The California Energy Commission, formally the Energy Resources Conservation and Development Commission, is California’s primary energy policy and planning agency. Created in 1974 and headquartered in Sacramento, the Commission has responsibility for activities that include forecasting future energy needs, promoting energy efficiency through appliance and building standards, and supporting renewable energy technologies. The Commission is a division of the California Natural Resources Agency, which is under the direction of Cabinet Secretary John Laird. One of its prominent responsibilities is maintenance of the California Energy Code. Wikipedia.
News Article | February 15, 2017
California Gov. Jerry Brown gave an impassioned speech on Tuesday, rejecting many of the conservative policies championed by the Trump administration and Republicans in Washington, D.C. “California is not turning back. Not now, not ever,” said Brown during his state-of-the-state address. He focused his speech on fighting for immigrant rights, protecting healthcare and continuing to act on climate change. “Our state is known the world over for the actions we have taken to encourage renewable energy and combat climate change,” said Brown. “We cannot fall back and give in to the climate deniers,” he said. “The science is clear. The danger is real.” Many in the environmental community and cleantech industry will be looking to California, which represents the sixth-largest economy in the world, to continue leading the clean energy transition during Trump’s presidency. The new administration has already pledged to undo federal regulations on climate change and proposed budget cuts for the Environmental Protection Agency and the Department of Energy. Trump also took executive action on Tuesday to advance the approval of the Keystone XL and Dakota Access pipelines. Brown’s state-of-the-state address isn’t the first time the governor has spoken out against Trump. In December, he told scientists attending the American Geophysical Union conference that he would protect University of California science labs, and if Trump plans to turn off the NASA satellites monitoring Earth’s climate, California would “launch its own damn satellite.” California has already taken major steps to act on climate, including the approval of a 50 percent renewable energy target. The only flaw with that target is that it wasn’t ambitious enough, California Senate leader Kevin de León recently told The Los Angeles Times. California is already moving toward a clean energy future faster than expected and should “explore the idea” of a 100 percent renewable energy target, he said. In addition to California’s renewable energy portfolio standard, Governor Brown has set a goal of installing 12,000 megawatts of distributed generation in the state, defined as projects under 20 megawatts. As of October 31, 2016, nearly 9,400 megawatts of distributed generation capacity was operating or installed in California, with an additional 900 megawatts pending. That total includes almost 5,100 megawatts of solar self-generation capacity, which far exceeds the state’s goal of installing 3,000 megawatts of solar energy residential and commercial sites by 2017, according to a recent report by the California Energy Commission. California’s programs to support renewable distributed generation could add another 1,800 megawatts if fully subscribed, the report states. Distributed energy resources have become an important element of California’s fight against climate change -- as well as an important part of the state's economy. To facilitate growth in the sector, state lawmakers and regulators have introduced myriad programs and policies aimed at the integration of distributed energy resources. At the same time, the private sector has come up with new technologies and business models to better manage distributed energy resources on the grid. On March 8-9 in San Francisco, Greentech Media is hosting a conference on the future of electricity in California -- one of America’s most innovative states. California’s Distributed Energy Future (CDEF) will kick off on March 8 with a pre-conference workshop in collaboration with More Than Smart. The workshop will give attendees the opportunity to review the stakeholders in California’s clean energy sector, catch up on the latest policy developments, and discuss distributed energy terms and concepts in an interactive half-day session. On March 9, GTM will host a full day of panel sessions, taking a deep dive on topics such as rate design, community-choice aggregation, electric vehicle infrastructure, and distributed energy financing. The conference will feature insights from GTM Research and industry experts, including the California Public Utilities Commission, Southern California Edison, SolarCity, Siemens and many more. California can act on clean energy and climate change on its own, and in partnership with like-minded states, said Gov. Brown in his address. “Make no mistake -- we’re going to do exactly that,” he said. Register to attend CDEF here to be a part of the conversation on the future of distributed energy resources in the Golden State.
News Article | February 23, 2017
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 North American energy infrastructure company," said David Harris, President and Chief Executive Officer of AltaGas. "We also significantly advanced our northeast B.C. and energy export strategies and will soon be starting construction of Canada's first ever propane export terminal off of the west coast. In 2017, we expect to deliver further growth in EBITDA and FFO and we will continue to advance all of our strategic initiatives. 2017 has already proven to be a momentous year with the announcement of the pending acquisition of WGL Holdings, Inc. While the acquisition is subject to regulatory approval, it would be transformational for AltaGas. Together we will be a more diverse and stronger company with a complementary set of energy businesses that will open up even more opportunities to provide significant value for all of our stakeholders." 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. The audited annual consolidated financial statements and annual Management's Discussion and Analysis (MD&A) prepared in accordance with United States generally accepted accounting principles (GAAP) are expected to be filed on SEDAR on or about February 23, 2017. The material will also be available on the AltaGas website on that same day at www.altagas.ca. 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", "aim", "advance", "seek", "propose", "position", "estimate", "forecast", "expect", "project", "target", "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; expectations with respect to the WGL Acquisition including the expected closing date, 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, the combined rate base and rate base growth, the ability of the combined entity to target higher growth markets, high growth franchise areas, and other growth markets; expectations for the Cove Point LNG Terminal including anticipated completion timing, the stability of cash flows and of AltaGas' business, the growth potential available to AltaGas in the Midstream business, clean energy, natural gas generation and retail energy services, the significance and growth potential and expectations for growth in the Montney and Marcellus/Utica formations; expected use of proceeds from the issuance of subscription receipts; 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, AltaGas' ability to increase the size of the Townsend Facility, to retrofit to deep cut facility and timing of retrofit; expectations with respect to the 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, and connection capability to North Pine Facility, plans for transport including new NGL pipelines 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, 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 serving growing demand in Asia and offering new markets to producers and timing of 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 and commercial operation and expectations regarding Painted Pony's gas volumes, commitment and contract; expectations with respect to the Montney Gas and Liquids Processing Facilities including design specifications, ownership, location, cost, capacity, access to the CN rail network, transport of propane to the Ridley Island Propane Export Terminal; expectations regarding AltaGas' ability to underpin and nature of contract commitments including with respect to term and dedication, AltaGas' ability to negotiate and execute definitive agreements and receive regulatory approvals, and expected timeline for executing definitive agreements and being on-line; 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 relating to increased demand for clean energy, expectations relating to the energy needs of California and anticipated timeline for retirement of facilities; 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 through bilateral discussions or otherwise; expectations relating to the AltaGas Pomona Energy Storage Project including AltaGas' ability to operate the project, potential expansion opportunities, potential size of expansion, expected energy storage capacity and available resource adequacy, AltaGas' ability to earn additional revenue from energy from batteries and impact successful commercial operations has on AltaGas and on earnings; expectations with respect to the existing Pomona facility including ability to repower, increase capacity, reconfigure, use more efficient technology, application review process and timeline, its strategic location, 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 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 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 sale of EDS and JFP pipelines including expected closing date and impact on earnings; impact of facility turnarounds on earnings and timing of turnarounds; 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 year ended December 31, 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 year ended December 31, 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.
News Article | March 3, 2017
Changes to net metering are on the way. Southern California Edison is now in the process of passing out NEM 1.0, initiating NEM 2.0. NEM 2.0 will have fewer solar incentives and new rate charges. Net Metering 1.0 is expected to reach its cap by July 1st, which means that homeowners considering going solar need to get their solar installed before the cap is reached to be grandfathered in on Net Metering 1.0. Co-owner of local and veteran owned Semper Solaris, John Almond, explains Net Metering this way, “Net Metering 1.0 is a list that has a cap. Once that cap is reached, you can’t be on Net Metering 1.0. The list is full. It is important to go solar before the list fills up in order to get the best incentives.” All NEM 2.0 customers are put on a TOU (Time of Use) schedule, and charged higher rates for energy usage during peak hours. This especially affects anyone who runs their air conditioning, or families who stay home for a portion of the day. Solar customers who don’t get their solar installed in time to be grandfathered in on NEM 1.0 will be credited lower amounts if their solar panel system is producing extra. NEM 2.0 also includes a new interconnection fee. As co-owner of the fastest growing solar company in California, John Almond makes solar simple for his customers. “Solar is a math problem, with an obvious answer. With current prices as low as they are, there will likely never be a better time to go solar.” Especially as Southern California Edison is nearing the cap for Net Metering 1.0, going solar sooner, rather than later, just makes sense. Customers that go solar before NEM 1.0 changes are grandfathered in, and receive the best solar incentives for 20 years. NEM 2.0 starts July 1, 2017—or once Southern California Energy reaches a cap in energy usage for NEM this year. If anyone installs solar panels before then, they are guaranteed a spot on the original NEM program plan. That means that now is an urgent time to install solar—before these new changes go into effect. Those interested in solar panels need to install as soon as possible, because SCE could certainly reach their energy cap before July 1st—and the panels need to be installed and approved before the cap is reached. The Net Metering changes also come on the heels of a new high usage fee instituted by several California electricity companies. The 2017 high usage surcharge comes after historic rate increase in 2016. With all these factors in mind, now is a better time than ever for homeowners to go solar, reduce their electricity bills, avoid rate increases, and lock in their solar incentives. For homeowners that want to install solar and guarantee their placement on the NEM 1.0 list, there are several factors to consider when choosing a solar contractor. The California Solar Initiative (CPUC) and the California Energy Commission recommend choosing a contractor that is accredited, certified, well established, and who has a strong rating with the Better Business Bureau. About Semper Solaris: Semper Solaris is a licensed solar and roofing company based out of San Diego, California. Semper Solaris is veteran owned and operated, a SunPower Elite Dealer and an Owens Corning Preferred Contractor. Semper Solaris is recognized as the fastest growing solar company in California, and were awarded the SunPower Rising Star Award and Residential National Dealer of the Year Award. Semper Solaris prides themselves on taking the time to help their customers understand how solar works and how to choose the right system. They are A+ Rated with the BBB and have 5 stars on Yelp. Semper Solaris is NABCEP and IREC certified, with over 27 years solar industry experience. For more information, visit sempersolaris.com.
News Article | February 28, 2017
California’s power sector emissions are two-and-a-half times higher today than they would have been had the state kept open and built planned nuclear plants, an Environmental Progress (EP) analysis finds. In the 1960s and 1970s, California’s electric utilities had planned to build a string of new reactors and new plants that were ultimately killed by anti-nuclear leaders and groups, including Governor Jerry Brown, the Sierra Club and Natural Resources Defense Fund (NRDC). Other nuclear plants were forced to close prematurely, including Rancho Seco and San Onofre Nuclear Generation Station, while Diablo Canyon is being forced to close by California’s Renewable Portfolio Standard, which excludes nuclear. Had those plants been constructed and stayed open, 73 percent of power produced in California would be from clean (very low-carbon) energy sources as opposed to just 34 percent. Of that clean power, 48 percent would have been from nuclear rather than 9 percent. EP calculates that’s California’s emissions in 2014 were 30.5 million metric tons higher than they would have been had California gone forward with its nuclear build-out, and retained the nuclear plants it had. EP created this calculation based on the assumption that natural gas was built instead of nuclear. As such, it is a conservative estimate since a significant percentage of California’s power since the 1970s came from coal. Even so, that amount of emissions was equal or greater than the power sector emissions produced by 23 states including Virginia, Minnesota, New Jersey, Washington, and Massachusetts. And it was greater than the total commercial, power, residential, industrial and transportation emissions of eight states including Idaho, New Hampshire, and Rhode Island. Nuclear power plants can be constantly re-furbished and parts replaced for 60 to 80 and perhaps many more years, according to experts. They have no known upper age limit. Electricity and emissions. Data are from the California Air Resources Board (CARB) and the California Energy Commission. EP’s assumptions are that: Emissions reductions for the subtracted coal and gas power uses assumed carbon intensities of 0.98 kg CO2 and 0.4 kg CO2 per kWh, respectively. Assumed capacity factor for nuclear reactors is 92%, the national average in the USA in 2014. To calculate lost nuclear electricity production, we count plants that were already built and closed, and those plants that were not yet under construction but were close to construction and had a utility operator intent on building it. As such, we are not counting plants defeated early in the planning stages, such as the nuclear plant proposed for Bolsa Island, Malibu, and another in Orange County, but we are counting Sun Desert and San Joaquin Valley. There is a large body of historical evidence documenting the role played by Governor Jerry Brown, NRDC, Sierra Club, Ralph Nader and other groups. One of the best single sources is Thomas Wellock’s Critical Masses: Opposition to Nuclear Power in California, 1958 – 1978 (University of Wisconsin Press: 1998). Additional information comes from Christian Joppke’s Mobilizing Against Nuclear Energy (University of California, 1993), and newspaper articles. Utilities that cancel plants often name reasons for their closure other than public opposition. With reference to the 1964 Bolsa Island Proposal, Wellock notes, “The utilities involved in the [Bolsa Island] project claimed that they cancelled the plant owing to its poor economics. But the economic rationale given to the public masked larger siting problems, including public opposition…” (Wellock p. 126) Diablo Canyon Power Plant, Units 3, 4, and 5 were included in blueprints but not constructed in wake of anti-nuclear movement and Gov. Jerry Brown’s opposition. Sundesert Nuclear Power Plant. The plant’s two units were intended to be just under 1 GW each. Governor Jerry Brown, NRDC & Sierra Club opposed them, and sought their demand to be filled with coal instead: “Richard Maullin, the Governor’s appointee as chairman of the Energy Commission, has suggested building new coal-fired generating plants in place of Sundesert.” “The State Energy Commission, an arm of the Brown Administration, reported after an exhaustive study that future power needs for which the Sundesert plant was projected could be met by existing and planned fossil fuel generating facilities…” Rancho Seco Nuclear Generating Station was opposed by Governor Jerry Brown and shut down by a coalition led by Bob Mulholland, an advisor to California’s Democratic Party, and Bettina Redway, Deputy Treasurer of the State of California and the wife of Michael Picker, current President of the state PUC. Against claims that Rancho Seco was inherently flawed, the coalition beat back an effort by a Portland utility to buy it. San Onofre Nuclear Generating Station was shut down after the head of California’s PUC urged Southern California Edison to accept $4.7 billion in investor and ratepayer money in exchange for abandoning the plant, which at the time was repairing a $700 million steam generator. The original posting of this article can be found here.
News Article | February 21, 2017
« Toyota unveiling i-TRIL Concept at Geneva; electric and autonomous urban mobility | Main | California Energy Commission selects 16 hydrogen station projects for up to $33.4M in funding » The Institute for Advanced Composites Manufacturing Innovation (IACMI)—a 100+ member, University of Tennessee, Knoxville and Department of Energy led consortium committed to increasing domestic production capacity and manufacturing jobs across the US composites industry—launched the first technical collaboration project in the compressed gas storage focus area. The project will combine partnership efforts from DuPont Performance Materials (DuPont), the University of Dayton Research Institute (UDRI), Composite Prototyping Center (CPC) and Steelhead Composites. The target objective of the project is to provide unique advantages to the storage of compressed natural gas with the use of thermoplastic composite technologies to achieve better durability, weight reduction and recyclability. The project plan will take advantage of several unique technologies combined with the expertise of each partner. The project proposal begins with the design of a prototype CGS tank based on measured mechanical properties of polyamide composite panels produced by AFP. Pending successful results from two initial phases, the project will conclude with the production of full size tanks. DuPont Performance Materials (DPM) is a leading innovator of thermoplastics, elastomers, renewably sourced polymers, high-performance parts and shapes, as well as resins that act as adhesives, sealants, and modifiers. DPM supports a globally linked network of regional application development experts who work with customers throughout the value chain to develop innovative solutions in automotive, packaging, construction, consumer goods, electrical/electronics and other industries.
News Article | February 15, 2017
Randall D. Martinez, Cordoba Corporation Executive Vice President and Chief Operating Officer, recently joined the board of directors of Sacramento, CA-based nonprofit conservation philanthropy Resources Legacy Fund (RLF). Martinez brings to RLF’s Board experience in protecting and developing underserved communities while also providing civic leadership service. He currently serves as an advisory board member for the Smithsonian Institution’s National Museum of American History in Washington, D.C. and is a governing board member of the Los Angeles Area Chamber of Commerce. In 2015, Martinez was appointed by then California Attorney General Kamala Harris to the California Energy Commission’s $3 billion Clean Energy and Jobs Act (Proposition 39) Citizens Oversight Board. "We are very excited that Randall Martinez has agreed to join Resources Legacy Fund's Board of Directors. His business, financial and management experience and expertise will be important assets for the organization,” said Michael Mantell, president of Resources Legacy Fund. “In addition, Randall's coming on board personifies Resources Legacy Fund 's already strong yet growing engagement with Southern California leaders and communities on the important environmental issues of our time," he added. Resources Legacy Fund works collaboratively with philanthropic partners, diverse urban communities, as well as established conservation constituencies, business leaders and policy officials, to support donor aspirations for protecting significant landscapes, stewarding precious natural resources, and building consensus on complex environmental policy issues. Resources Legacy Fund’s work focuses on four priority categories—land, water, coasts and oceans, and climate and energy—across western North America. For more information about Resources Legacy Fund visit http://www.resourceslegacyfund.org.
News Article | February 21, 2017
« California Energy Commission selects 16 hydrogen station projects for up to $33.4M in funding | Main | MAN and Austria’s CNL partnering on medium- and heavy-duty electric trucks; trials this year, production 2018 » Volkswagen’s new e-Golf, with a larger battery pack and enhanced driving range (earlier post), is now available for order in Europe. Compared to its predecessor, the new version offers more power, longer range and extended standard features. Prices for the zero-emission model start at €35,900 (US$38,000) in Germany. The new e-Golf features a new lithium-ion battery the energy capacity of which has been increased from 24.2 kWh to 35.8 kWh. Its driving range in the New European Driving Cycle (NEDC) is 300 kilometers (186 miles). Volkswagen says that the e-Golf will cover up to 200 real-world kilometers (124 miles) or more in everyday driving depending on driving style, the use of air conditioning and other parameters. This increase the range compared to its predecessor by up to 50%, depending on driving style and usage. All 2017 e-Golf customers receive extended standard features such as Front Assist including City Emergency Braking with the new Pedestrian Monitoring, a multi-function steering wheel (in leather) and Volkswagen Media Control. The electric motor now develops 100 kW/136 PS—15 kW/20 PS more than in the previous model. The compact four-door car accelerates from 0 to 100 km/h in 9.6 seconds. Other new features in the e-Golf are the optional Active Info Display (digital instruments) and the standard 9.2-inch Discover Pro infotainment system that is operated by gesture control. As in all electric models from Volkswagen, it is possible conveniently to access various vehicle functions of the e-Golf via the Car-Net “e-remote” app. A smartphone or tablet can be used to start or stop the air conditioning or battery charging, for example. The app also shows the most recent parking location of the e-Golf on a map. In its exterior appearance, the updated e-Golf features modified front and rear ends with new LED headlights and LED tail lights. The e-Golf heats interior air with an electrical heating unit. It offers the same familiar Golf level of comfort, even at temperatures below freezing. If the user wants to warm up the car while it is charging, utilizing energy from the electrical grid, this can be activated with the “Car-Net e-Remote” remote control app. This function preserves the charge of the high-voltage battery, preserving more energy for driving. An optional heat pump warms the vehicle interior using ambient air and lost heat from the power unit components. The heat pump that was specially developed for the e-Golf reduces electrical consumption and improves the driving range of the electric Golf.
News Article | January 31, 2017
Fremont, USA (January 31, 2017) – SolarEdge Technologies, Inc. (“SolarEdge”) (NASDAQ: SEDG), a global leader in PV inverters, power optimizers, and module-level monitoring services, announced today that its award-winning HD-Wave inverter set a new record for the California Energy Commission (CEC), by reaching 99% weighted efficiency. Topping the CEC inverter efficiency list, SolarEdge’s HD-Wave inverter is based on a novel power conversion topology that significantly decreases inverter size and weight, while also improving efficiency. Weighing in at only 25.3 pounds and measuring 17.7H x 14.6W x 6.8D (including safety switch), SolarEdge’s HD-Wave inverter is the smallest and lightest inverter the company has ever manufactured, which enables faster and easier installation. The innovative inverter complies with safety and revenue grade standards including: integrated arc fault protection; integrated rapid shutdown for NEC 2014 and 2017 690.12; and optional revenue grade data, according to ANSI C12.20 Class 0.5 (0.5% accuracy). Consistent with all its other inverters, SolarEdge’s HD-Wave inverter includes 25-years of free module-level monitoring and 12-year standard warranty. “At SolarEdge we are dedicated to making solar energy more accessible around the world by focusing on innovation,” stated Lior Handelsman, Vice President of Marketing and Product Strategy and Founder of SolarEdge. “Breaking this new record is in line with our commitment to lead the industry in solar energy advancement." By adopting a holistic approach to innovation, SolarEdge designed the new inverter to support enhanced product reliability by using film capacitors instead of electrolytic capacitors. To enable faster commissioning, the HD-Wave inverter has automatic power optimizer identification and string assignment detection. In addition to offering standard SolarEdge design flexibility, the HD-Wave inverter enables 155% DC/AC oversizing. About SolarEdge: SolarEdge provides an intelligent inverter solution that has changed the way power is harvested and managed in solar photovoltaic systems. The SolarEdge DC optimized inverter system maximizes power generation at the individual PV module-level while lowering the cost of energy produced by the solar PV system. The SolarEdge system consists of power optimizers, inverters, storage solutions, and a cloud-based monitoring platform and addresses a broad range of solar market segments, from residential solar installations to commercial and small utility-scale solar installations. SolarEdge is online at http://solaredge.com/us
News Article | February 15, 2017
Soak up these rainy days, Southern California. They are not going to last forever. Summer will be here before you know it, and if recent trends continue, it will likely be a hot one. Globally, 2016 was the warmest year on record. Here in Los Angeles, temperature records were shattered last summer during scorching heat waves that saw highs of 100 degrees for five days straight. If you think the city is too hot, you’ve got company at City Hall. Los Angeles Mayor Eric Garcetti agrees, and he wants to do something about it. As part of a sweeping plan to help L.A. live within its environmental means, Garcetti has pledged to reduce the average temperature in the metropolis by 3 degrees over the next 20 years. It’s a noble goal. Not only will it make you more comfortable, it will reduce energy consumption and improve air quality. It may even save lives — extreme heat kills more people each year than hurricanes, floods or tornadoes. But how do you turn down the thermostat of an entire city in a warming world? And in a place as vast, sprawling and heterogeneous as Los Angeles, how do you measure success? These questions have never been more relevant. L.A.’s heat problem is expected to worsen over the coming decades. Climate models suggest that by 2050, the temperature in downtown L.A. will exceed 95 degrees 22 days per year. In 1990, only six days were that warm. The San Fernando Valley is expected to see 92 days of this extreme heat per year, compared with 54 in 1990. Climate change is primarily responsible for the warming trend, but it’s not the only force at work. Angelenos are also contending with an additional layer of misery caused by what’s known as the “urban heat island effect.” It means that cities — with their asphalt streets, dark roofs, sparse vegetation and car-clogged roads — are almost always a few degrees warmer than the more rural areas that surround them. The mayor’s plan to cool the region won’t compensate for all the effects of climate change. “We can’t geoengineer the atmosphere,” said Matt Petersen, chief sustainability officer for the office of the mayor. But Petersen believes we can do something about the way the city traps heat. By counteracting this heat island effect, he hopes to reduce the amount of warming L.A. will experience in the future. In early July, Petersen’s team convened a group of about 20 civil servants and university scientists to determine how to bring the city’s temperature more in line with what it would have been if Los Angeles had never been developed. “What we are trying to do is create a research collective to help us reach our target,” Petersen said. “It’s a huge challenge.” The city has already teamed up with USC environmental engineer George Ban-Weiss. A veteran of the Lawrence Berkeley National Laboratory’s Heat Island Group, he said there is no better place to test different ways of reducing urban heat than L.A. “There is all this variation across the city,” Ban-Weiss said. “You can’t get a richer place to study climate and meteorology.” The built environment is mostly responsible for the problem. More than half of city surfaces are covered by dark pavements and dark roofs. Traditional asphalt absorbs up to 90% of the sun’s radiation. As the asphalt gets hotter, it warms the air around it, adding to the overall heat. Even after the sun goes down, that accumulated heat lingers for hours and continues to transfer warmth to the night air. One way to combat this heat sink is to replace the city’s streets and sidewalks with high-tech materials that reflect more sunlight and stay cooler during the day and at night. Some of these “cool pavements” reflect light only in the infrared part of the spectrum, which we cannot see. In the summer of 2015, the city’s Bureau of Street Surfaces tested one of these cool pavements at the Balboa Sports Complex parking lot in Encino. The new surface was approximately 11 degrees cooler than regular pavement in the mid-afternoon. Scientists and policymakers are also investigating “cool roofs” and their potential to reduce the overall temperature of the city. Studies have found that in Los Angeles, widespread deployment of cool roofs could reduce the city’s temperature by as much as 2 degrees Fahrenheit. But it’s unlikely that a single strategy will be the most effective option for all neighborhoods. “The heat island effect is a regional phenomenon, and the way you choose your mitigation strategy could vary block to block,” Ban-Weiss said. If an area has no tree cover but lots of cool roofs, adding more cool roofs won’t be as useful as planting trees. On the other hand, if an area has lots of trees, adding reflective pavements won’t reduce temperatures because the sidewalks don’t get much sunlight anyway. Also, some regions of the city require more cooling than others. The biggest factor affecting temperature in the Southland is the influence of sea breezes. As those winds travel east, they pick up heat from the land and deliver it to those who live inland. To address the hyper-local nature of the heat island effect, Ban-Weiss and his graduate students are modeling microclimates of areas as small as a few city blocks. They started with a neighborhood in El Monte, a city that is relatively warm compared to its surroundings. After painstakingly building a computer model that included each tree and building, the researchers were able to analyze the effects of various heat mitigation strategies, comparing how it would feel if streets had more reflective surfaces, if every grassy yard were shaded by trees, and if every roof were covered in grass. They found that cool roofs and green roofs had little effect on the thermal comfort of a person walking down the street, and that putting more trees in unshaded areas was the most effective cooling strategy. However, in areas that were already shady, the most significant effect came from cool pavements. In another project, the team determined that the current zeal for xeriscaping could make L.A. up to 3.4 degrees Fahrenheit warmer in the daytime by depriving the soil of water and limiting the amount of evapotranspiration that occurs. “Evapotranspiration works as an air conditioner,” Ban-Weiss said. “When water evaporates, it removes energy from the system and cools it down.” But at night, different forces are at work: Heat rises from the subsurface of the Earth, moves through the soil and dissipates into the air. Dry soil slows this heat transfer. That means drought-tolerant landscaping could reduce the nighttime temperature by about 5.4 degrees. Ban-Weiss and his collaborators used computer models to identify regions of greater Los Angeles that are particularly hot compared with the areas around them (downtown L.A., Northridge), and those that are particularly cool (South Pasadena, San Marino). Working with heat island researchers at Lawrence Berkeley and with funding from the California Energy Commission, he is installing about a dozen high-tech weather stations to measure these hot and cool islands and watch how they change over time. “We’re spending a lot of time and going to a good deal of effort to determine the best places to put these weather stations,” Ban-Weiss said. “We want to make sure that we put them in locations that will measure the heat island effect, and not the signal from the ocean.” That’s why two of Ban-Weiss’ grad students spent weeks roaming the streets of Los Angeles with a tube-shaped contraption on the roof of their car. The tube, designed at Lawrence Berkeley, holds a needle-thin thermometer that Arash Mohegh and Mo Chen have been squiring around, searching for pockets of heat. The job is tedious. To get accurate measurements, they spend hours weaving up and down streets in their target neighborhoods. They visited the San Fernando Valley on a particularly scorching day in June. “We’re about to go from an industrial area to a more residential neighborhood, so we’ll see how the temperature changes,” Mohegh said as Chen steered the car through Chatsworth. Sure enough, as blocky office buildings gave way to tree-lined streets with green lawns, the dashboard thermometer dropped from 102 to 100 degrees. Petersen said work like this will help the city identify which areas should be targeted for cooling and which strategies will work best. By 2019, he hopes to have a better idea of how realistic the goal of lowering the temperature by 3 degrees really is, as well as the best way to achieve it. The cooling of Los Angeles is still years away, but the groundwork has begun.
Asmus P.,California Energy Commission
Electricity Journal | Year: 2010
Opportunities for VPPs and microgrids will only increase dramatically with time, as the traditional system of building larger and larger centralized and polluting power plants by utilities charging a regulated rate of return fades. The key questions are: how soon will these new business models thrive - and who will be in the driver's;s seat? © 2010 Elsevier Inc.