ASTC Power Partnership in the fourth quarter of 2016. This was partially offset by higher taxable earnings in 2016 compared to 2015. On a U.S. GAAP basis, net income applicable to common shares for 2016 was $155 million ($0.99 per share) compared to $10 million ($0.07 per share) for 2015. Normalized net income for 2016 was $153 million ($0.98 per share), compared to $140 million ($1.02 per share) in 2015. The variance was driven by the same factors previously referenced impacting normalized EBITDA as well as higher depreciation and amortization expense, interest expense and preferred share dividends. For 2016, normalizing items included after-tax amounts related to unrealized losses on risk management contracts, transaction costs related to acquisitions, gains on sale of assets and related tax recovery, a dilution loss recognized on an investment accounted for by the equity method, provision on investments accounted for by the equity method, restructuring costs, development costs incurred for energy export projects, the Sundance B PPAs termination costs, the tax recovery on the dissolution of ASTC Power Partnership, and the recovery of development costs for the PNG Pipeline Looping Project. For 2015, normalizing items included after-tax amounts related to unrealized gains on risk management contracts, loss on long-term investments, provisions on assets and investments accounted for by the equity method, development costs incurred for energy export projects, transaction costs related to acquisitions, and a statutory tax rate change. Pending Acquisition of WGL Holdings, Inc. (WGL) On January 25, 2017, AltaGas entered into a definitive agreement (the Merger Agreement) to indirectly acquire WGL Holdings, Inc. (NYSE:WGL) (the WGL Acquisition). Pursuant to the Merger Agreement, following the consummation of the WGL Acquisition, WGL common shareholders will receive US$88.25 per common share in cash, which represents a total enterprise value of $8.4 billion, including the assumption of approximately $2.4 billion of debt as at September 30, 2016. WGL is a diversified energy infrastructure company and the sole common shareholder of Washington Gas, a regulated natural gas utility headquartered in Washington, D.C., serving 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. 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 a $400 million private placement of subscription receipts to OMERS, the pension plan for Ontario's municipal employees, and a bought deal subscription receipt offering for gross proceeds of approximately $2.1 billion, subsequent offerings of senior debt, hybrid securities, equity or equity-linked securities (including preferred shares or convertible debentures), select AltaGas asset sales and through a fully committed US$3.1 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 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 by the Public Service Commission of the District of Columbia, The Maryland Public Service Commission, The Commonwealth of Virginia State Corporation Commission, the United States Federal Energy Regulatory Commission, and the Committee on Foreign Investment in the United States, and expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. Project Updates Townsend Gas Processing Facility Expansion AltaGas is developing an expansion (Townsend Phase 2) of the existing Townsend Facility. AltaGas will be constructing Townsend Phase 2 in two separate gas processing trains. The first train 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 the first train of Townsend Phase 2 will 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 will be approximately $120 to $140 million. NGL produced from Townsend Phase 2 is expected to be transported approximately 70 km to AltaGas' North Pine Facility via existing and planned NGL pipelines owned by AltaGas. On December 19, 2016, AltaGas received approval from the British Columbia Oil and Gas Commission (BCOGC) for Townsend Phase 2 and to retrofit the existing shallow-cut Townsend Facility to a deep-cut facility at a future date if AltaGas elects to do so. On February 22, 2017, the Board of Directors approved a positive FID for the first train of Townsend Phase 2. Long-lead major equipment has been ordered and the first train of Townsend Phase 2 is expected to begin commercial operation in October 2017. The first train of Townsend Phase 2 and the field compression equipment are expected to be fully contracted with Painted Pony Petroleum Ltd. (Painted Pony) under a 20-year take-or-pay agreement. 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. The permit from the BCOGC to construct, own and operate the North Pine Facility was issued on September 23, 2016. 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 and will run from 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+. At the Truck Terminal, 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. The BCOGC permit for the North Pine Pipelines was received on December 16, 2016. Site preparation for the North Pine Facility and the North Pine Pipelines is underway with a target commercial on-stream date in 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, and will proceed with the construction, ownership and operation of the Ridley Island Propane Export Terminal. 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. from the Prince Rupert Port Authority. The locational advantage of the site is 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 a world class marine jetty with deep water access to the Pacific Ocean. 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. 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 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. Construction is expected to begin in the first 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. Montney Gas and Liquids Processing Facilities In January 2017, AltaGas entered into a non-binding Letter of Intent (LOI) 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 (the Montney Facilities). The Montney Facilities, which are to be located in another area of the Montney separate from AltaGas' current operations, are expected to have access to the CN rail network allowing for the transportation of propane to the Ridley Island Propane Export Terminal. Under the terms of the LOI, it is contemplated that the deep-cut processing facility will be jointly owned, while the NGL separation train and rail terminal will be fully owned by AltaGas. The deep-cut processing facility is expected to cost approximately $100 to $110 million while the NGL separation train and rail terminal are expected to cost approximately $60 to $70 million. It is expected that the deep-cut facility will be underpinned with long-term take-or-pay and dedication commercial agreements. Completion of the project is subject to, among other things, negotiation and execution of definitive agreements, which AltaGas targets to have signed within the first quarter of 2017. Subject to regulatory approvals, the Montney Facilities are expected to be on-line in early 2019. 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 MPSC seeking approval to construct, own, and operate the MCP. The MCP is a proposed new pipeline that will connect the Great Lakes Gas Transmission pipeline to the Northern Natural Gas pipeline in Marquette, Michigan where it 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 several RFPs to emerge from these states throughout 2017 and beyond, and expects to bid both the potential re-contracting of its Blythe Facility after its Power Purchase Agreement (PPA) expires July 31, 2020, and the potential Sonoran Facility, into these upcoming RFPs. Separately, AltaGas continues to have bilateral discussions with utilities, municipalities, and corporations for multi-year capacity agreements, while also considering Resource Adequacy market pricing, potential energy and ancillary service offerings, and alternative configurations (gas, combined with solar and energy storage) for the Blythe facilities using the multiple transmission options and capacity available to best serve AltaGas' potential customers in the desert southwest, as the demand for clean energy increases. It is expected that up to 15,000 megawatts (MW) will need to be replaced in California due to retirements over the next decade. As utilities, non-utilities and large generators continue to determine their future resource needs to achieve California's 50 percent renewable portfolio standard, sufficient flexible, fast ramping gas-fired capability will be required to help backstop intermittent, non-dispatchable, low capacity factor renewable energy sources and meet peak load requirements. Pomona Facility AltaGas is continuing to work on reconfiguring the existing Pomona 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 in 2017, which will be followed by the City of Pomona and local air district permitting processes. The existing Pomona facility is a 44.5 MW gas-fired peaking plant strategically located in the east Los Angeles Basin load pocket. The repowered facility could be comprised of more efficient gas-fired technology with capacity of up to 100 MW. Following approval, AltaGas will be ready to bid the proposed reconfigured facility into upcoming RFPs or enter into other bilateral contract arrangements. In parallel with the repowering proposal, AltaGas will evaluate a mutually exclusive expansion of the Pomona Energy Storage Facility based on SCE's need for additional energy storage at the site which could readily accommodate another 20 MW of lithium-ion batteries. 2017 Outlook AltaGas currently expects 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 EBITDA growth, 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 following are the key drivers contributing to the expected EBITDA growth in 2017:
The overall forecasted EBITDA growth in 2017 includes an anticipated asset sale of the Ethylene Delivery Systems (EDS) and the Joffre Feedstock Pipeline (JFP) transmission assets to Nova Chemicals Corporation (Nova Chemicals) and scheduled turnarounds at the EEEP and Gordondale facilities in 2017. Normalized funds from operations are also expected to increase by approximately high single digit percentage growth 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. As part of the financing strategy for the WGL Acquisition, certain 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 Townsend Phase 2 entering commercial operations in the fourth quarter of 2017. The additional earnings are expected to be offset by the closing of an anticipated sale of the EDS and JFP transmission pipelines in the first quarter of 2017, and scheduled turnarounds at the Gordondale and EEEP facilities in mid-2017. Based on current commodity prices, AltaGas estimates an average of approximately 9,600 Bbls/d will be exposed to frac spreads prior to hedging activities. For 2017, AltaGas has frac hedges in place for approximately 5,450 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 contributions from the Pomona Energy Storage Facility, higher expected earnings from the Northwest Hydro Facilities as improvements in productivity continue and contractual price increases take effect, 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 flows will vary with regional temperatures and precipitation levels. In the Utilities segment, AltaGas expects to continue to benefit from the normal seasonally strong first and fourth quarters 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, 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. Based on projects currently under review, development or construction, AltaGas expects capital expenditures in the range of $550 to $650 million for 2017. AltaGas' Gas segment will account for approximately 65 to 75 percent of the 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 the 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, Townsend Phase 2, the North Pine Facility, the North Pine Pipelines, and the new Montney Gas and Liquids Processing Facilities. The Corporation continues to focus on enhancing productivity and streamlining businesses, including the disposition of smaller non-core assets. Larger asset sales may also be considered subject to market conditions as part of the WGL acquisition financing strategy. 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 sufficient borrowing capacity available under its credit facilities, as well as access to capital markets. Monthly Common Share Dividend and Quarterly Preferred Share Dividends
Consolidated Financial Review 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 2016 fourth quarter and year-end financial results, progress on construction projects and other corporate developments. Members of the investment community and other interested parties may dial (703) 318-2220 or call toll free at 1-844-543-5238. There is no passcode. 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 (855) 859-2056 or 1-800-585-8367. The passcode is 68549576. The replay will expire at 2:00 p.m. (Eastern) on February 25, 2017. AltaGas is an energy infrastructure business 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. |
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53074 | Re: AltaGas Ltd. Reports 2016 Fourth Quarter and Year End Results | samsung | 5 | 2/23/2017 6:31:14 PM |