AltaGas Reports Strong Third Quarter Results and Announces Final Investment Decision for the North Pine Facility

AltaGas (“AltaGas”) (TSX:ALA) today reported third quarter 2016 normalized EBITDA of $176 million, an increase of 41 percent over the same quarter of 2015. Normalized funds from operations were $137 million ($0.84 per share) for the third quarter of 2016, compared to $102 million ($0.75 per share) in the same period of 2015. On a U.S. GAAP basis, net income applicable to common shares for the third quarter of 2016 was $46 million ($0.28 per share) compared to $20 million ($0.15 per share) for the same quarter in 2015. Normalized net income was $38 million ($0.23 per share) for the third quarter of 2016, compared to $19 million ($0.14 per share) in the same period of 2015.
Highlights

• Strong normalized EBITDA in the third quarter of $176 million, a 41 percent increase over the third quarter of 2015;
• 34 percent increase in normalized funds from operations to $137 million;
• Reached a positive Final Investment Decision (FID) on the North Pine NGL Facility (the North Pine Facility);
• Commenced commercial operations of the 198 Mmcf/d Townsend Facility with processing volumes increasing as expected;
• Significantly advanced plans for the expansion of Townsend which would include an additional 100 Mmcf/d shallow-cut processing capability;
• Signed a 10-year Energy Storage Resource Adequacy Purchase Agreement (Energy Storage Agreement or ESA) with Southern California Edison (SCE) for 20 megawatts (MW) of energy storage at the Pomona Facility (the Pomona Energy Storage Project);
• Public comment period for the Environmental Evaluation Document for the proposed Ridley Island Propane Export Terminal was successfully completed;
• Approval received for a 25-year licence from the National Energy Board (NEB) to export up to 1.35 million tonnes per annum of propane to support Ridley Island Propane Export Terminal;
• 18 percent increase in generation at Forrest Kerr compared to the third quarter of 2015; and
• On a U.S. GAAP basis, net income applicable to common shares for the third quarter was $46 million ($0.28 per share), an increase of 87 percent on a per share basis as compared to the same quarter in 2015.

“Our strong third quarter results continue to highlight the strength of AltaGas’ business and the significant growth we achieved in our power segment with the addition of the San Joaquin assets and our Northwest Hydro Facilities reaching the highest quarterly recorded generation to date,” said David Harris, President and CEO of AltaGas. “We also had great success over the quarter advancing our northeast B.C. strategy. Our Townsend Facility came online ahead of schedule and under budget and Painted Pony has been steadily increasing volumes through the facility. We are moving forward with an expansion of Townsend and expect to announce a final investment decision on this in early 2017. We are also excited to move forward with our North Pine Facility. North Pine is a key component of our energy value chain and brings forward a significant new and competitive option for producers in the Montney. Together with our proposed Ridley Island Propane Export Terminal, we can offer producers superb service to existing and new markets. As we move into the last couple months of the year we expect to hit our financial targets and bring our Ridley Island Propane Export Terminal investment decision to fruition.”
The increase in normalized EBITDA for the third quarter of 2016 was mainly due to the San Joaquin Facilities acquired late in 2015, which contributed approximately $25 million of EBITDA, higher contributions from the Northwest Hydro Facilities as a result of McLymont entering commercial service in the fourth quarter of 2015 and strong performance at Forrest Kerr, commencement of commercial operations at the Townsend Facility and the absence of equity losses from the Sundance B Power Purchase Arrangements (the Sundance B PPAs) terminated in the first quarter of 2016. These increases were partially offset by lower gains from frac hedges, lower earnings from Petrogas Energy Corp. (Petrogas), the impact from the expiration of the Pomona PPA at the end of 2015, lower incremental fee-for-service revenues at the Gordondale facility due to lower volumes delivered in excess of take-or-pay levels, and the impact of the sale of non-core assets to Tidewater Midstream and Infrastructure Ltd. on February 29, 2016 (the Tidewater Gas Asset Disposition).
The increase in normalized funds from operations in the third quarter of 2016 was driven by the same factors as normalized EBITDA, as well as higher common share dividends from Petrogas, partially offset by higher interest and current income tax expense.
For the third quarter of 2016, AltaGas recorded income tax expense of $17 million compared to $5 million in the same quarter of 2015. The increase was mainly due to higher taxable earnings in the third quarter of 2016, including higher taxable earnings from U.S. operations which bear higher corporate income tax rates.
On a U.S. GAAP basis, net income applicable to common shares for the third quarter of 2016 was $46 million ($0.28 per share) compared to $20 million ($0.15 per share) for the same quarter in 2015.
The increase in normalized net income in the third quarter of 2016 was driven by the same factors as normalized EBITDA as well as higher depreciation and amortization expense, interest expense and preferred share dividends. In the third quarter of 2016, normalizing items included after-tax amounts related to unrealized gains on risk management contracts and long-term investments, and recovery of development costs for the PNG Pipeline Looping Project. In the third quarter of 2015, normalizing items included after-tax amounts related to unrealized gains on risk management contracts, energy export development costs, and provision on long-lived assets.
For the nine months ended September 30, 2016, AltaGas reported normalized EBITDA of $507 million compared to $409 million for the same period in 2015. The increase was primarily due to EBITDA generated from the San Joaquin Facilities, higher contributions from the Northwest Hydro Facilities, rate base and customer growth at the Utilities, the impact of the stronger US dollar on reported results of the U.S. assets, the absence of turnarounds at the Younger and Harmattan facilities, commencement of commercial operations at the Townsend Facility, and lower equity losses from the Sundance B PPAs. This was partially offset by the impact of significantly warmer weather experienced at all of AltaGas’ Utilities during the winter heating season, lower gains from frac hedges, the impact from the Tidewater Gas Asset Disposition, the impact from the expiration of the Pomona PPA at the end of 2015, and lower incremental fee-for-service revenues at the Gordondale facility due to lower volumes delivered in excess of take-or-pay.
Normalized funds from operations for the nine months ended September 30, 2016 were $383 million ($2.48 per share), compared to $311 million ($2.30 per share) for the same period in 2015, driven by the same factors impacting normalized EBITDA as well as higher common share dividends from Petrogas, partially offset by higher interest and current income tax expense.
For the nine months ended September 30, 2016, AltaGas recorded income tax expense of $27 million compared to $45 million for the same period in 2015. Income tax expense decreased primarily due to the absence of the one-time, non-cash $14 million charge in the second quarter of 2015 related to the increase in the Alberta corporate income tax rate, and the $10 million tax recovery related to the Tidewater Gas Asset Disposition recorded in the first quarter of 2016.
On a U.S. GAAP basis, net income applicable to common shares for the nine months ended September 30, 2016 was $118 million ($0.76 per share) compared to $64 million ($0.48 per share) for the same period in 2015.
Normalized net income for the nine months ended September 30, 2016 was $105 million ($0.68 per share), compared to $84 million ($0.62 per share) reported for the same period in 2015. The variance was driven by the same factors impacting normalized EBITDA as well as higher depreciation and amortization expense, interest expense and preferred share dividends. For the nine months ended September 30, 2016, normalizing items included after-tax amounts related to unrealized gains on risk management contracts and long-term investments, 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, provisions on investments accounted for by the equity method, restructuring costs, and recovery of development costs for the PNG Pipeline Looping Project. For the nine months ended September 30, 2015, normalizing items included after-tax amounts related to unrealized gains on risk management contracts and long-term investments, development costs incurred for energy export projects, provisions on certain long-lived assets, and a statutory tax rate change.
Based on projects currently under review, development or construction, AltaGas now expects capital expenditures in the range of $550 to $600 million for 2016. Gas and Power maintenance capital is expected to be approximately $25 million of total capital expenditures. With the completion of the Townsend Facility and associated infrastructure, a significant portion of the 2016 committed growth capital has already been incurred. The Corporation continues to focus on enhancing productivity and streamlining businesses, including the disposition of smaller non-core assets.
AltaGas maintains financial strength and flexibility, investment grade credit ratings, and ready access to capital markets. AltaGas’ 2016 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). In addition, as at September 30, 2016, the Corporation had approximately $1.3 billion available under its credit facilities.
Project Updates
North Pine NGL Project
On October 19, 2016, the Board of Directors approved a positive Final Investment Decision 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 proposed Ridley Island Propane Export Terminal. The permit from the B.C. Oil and Gas Commission (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. Site preparation for the first NGL separation train is expected to begin in the first quarter of 2017, with an expected commercial on-stream date in the second quarter of 2018. The second 10,000 Bbls/d NGL separation train is expected to follow after completion of the first train.
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 the 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 two existing 30 km NGL egress pipelines (the 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 is expected in the fourth quarter of 2016, and site work would commence in the first quarter of 2017 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 its NGL produced at the Townsend and Blair Creek facilities.
Townsend Gas Processing Facility
The Townsend Facility is a key component of AltaGas’ northeast British Columbia energy strategy. Commercial operations commenced early in the third quarter of 2016 at the integrated midstream complex at Townsend, located approximately 100 km north of Fort St. John and 20 km southeast of AltaGas’ Blair Creek facility in northeast British Columbia. This complex includes the 198 Mmcf/d shallow-cut gas processing facility (the Townsend Facility), gas gathering line, NGL egress pipelines and truck terminal. The $430 million project was completed ahead of schedule and under budget. Painted Pony has reserved all of the firm capacity under a 20-year take-or-pay agreement.
Associated with the Townsend Facility is a 25 km gas gathering line, which connects the Blair Creek field gathering area to the Townsend Facility. In addition, the Townsend NGL Egress Pipelines run from the Townsend Facility to a newly constructed truck terminal on the Alaska Highway. The Townsend NGL Egress Pipelines can move initial NGL volumes of up to 10,000 Bbls/d each, and with pumping modifications, can accommodate up to 30,000 Bbls/d each. Painted Pony has reserved all of the firm service for the gas gathering line and reserved firm NGL transport capacity on the Townsend NGL Egress Pipelines for all the NGL from the first phase of the Townsend Facility under separate 20-year take-or-pay agreements.
Townsend Gas Processing Facility Expansion
AltaGas is developing an expansion (Townsend Phase 2) of the existing Townsend Facility. AltaGas expects Townsend Phase 2 will be a 100 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 Phase 2 will be approximately $85 to $95 million. In addition, incremental field compression equipment, estimated to cost between $35 to $45 million, will be required to move raw gas production from the Blair Creek area to Townsend. NGL produced from Townsend Phase 2 is expected to be transported approximately 70 km to AltaGas’ proposed North Pine Facility via existing and planned NGL pipelines owned by AltaGas. An application to permit Townsend Phase 2 is expected to be submitted to the BCOGC by the end of October 2016, with approval expected by the second quarter of 2017. Subject to stakeholder engagement and regulatory approvals, the commercial on-stream date is expected in the fourth quarter of 2017.
The regulatory application to build the new Townsend Phase 2 gas processing facility will also include a plan to modify the existing Townsend Facility to enhance liquids recovery.
Ridley Island Propane Export Terminal
AltaGas signed a sublease and related agreements with Ridley Terminals Inc. in the fourth quarter of 2015, to develop, build, own and operate the proposed Ridley Island Propane Export Terminal located near Prince Rupert, British Columbia on lands leased from Ridley Terminals Inc. and the Prince Rupert Port Authority. The proposed Ridley Island Propane Export Terminal is estimated to cost approximately $400 to $500 million and is to be designed to ship 1.2 million tonnes of propane per annum. It will be built on a brownfield site with a history of industrial development, connections to existing rail lines and an existing 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.
AltaGas began the formal environmental review process earlier in 2016 and the public comment period for the Environmental Evaluation Document was successfully completed in September 2016. AltaGas has also engaged closely with First Nations as well as the local municipalities. On October 18, 2016, AltaGas LPG General Partner Inc., on behalf of AltaGas LPG Limited Partnership, was granted approval from the NEB for a 25-year licence to export up to 1.35 million tonnes per annum of propane. The FEED study has been completed and request for proposals for supply and installation of major equipment have been issued. AltaGas expects to reach FID in the fourth quarter of 2016, subject to First Nations engagement and necessary approvals.
On May 24, 2016, AltaGas LPG Limited Partnership, a wholly owned subsidiary, entered into a Memorandum of Understanding with Astomos Energy Corporation (Astomos) setting out key commercial terms for the sale and purchase of liquefied petroleum gas (LPG) from the proposed Ridley Island Propane Export Terminal. Under the terms of a contemplated multi-year agreement, it is anticipated that Astomos will purchase at least 50 percent of the 1.2 million tonnes of propane available to be shipped from the export terminal each year. Active commercial discussions are continuing for additional capacity commitments.
Early Stage Deep Basin NGL Facility
AltaGas is in the early stages of development of a NGL facility which will serve producers in the Deep Basin region of northwest Alberta. The facility is being designed with capacity to process up to 10,000 Bbls/d of C3+ and handle up to 4,000 Bbls/d of C5+. The Deep Basin facility will have access to existing rail and can be connected to AltaGas’ proposed Ridley Island Propane Export Terminal. Active discussions with producers to contractually underpin the base capacity are continuing, and engagement with First Nations and key stakeholders is underway. A facility application was submitted to the Alberta Energy Regulator in May 2016. FID is subject to completing commercial arrangements, stakeholder engagement, and regulatory approvals. Based on current preliminary estimates, the NGL facility is expected to cost approximately $60 to $80 million.
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 request for proposals (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 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 available to best serve our potential customers in the west. 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 Energy Storage Project
In August 2016, AltaGas, through its subsidiary, AltaGas Pomona Energy Storage Inc., signed a 10-year ESA with SCE for 20 MW of energy storage at the existing Pomona facility, located in the east Los Angeles Basin of Southern California. AltaGas will build, own and operate the Pomona Energy Storage Project, which is expected to cost between US$40 to $45 million and will be among the largest battery storage projects in North America when it comes on-line as anticipated by the end of December 2016. Under the terms of the ESA, AltaGas will provide SCE with 20 MW of resource adequacy capacity for a continuous four hour period, which represents the equivalent of 80 MWh of energy discharging capacity. AltaGas will receive fixed monthly resource adequacy payments under the ESA and will retain the rights to earn additional revenue from the energy and ancillary services provided by the lithium-ion batteries.
In conjunction with the ESA, AltaGas is working with Greensmith Energy Management Systems, Inc., a leading provider of energy storage software and integration services, to provide and integrate its software control platform in addition to the batteries and power conversion technology. AltaGas will retain control for the overall project management, execution and operations.
Repowering of Pomona Facility
AltaGas is continuing to work on repowering 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 to repower the Pomona facility to a flexible, fast ramping peaking facility under the small power plant exemption process. It is anticipated that the application review process will be approximately 12 months and include a review of the emissions profile by the local air district. 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 repowered facility into upcoming RFPs or enter into other bilateral contract arrangements.
2016 Outlook
AltaGas continues to expect to deliver overall normalized EBITDA growth of approximately 20 percent in 2016 compared to 2015. The majority of the annual growth in 2016 is expected to be driven by the Power segment, with the Utilities segment also expected to increase by a moderate amount from 2015, while the Gas segment is expected to see a small decline compared to 2015 mainly due to the Tidewater Gas Asset Disposition. The most significant driver of normalized EBITDA growth is a full year contribution from the San Joaquin Facilities acquired on November 30, 2015. 2016 will also be the first year that all three Northwest Hydro Facilities provide a full year contribution as McLymont entered commercial service in the fourth quarter of 2015. AltaGas’ integrated northeast British Columbia strategy began adding EBITDA in the second half of 2016 with the first phase of the Townsend Facility entering commercial operations in July 2016. The Townsend Facility is expected to generate normalized EBITDA of approximately $20 million for 2016 as volumes from Painted Pony Petroleum Ltd. (Painted Pony) progressively increase through year-end. Despite the warm winter weather experienced in early 2016, the Utilities segment is expected to report increased normalized EBITDA in 2016 driven by rate base and customer growth while also benefitting from a favorable US dollar exchange rate. The overall forecasted growth in normalized EBITDA includes lower commodity hedge gains in the Gas segment compared with 2015 as well as higher operating and administrative costs due to new assets placed into service.
AltaGas continues to expect normalized funds from operations to grow by approximately 15 percent in 2016, driven by the factors noted above for normalized EBITDA growth, partially offset by higher financing costs related to new assets acquired as well as new assets in service and higher current tax expenses. AltaGas’ $150 million investment in the Petrogas cumulative redeemable convertible preferred shares made in June 2016 (the Petrogas Preferred Shares) contributed to funds from operations as dividends are expected to be paid quarterly. In the third quarter of 2016, AltaGas received $6 million in common share dividends and approximately $3 million in preferred share dividends from Petrogas and currently expects to receive similar amounts in the fourth quarter of 2016. For the nine months ended September 30, 2016, AltaGas received $18 million in common share dividends and approximately $3 million in preferred share dividends from Petrogas. For the full year of 2015, AltaGas received $11 million in common share dividends from Petrogas.
The Workforce Restructuring is expected to reduce operating and administrative expenses by approximately $7 million on an annualized basis.
In the Power segment, increased earnings are expected to be driven by a full-year contribution from the San Joaquin Facilities and McLymont. The earnings and cash flows from the Northwest Hydro Facilities were seasonally stronger 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 the fourth quarter to be seasonally stronger due to the winter heating season. The Utilities segment is expected to report increased earnings in 2016 driven by rate base and customer growth. SEMCO Gas expects approximately $8 million of revenue in 2016 as a result of a full year contribution from its Main Replacement Program (MRP). In July 2016, the Regulatory Commission of Alaska approved an interim refundable rate increase of approximately US$5 million (annualized) for ENSTAR effective August 1, 2016 with final rates to be set in 2017. In September 2016, the NSUARB approved Heritage Gas’ Customer Retention Program application to decrease distribution rates for certain commercial and residential customers, suspend depreciation and to increase the capitalization rate for operating, maintenance and administrative expenses effective March 22, 2016. Heritage Gas’ normalized EBITDA is expected to decrease by approximately $3 million in 2016 as a result of its Customer Retention Program. 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 the Gas segment, additional earnings in 2016 are expected to be driven by the first phase of the Townsend Facility, which entered commercial operations in July 2016, the absence of turnarounds at the Harmattan and Younger facilities, and higher earnings at Petrogas. The additional earnings are expected to be offset by lower commodity hedge gains, the Tidewater Gas Asset Disposition, moderately lower volumes at certain non-core gas facilities and moderately lower volumes above take-or-pay levels at the Gordondale facility. The Tidewater Gas Asset Disposition represented approximately 5 percent of 2015 normalized EBITDA for the Gas segment and less than 2 percent of AltaGas’ expected 2016 normalized EBITDA. Based on recent strength in commodity prices, AltaGas is increasing the amount of frac exposed volumes for the remainder of 2016 to capitalize on the higher prices and now estimates an average of approximately 7,500 Bbls/d will be exposed to frac spreads prior to hedging activities. For the remainder of 2016, AltaGas has frac hedges in place with volumes which range between 1,700 to 3,900 Bbls/d at an average price of approximately $21/Bbl excluding basis differentials.
For the first nine months of 2016, EBITDA generated from U.S. assets benefitted from the strengthening of the US dollar compared to the same period in 2015. If the US dollar remains strong in the fourth quarter of 2016 compared to the fourth quarter of 2015, EBITDA reported for AltaGas’ U.S. assets will benefit accordingly. Some of this benefit will be offset by US dollar denominated depreciation, interest on US dollar denominated debt, dividends on US dollar denominated preferred shares and U.S. income tax expense.
Monthly Common Share Dividend and Quarterly Preferred Share Dividend

• The Board of Directors approved a dividend of $0.175 per common share. The dividend will be paid on December 15, 2016, to common shareholders of record on November 25, 2016. The ex-dividend date is November 23, 2016. 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 September 30, 2016 and ending December 30, 2016, on AltaGas’ outstanding Series A Preferred Shares. The dividend will be paid on December 30, 2016 to shareholders of record on December 14, 2016. The ex-dividend date is December 12, 2016;
• The Board of Directors approved a dividend of $0.19921 per share for the period commencing September 30, 2016 and ending December 30, 2016, on AltaGas’ outstanding Series B Preferred Shares. The dividend will be paid on December 30, 2016 to shareholders of record on December 14, 2016. The ex-dividend date is December 12, 2016;
• The Board of Directors approved a dividend of US$0.275 per share for the period commencing September 30, 2016 and ending December 30, 2016, on AltaGas’ outstanding Series C Preferred Shares. The dividend will be paid on December 30, 2016 to shareholders of record on December 14, 2016. The ex-dividend date is December 12, 2016;
• The Board of Directors approved a dividend of $0.3125 per share for the period commencing September 30, 2016, and ending December 30, 2016, on AltaGas’ outstanding Series E Preferred Shares. The dividend will be paid on December 30, 2016 to shareholders of record on December 14, 2016. The ex-dividend date is December 12, 2016;
• The Board of Directors approved a dividend of $0.296875 per share for the period commencing September 30, 2016, and ending December 30, 2016, on AltaGas’ outstanding Series G Preferred Shares. The dividend will be paid on December 30, 2016 to shareholders of record on December 14, 2016. The ex-dividend date is December 12, 2016; and
• The Board of Directors approved a dividend of $0.328125 per share for the period commencing September 30, 2016, and ending December 30, 2016, on AltaGas’ outstanding Series I Preferred Shares. The dividend will be paid on December 30, 2016 to shareholders of record on December 14, 2016. The ex-dividend date is December 12, 2016.

Consolidated Financial Review
			Three Months Ended				Nine Months Ended
			September 30				September 30
($ millions)			2016		2015		2016		2015
Revenue			492		452		1,528		1,613
Normalized EBITDA(1)			176		125		507		409
Net income applicable to common shares			46		20		118		64
Normalized net income(1)			38		19		105		84
Total assets			9,952		8,959		9,952		8,959
Total long-term liabilities			4,541		4,208		4,541		4,208
Net additions to property, plant and equipment			80		164		284		417
Dividends declared(2)			85		65		233		188
Cash flows
	Normalized funds from operations(1)		137		102		383		311
			Three Months Ended				Nine Months Ended
			September 30				September 30
($ per share, except shares outstanding)			2016		2015		2016		2015
Normalized EBITDA(1)			1.07		0.92		3.29		3.03
Net income per common share – basic			0.28		0.15		0.77		0.48
Net income per common share – diluted			0.28		0.14		0.76		0.47
Normalized net income – basic(1)			0.23		0.14		0.68		0.62
Dividends declared(2)			0.52		0.48		1.51		1.39
Cash flows
	Normalized funds from operations(1)		0.84		0.75		2.48		2.30
Shares outstanding – basic (millions)
	During the period(3)		164		136		154		135
	End of period		165		145		165		145

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 $0.1475 beginning on May 26, 2014, $0.16 beginning on May 26, 2015, $0.165 beginning on October 26, 2015, and $0.175 beginning on August 25, 2016.

3. Weighted average.

Conference Call and Webcast Details:
AltaGas will hold a conference call, October 20, 2016 at 9:00 a.m. MT (11:00 a.m. ET) to discuss third quarter financial results, progress on projects and other corporate developments.
Members of the investment communities and other interested parties may dial (416) 340-2216 or call toll free at 1-866-225-0198. There is no passcode. Please note that the conference call will also be webcast. To listen, please go to https://www.altagas.ca/investors/presentations_and_events. The webcast will be archived for one year.
Shortly after the conclusion of the call, a replay will be available by dialing (905) 694-9451 or 1-800-408-3053. The passcode is 8772250. The replay will expire at midnight (Eastern) on October 27, 2016.
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 and nine months ended September 30, 2016 available through AltaGas’ website at www.altagas.ca or through SEDAR at www.sedar.com.
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.
This news release contains forward-looking statements. When used in this news release, the words “may”, “can” “would”, “could”, “will”, “intend”, “plan”, “anticipate”, “bring”, “believe”, “seek”, “contemplate”, “continue”, “projection”, “propose”, “focus”, “estimate”, “target”, “potential, “on track”, “expect”, and similar expressions, as they relate to AltaGas or an affiliate of AltaGas, are intended to identify forward-looking statements. This news release contains forward-looking statements with respect to, among other things, business objectives, expected growth, results of operations, performance, business projects and opportunities, capital expenditures, and financial results. In particular this news release contains forward looking statements with respect to the projected growth or decline in normalized EBITDA and normalized funds from operations (including per business segment); expectations with respect to AltaGas’ ability to hit its financial targets; expectations with respect to the Townsend Facility and related projects including, expected earnings and impact on earnings, ability to increase capacity on Townsend NGL Egress Pipelines, ability to make modifications to the facility and expectations regarding Painted Pony’s delivery of gas volumes; expectations with respect to the Townsend Gas Processing Facility Expansion including design specifications, location, capacity, cost, transportation network and connection capability to North Pine Facility, expected timeline for permitting, final investment decision and commercial on-stream and content of regulatory application; expectations with respect to the development of the proposed Ridley Island Propane Export Terminal including development costs, propane transport capability, initial shipment capacity, sale and purchase of liquefied petroleum gas from the terminal, entering into a multi-year agreement with Astomos and timing of final investment decision and commercial operations; expectations relating to the development of the North Pine Facility and NGL supply pipelines including bringing forward new and competitive options for producers and access to markets, 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, handling capability, service area, cost, product mix, timeline for site preparation, permitting and commercial operation and expectations regarding Painted Pony’s gas volumes, commitment and contract; expectations with respect to the development of the Deep Basin NGL facility including facility specifications, design and handling capacity, 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 that AltaGas is well-positioned to fund its growth capital and to take advantage of growth opportunities as they arise; expectations relating to AltaGas’ ability to fund its projects and business; expectations relating to the energy needs of California; the potential for, and timing of, RFPs from western U.S. states, the ability to bid the Blythe and Sonoran facilities into these upcoming RFPs, and to reconfigure, recontract, use multiple transmission options and pursue other opportunities; expectations with respect to the AltaGas Pomona Energy Storage Project including AltaGas’ ability to build, own and operate the project, expected energy storage capacity and available resource adequacy, the facility being among the largest in North America, battery run time, estimated cost and in-service date, expectations regarding resource adequacy payments and AltaGas’ ability to earn additional revenue from energy from batteries, AltaGas’ expectations with respect to Greensmith’s ability to integrate battery and PCS hardware, and AltaGas’ expectation to retain overall project management and execution; 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 San Joaquin Facilities including expected contributions to growth and impact on earnings; expectations relating to the Northwest Hydro Facilities including expected 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 and contributions to growth of AltaGas; expectations regarding the U.S. dollar exchange rate, foreign exchange forward contracts, commodity hedge gains and operating and administrative costs; expected impact the Workforce Restructuring will have on operating and administrative expenses; expected earnings from the utilities segment including from rate base and customer growth, from SEMCO Gas as a result of its Main Replacement Program, from ENSTAR in connection with its 2016 rate case and from Heritage Gas from its customer retention program; expected decision date on ENSTAR’s rates; 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, 2015.
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 as well as 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 news release as intended, planned, anticipated, believed, sought, proposed, estimated, forecasted, expected, projected or targeted, 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 and nine months ended September 30, 2016. 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 and nine months ended September 30, 2016. 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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