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DURHAM REGION, ONTARIO--(Marketwired - March 1, 2017) - The CEO's of three leading Ontario utilities who are currently evaluating the benefits of a merger, namely Veridian Corporation ("Veridian"), Oshawa Power and Utilities Corporation ("Oshawa PUC") and Whitby Hydro Energy Corporation (Whitby Hydro"), have announced today that Oshawa PUC will be amicably withdrawing from further merger discussions. Both Veridian and Whitby Hydro have confirmed they are fully committed to moving forward with due diligence and review of a possible merger. In late 2015, the respective leadership teams of Veridian, Oshawa PUC and Whitby Hydro began discussions to identify the potential benefits of a merger that would create value for all shareholders and customers, as well as position the combined entity for the future. Since that time, all parties have participated in rigorous business case analysis and valuations. On March 1st, 2017, the parties jointly announced that Oshawa PUC had amicably withdrawn from future merger discussions and only Veridian and Whitby Hydro would proceed to the next stages of merger review. "This is not uncommon in merger proceedings. Merger evaluations are designed to ensure all parties can deliver benefits to their respective shareholders and customers. Oshawa PUC has chosen to withdraw as they believe benefits to their shareholders and customers are not sufficient," said Michael Angemeer, President and CEO of Veridian Corporation. In 2012, the Provincial government conducted a review of Ontario's distribution facilities and encouraged local utilities to drive efficiencies and find benefits to customers. Consolidation, or merging with other local utilities, was one pathway to achieve this if the right set of variables existed for all parties involved. "It was an informative process and one that we were pleased to participate in together with our partners, Veridian and Whitby Hydro," said Ivano Labricciosa, President and CEO of Oshawa PUC. "We conducted a thorough review of the potential merger and for us, it was in the best interest of our customers and shareholders to withdraw at this time. We thank all of our stakeholders who contributed to this process and assisted with our investigation and we wish both Veridian and Whitby Hydro success in their ongoing evaluation of this merger." Veridian and Whitby Hydro re-affirmed their commitment to the next phase in the process and stand by the prospective merits of the proposed merger. "From our perspective, consolidation is a viable pathway to ensure that we can improve efficiencies, deliver safe and reliable service while also putting the customer first," said John Sanderson, President and CEO of Whitby Hydro. "Those are at the top of our list for core principles guiding this assessment." He also said that, "the merged company should also lead to an increased ability to participate in new business that will offset some of the risks of disruptive technology." The core principles of the assessment also included ongoing municipal ownership and control, responsible and sound governance as well as diversification and growth. "We look forward to next steps and to ongoing consultation with our communities. We set out to deliver benefits to all of our customers and shareholders and we look forward to delivering that result at the end of this process," said Angemeer. More information on the proposed merger and upcoming opportunities for community consultation can be found at one of our dedicated websites. Veridian Corporation owns and operates Veridian Connections, a subsidiary company that distributes electricity, generates power and provides energy services to more than 120,000 customers. The City of Pickering, the Town of Ajax, the Municipality of Clarington and the City of Belleville jointly own Veridian Corporation. The utility is the fifth largest municipally owned electric utility in Ontario. Veridian has a successful history of effective growth through two mergers and five acquisitions, and now serves nine communities east and north of Toronto more efficiently than any other large non-contiguous utility in Ontario. Veridian has a keen focus on reliability, customer communication and helping to lower customers' electricity bills through the delivery of innovative conservation programs and reasonable rates. Veridian not only contributes to local communities through industry leading financial returns, but also helps build stronger communities through the support of youth, health, economic development, education, the arts, the environment and the disadvantaged. Industry leading employee and public safety, environmental programs and a focus on employee engagement has created an environment that has attracted seven consecutive Canada's Greenest Employer awards and one Top GTA Employer award. Veridian has now diversified into renewable energy, and will be establishing other value added offerings for its customers Oshawa Power and Utilities Corporation (OPUC) is the holding company for a diversified group of four subsidiaries involved in energy distribution, telecom ventures, clean power generation and solar energy generation. Through its subsidiaries OPUC provides: safe, reliable and efficient electricity distribution services to over 57,000 customers; develops, constructs and operates clean and green energy generation assets in Ontario; and provides a reliable dark fibre optics communications network within Oshawa and the Region of Durham. OPUC is wholly owned by the Corporation of The City of Oshawa. Whitby Hydro Energy Corporation is a holding company owned by The Town of Whitby. Contained within are two separate and distinct subsidiaries - Whitby Hydro Electric Corporation and Whitby Hydro Energy Services. Whitby Hydro Electric Corporation is an electricity distributor licensed by the Ontario Energy Board (OEB) to deliver electricity to homes and businesses in our service area of the Whitby, Brooklin and Ashburn communities. Our organization serves more than 41,500 customers.


News Article | February 28, 2017
Site: www.theenergycollective.com

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.


TORONTO, ONTARIO / ACCESSWIRE / February 15, 2017 / Pancontinental Gold Corporation (TSXV: PUC) ("Pancon Gold" or the "Company") is pleased to provide a progress update on the initial stage of its Jefferson Gold Project drill program in Chesterfield county, South Carolina, USA. The drill program began in mid-November 2016 (as per Pancon Gold's news release of November 15, 2016). Four pilot holes have been completed to date at Anomaly A, which is partially covered by a veneer of younger sand that limits the availability of surface exposures. The purpose of these pilot holes has been to test structural and lithologic controls on mineralization at depth, and to provide context and guidance for further drilling throughout the first half of 2017. The geology on the Jefferson Gold Project is similar to that hosting the nearby producing Haile gold mine and the adjacent historic Brewer gold mine. Unique to Pancon Gold's Jefferson Gold project is the recognition from current drilling that the mineralization identified consists of Haile-style sediment hosted gold replacement mineralization and altered packages, together with porphyry intrusives that more closely resemble a Brewer-style high sulphidation gold system and related low sulphidation mineralization. Current drilling has also identified surface oxidation to depths of nearly 70 metres (229 feet), which bodes well for the discovery of a bulk tonnage oxidized gold deposit within the current target areas. Pancon Gold's Board and Technical Advisory Committee are encouraged by the degree of alteration and sulphide mineralization observed in the initial Anomaly A pilot holes, and by the presence of significant wide zones of silicification and quartz stockwork. The Company is employing oriented drill core and close-spaced drilling to unravel the structure within a footprint of 300 metres by 200 metres (984 feet by 656 feet). Additional surface anomalies up to a kilometre (0.6 mile) south of Anomaly A have been identified, but are yet to be tested. These anomalies may relate to the Anomaly A trend or a parallel trend, and the Company is conducting surface sampling in this area where possible. Approximately 715 metres (2,345 feet) have been drilled to date, and the current initial stage drill plan calls for completing approximately 1,500 metres (5,000 feet) in total, at which time results will be released. Core samples are being shipped first to ALS Chemex in Arizona for preparation, then to ALS in Vancouver for fire assay gold analysis and four acid digestion 33 multi-element ICP-AES analysis. Standard quality assurance/quality control procedures are followed including blanks, duplicates and standards. Dr. Dennis LaPoint is a qualified person under National Instrument 43-101 "Standards of Disclosure for Mineral Projects," and has approved the technical information contained in this news release. Dr. LaPoint is not independent of Pancon Gold, as he is Vice President of Exploration. Also today, the Pancon Gold Board announced the appointment of Layton Croft as President and CEO of Pancon Gold's wholly-owned subsidiary, Palmetto Mining Corporation. Incorporated in South Carolina, Palmetto Mining has 100% ownership of the Jefferson Gold Project. Mr. Croft is responsible for ensuring successful and cost effective drill programs at the Jefferson Gold Project. He is also responsible for building and maintaining positive, mutually beneficial stakeholder relationships in the Carolinas region to foster stability, expansion and growth over time. He will be working closely with Dr. LaPoint and with Pancon Gold's Technical Advisory Committee. Mr. Croft was appointed Vice President of Corporate Development for Pancon Gold on January 26, 2017. The Jefferson Gold Project is located in the highly mineralized, gold-rich Carolina Mineral Belt, which was home to the first gold rush in the United States, 190 years ago. Pancontinental Gold Corporation (www.pancongold.com) is a Canadian-based mining company focused on the exploration and development of the Jefferson Gold Project in South Carolina, USA, and on acquiring additional prospective properties. The Company's shares are listed on the TSX Venture Exchange, trading under the symbol PUC. In 2015, Pancon Gold sold its interest in its Australian rare earth element (REE) and uranium properties, formerly held through a joint venture, and retains a 1% gross overriding royalty on 100% of future production. ON BEHALF OF THE BOARD OF DIRECTORS For further information, please contact: For additional information please visit our web site: www.pancongold.com, and our Twitter feed: @PanconGold. Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release. This news release contains forward-looking information which is not comprised of historical facts. Forward-looking information is characterized by words such as "plan", "expect", "project", "intend", "believe", "anticipate", "estimate" and other similar words, or statements that certain events or conditions "may" or "will" occur. Forward-looking information involves risks, uncertainties and other factors that could cause actual events, results, and opportunities to differ materially from those expressed or implied by such forward-looking information. Factors that could cause actual results to differ materially from such forward-looking information include, but are not limited to, changes in the state of equity and debt markets, fluctuations in commodity prices, delays in obtaining required regulatory or governmental approvals, and other risks involved in the mineral exploration and development industry, including those risks set out in the Company's management's discussion and analysis as filed under the Company's profile at www.sedar.com. Forward-looking information in this news release is based on the opinions and assumptions of management considered reasonable as of the date hereof, including that all necessary governmental and regulatory approvals will be received as and when expected. Although the Company believes that the assumptions and factors used in preparing the forward-looking information in this news release are reasonable, undue reliance should not be placed on such information. The Company disclaims any intention or obligation to update or revise any forward-looking information, other than as required by applicable securities laws. TORONTO, ONTARIO / ACCESSWIRE / February 15, 2017 / Pancontinental Gold Corporation (TSXV: PUC) ("Pancon Gold" or the "Company") is pleased to provide a progress update on the initial stage of its Jefferson Gold Project drill program in Chesterfield county, South Carolina, USA. The drill program began in mid-November 2016 (as per Pancon Gold's news release of November 15, 2016). Four pilot holes have been completed to date at Anomaly A, which is partially covered by a veneer of younger sand that limits the availability of surface exposures. The purpose of these pilot holes has been to test structural and lithologic controls on mineralization at depth, and to provide context and guidance for further drilling throughout the first half of 2017. The geology on the Jefferson Gold Project is similar to that hosting the nearby producing Haile gold mine and the adjacent historic Brewer gold mine. Unique to Pancon Gold's Jefferson Gold project is the recognition from current drilling that the mineralization identified consists of Haile-style sediment hosted gold replacement mineralization and altered packages, together with porphyry intrusives that more closely resemble a Brewer-style high sulphidation gold system and related low sulphidation mineralization. Current drilling has also identified surface oxidation to depths of nearly 70 metres (229 feet), which bodes well for the discovery of a bulk tonnage oxidized gold deposit within the current target areas. Pancon Gold's Board and Technical Advisory Committee are encouraged by the degree of alteration and sulphide mineralization observed in the initial Anomaly A pilot holes, and by the presence of significant wide zones of silicification and quartz stockwork. The Company is employing oriented drill core and close-spaced drilling to unravel the structure within a footprint of 300 metres by 200 metres (984 feet by 656 feet). Additional surface anomalies up to a kilometre (0.6 mile) south of Anomaly A have been identified, but are yet to be tested. These anomalies may relate to the Anomaly A trend or a parallel trend, and the Company is conducting surface sampling in this area where possible. Approximately 715 metres (2,345 feet) have been drilled to date, and the current initial stage drill plan calls for completing approximately 1,500 metres (5,000 feet) in total, at which time results will be released. Core samples are being shipped first to ALS Chemex in Arizona for preparation, then to ALS in Vancouver for fire assay gold analysis and four acid digestion 33 multi-element ICP-AES analysis. Standard quality assurance/quality control procedures are followed including blanks, duplicates and standards. Dr. Dennis LaPoint is a qualified person under National Instrument 43-101 "Standards of Disclosure for Mineral Projects," and has approved the technical information contained in this news release. Dr. LaPoint is not independent of Pancon Gold, as he is Vice President of Exploration. Also today, the Pancon Gold Board announced the appointment of Layton Croft as President and CEO of Pancon Gold's wholly-owned subsidiary, Palmetto Mining Corporation. Incorporated in South Carolina, Palmetto Mining has 100% ownership of the Jefferson Gold Project. Mr. Croft is responsible for ensuring successful and cost effective drill programs at the Jefferson Gold Project. He is also responsible for building and maintaining positive, mutually beneficial stakeholder relationships in the Carolinas region to foster stability, expansion and growth over time. He will be working closely with Dr. LaPoint and with Pancon Gold's Technical Advisory Committee. Mr. Croft was appointed Vice President of Corporate Development for Pancon Gold on January 26, 2017. The Jefferson Gold Project is located in the highly mineralized, gold-rich Carolina Mineral Belt, which was home to the first gold rush in the United States, 190 years ago. Pancontinental Gold Corporation (www.pancongold.com) is a Canadian-based mining company focused on the exploration and development of the Jefferson Gold Project in South Carolina, USA, and on acquiring additional prospective properties. The Company's shares are listed on the TSX Venture Exchange, trading under the symbol PUC. In 2015, Pancon Gold sold its interest in its Australian rare earth element (REE) and uranium properties, formerly held through a joint venture, and retains a 1% gross overriding royalty on 100% of future production. ON BEHALF OF THE BOARD OF DIRECTORS For further information, please contact: For additional information please visit our web site: www.pancongold.com, and our Twitter feed: @PanconGold. Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release. This news release contains forward-looking information which is not comprised of historical facts. Forward-looking information is characterized by words such as "plan", "expect", "project", "intend", "believe", "anticipate", "estimate" and other similar words, or statements that certain events or conditions "may" or "will" occur. Forward-looking information involves risks, uncertainties and other factors that could cause actual events, results, and opportunities to differ materially from those expressed or implied by such forward-looking information. Factors that could cause actual results to differ materially from such forward-looking information include, but are not limited to, changes in the state of equity and debt markets, fluctuations in commodity prices, delays in obtaining required regulatory or governmental approvals, and other risks involved in the mineral exploration and development industry, including those risks set out in the Company's management's discussion and analysis as filed under the Company's profile at www.sedar.com. Forward-looking information in this news release is based on the opinions and assumptions of management considered reasonable as of the date hereof, including that all necessary governmental and regulatory approvals will be received as and when expected. Although the Company believes that the assumptions and factors used in preparing the forward-looking information in this news release are reasonable, undue reliance should not be placed on such information. The Company disclaims any intention or obligation to update or revise any forward-looking information, other than as required by applicable securities laws.


News Article | February 10, 2017
Site: www.theenergycollective.com

In a series of blog posts over the last several weeks, RAP has spotlighted the opportunities associated with beneficial electrification—the practice of electrifying appliances and machines that are currently powered by fossil fuels. Embracing beneficial electrification provides a significant opportunity for utilities, making them more competitive by giving them a “LEG up”—where “L” stands for emerging revenue streams associated with new load, “E” for potential environmental benefits, and “G” for better grid management. Utilities that embrace beneficial electrification opportunities like electric vehicles, space heating, and water heating, will set themselves up to sell electricity that is cleaner, manage their systems more cost-effectively, and offer services that customers increasingly want. Beneficial electrification promises significant environmental and public health benefits from both drawing upon a power sector with an improving emissions profile and replacing fossil-fueled energy end-uses with electricity where the grid is comparatively clean (e.g., through miles driven in an electric vehicle instead of a gasoline vehicle). Finally, keeping in mind what Teaching the Duck to Fly teaches us about the changing power sector and customer loads—especially net loads—beneficial electrification offers a key to intelligently managing the grid and integrating distributed resources. The opportunities that beneficial electrification can provide for utilities seem clear. But in today’s regulatory paradigm, utilities are regulated monopolies with respect to some or all of the “LEG up” benefits. Accordingly, some of these opportunities should also redound to the benefit of ratepayers. When, if, and how that happens, however, hinges on regulators’ understanding of beneficial electrification and its outcomes. This includes consideration of the extent to which any beneficial electrification services may be competitive and how revenue from such services should be treated. It could also include an examination of policy reasons why potentially competitive activities might be allowed for utilities and under what circumstances, how cost recovery for beneficial electrification investments occurs, and other issues. What does beneficial electrification (or strategic electrification, or smart electrification, or other equally apt terms) mean for utility regulators? First, this issue doesn’t rise above the noise of the routine regulatory agenda unless commissioners prioritize it. Why would they do that? They would, if they thought that beneficial electrification would position their states for a future with a higher share of renewable power on the grid (a priority that may be set by the executive or legislative branches, and may fall to the public utility commission (PUC) to implement). They also might prioritize it if customers clamor for cleaner choices. If beneficial electrification does become a priority in a state, a number of regulatory issues emerge. Among the questions that might arise are: We, at RAP, routinely talk with government officials about these sorts of questions. Because these issues are complicated, our discussions sometimes default to addressing the challenges. Answering tough questions also requires decision-makers to reconsider priorities, important cornerstones in and of themselves. Beneficial electrification provides a good reminder—for RAP as well as policymakers—that the flip side of challenge is opportunity. The real focus of our efforts together lies in creating greater value, helping to build the society that citizens want, and to make it work better and cost less. The post Utilities Can Get a “LEG” Up with Beneficial Electrification—But Regulators Also Have to be Ready appeared first on Regulatory Assistance Project.


News Article | February 22, 2017
Site: www.greentechmedia.com

What follows is a tale of two Dukes, one power plant and a bunch of hot air. As in steam. Steam produced by a combined heat and power plant that would burn natural gas on the campus of Duke University, but be owned and operated by Duke Energy. Duke the utility proposed the project for Duke the university (they share a common ancestor) in May as a way to install local generation while helping the host institution heat its classrooms, labs and hospital facilities. If the plant is approved, it could cut the university’s carbon emissions by reducing the need to burn natural gas in its campus steam plants. Clean energy advocates on campus and in the region had other ideas. They questioned the accounting Duke used to assess the benefits of the project, and warned that the project would create a long-term addition of fossil fuel infrastructure on a campus committed to carbon neutrality by 2024. Duke Energy, meanwhile, is hoping to gain experience in the up-and-coming CHP technology for development elsewhere in its territory. CHP works particularly well for college campuses, which have the electrical load and heating needs to justify such projects. Many of those campuses also hold strong public commitments to climate-change mitigation. "We definitely see this as a growing business within Duke Energy," Duke Energy spokesperson Randy Wheeless said of CHP. "There’s nothing like going to one that's already in existence and operating, and we hope the Duke University one will be that one for us. [...] We want to make sure this one goes correctly." This proposed 21-megawatt turbine, quite small by power plant standards, has shown the challenges of winning over public support for a new energy asset that's cleaner than traditional gas generation, but not absolutely clean. The proposal developed by the university administration and Duke Energy promises several big benefits. The gas plant will capture waste heat from electricity generation and pump it onto campus, making it a more efficient use of gas than traditional generators. That incidental heat source would allow the university to pull back on the natural gas it currently burns in two campus steam plants. A presentation on the topic says getting steam from the CHP project will cut campus natural-gas consumption by a whopping 50 percent, and reduce emissions counted under the Climate Action Plan by 18 percent. This tackles a major source of greenhouse gas emissions on campus, as well as avoiding $2.5 million in investments that would otherwise be needed for hot water infrastructure. The university expects a two- to three-year payback. Additionally, having an on-campus power generator serves the resilience of the university’s labs and hospital in the face of grid interruptions like hurricanes or thunderstorms. Diesel backup generators currently serve that role, but gas turbines are generally more reliable machines. Duke Energy would need to perform "minor relaying additions and programming" to enable this microgrid application, said Michael Schoenfeld, vice president for public affairs and government relations. A clean alternative like a solar array cannot guarantee backup at night, and pairing energy storage with solar would cost a lot more for this service than the gas turbine will at this time. The administration views resiliency improvement as the top priority in the project, Schoenfeld noted, followed by emissions reductions and cost savings. These benefits come at the expense of a new facility built to burn natural gas, and that on its face conflicts with the institutional drive toward a smaller carbon footprint. After the administration announced the plan in May, campus activism forced a pause for additional review. Duke Energy asked the North Carolina Utilities Commission to postpone a hearing on the project from Jan. 24 until May, campus newspaper The Chronicle reported. Some of the concerns centered on the internal processes that led to the proposal, and whether or not the campus sustainability bodies were adequately included. The local response also posed a deeper energy question: Should an institution committed to reducing its climate impact embrace a fossil fuel technology, even a relatively clean one? In this case, Duke aims to host a gas plant on campus and claim the carbon reductions it allows versus existing campus emissions. Since the new plant's emissions come from Duke Energy's business in generating electricity for the grid, the university would count them as part of the emissions factor for purchased electricity, not as emissions originating from campus. A pair of professors from Duke’s Nicholas School of the Environment argued in The Chronicle that the university should account for the plant’s carbon emissions when assessing the benefits of the proposal. “Under this alternative assumption, the net greenhouse gas emission benefits to Duke University are dramatically reduced, since the carbon intensity of electricity produced at the new CHP plant is considerably higher than the carbon intensity of the current Duke Energy electricity generation fleet,” they wrote in a letter to The Chronicle. When factoring in those emissions, plus transmission losses and upstream leakages associated with the additional gas consumption, the professors calculated a net Climate Action Plan emissions reduction of less than 4 percent. This debate comes down to a matter of where to draw the boundaries of responsibility. If Duke Energy built the plant nearby on land it acquired, and the university bought the steam and burned less fuel, there would be a stronger case for the 18 percent emissions reduction. But that’s not the case here. “This plant would not be built without Duke University support," said sophomore Claire Wang, who runs the Duke Climate Coalition. “We tout ourselves as a climate leader, and part of that is being responsible for the emissions that we cause.” The administration has asked the Campus Sustainability Committee to evaluate this and other questions about the proposal, and to make a recommendation about how to proceed. They are open to a change in the carbon accounting, Schoenfeld said. The hope is to get an answer by May, which would guide the administration's approach to a board of trustees meeting that month. If all goes well for the plan, the utility could then move ahead at the PUC. The questions facing utility regulators touch on a different set of concerns, specifically the equity of who pays for what. As Duke Energy's first CHP project in the state, this would set a broader precedent that the regulated utility can leverage ratepayer funds for a grid-serving generator that also delivers a specific, localized benefit to a particular customer. Ratepayers will get a deal from the Duke project that's as cost-competitive as more conventional, large-scale gas plants, Wheeless said. The utility would save on cost thanks to "a very attractive lease price" for the campus land, and the university's steam payments will go back to ratepayers. Ratepayers, though, would have to pay $55 million for the ability to create that steam in the first place. The ratepayer dollars going to create a resource for a particular host customer is what sets this apart from typical plant construction. There are some similar cases in the world of microgrids, with an important distinction in payment structure. Arizona Public Service is building two microgrids, one at a military base and one at a new data center. The host customer contributes for the resilience benefits in the event of an outage. The microgrids will provide grid power and other services most of the time, so APS asked regulators for permission to rate-base the costs for those services. A microgrid collaboration in Denver between utility Xcel Energy and Panasonic includes solar panels and a big battery on the latter's new facility there. Panasonic contributes some of the assets and gets backup power for its operations center; Xcel gets to rate-base its expenses for the assets that will improve grid reliability the rest of the time. Duke, on the other hand, has been piloting a “utility-controlled, single-customer microgrid” model, and has been able to enter costs into the rate base when the microgrid serves the distribution grid, rather than splitting costs with a host client. Now, this Duke project is not a microgrid, yet. That means the only benefit the school gets that the grid doesn't is the heat, which the school will pay for. Critics could still charge that if the utility wants to spend time on projects with a more localized benefit, it should extract more in return for the ratepayers at large. A plant that only served one customer wouldn't be a good candidate for the rate base, Wheeless said, but this is different. "In this case, it's connected to a substation that serves that customer but also serves other people in the community too," he said. Down the road, if the Dukes pursue the microgrid expansion, they could work out an appropriate cost-sharing agreement on that service. The way the NC Utilities Commission rules on CHP cost sharing will shape the utility's options in paying for projects like this, which will affect its willingness to pursue them. One lesson from this experience is already clear: Rolling out new CHP infrastructure isn't a technical challenge so much as a social one.


The year 2016 saw a low price level on the natural gas market, which helped increase the sales volume by 14%. Under the influence of the natural gas price, the revenue dropped by 11% against the previous year and amounted to 392.3 million euros. However, the EBITDA*, owing to the sales volume, grew by 11% to 76.5 million euros. The company’s net profit in the past year was 37.5 million euros, up from 30.5 million euros in 2015. The performance was boosted by the inception of natural gas trading in the neighbouring countries, which was a strategic step by Latvijas Gāze to get acquainted with the open market and competitive circumstances. The customers abroad were sold 132 million cubic metres of natural gas or 9% of the total annual sales volume. The Latvian consumers were sold 1.375 million cubic metres of natural gas, which is 4% more than in 2015. The investment amount in 2016 remained at the level of previous years – 29.6 million euros. Latvijas Gāze still prioritises safety and makes further investments in the modernisation of infrastructure to improve efficiency and reduce the environmental impact. Nevertheless, the year 2016 also saw a decrease by 2.1 million euros in the profit gained from the transmission and storage services spun off. This primarily stems from the decrease in storage volumes and the tariffs which have not changed since 2008. Latvijas Gāze is actively getting ready for the opening of the natural gas market on April 3. Legal entities will receive offers of further cooperation in March, while households will have an option to keep receiving natural gas for a tariff approved by the PUC. * EBITDA – earnings before interest, corporate income tax, depreciation and amortisation, and impairment of fixed assets.


The year 2016 saw a low price level on the natural gas market, which helped increase the sales volume by 14%. Under the influence of the natural gas price, the revenue dropped by 11% against the previous year and amounted to 392.3 million euros. However, the EBITDA*, owing to the sales volume, grew by 11% to 76.5 million euros. The company’s net profit in the past year was 37.5 million euros, up from 30.5 million euros in 2015. The performance was boosted by the inception of natural gas trading in the neighbouring countries, which was a strategic step by Latvijas Gāze to get acquainted with the open market and competitive circumstances. The customers abroad were sold 132 million cubic metres of natural gas or 9% of the total annual sales volume. The Latvian consumers were sold 1.375 million cubic metres of natural gas, which is 4% more than in 2015. The investment amount in 2016 remained at the level of previous years – 29.6 million euros. Latvijas Gāze still prioritises safety and makes further investments in the modernisation of infrastructure to improve efficiency and reduce the environmental impact. Nevertheless, the year 2016 also saw a decrease by 2.1 million euros in the profit gained from the transmission and storage services spun off. This primarily stems from the decrease in storage volumes and the tariffs which have not changed since 2008. Latvijas Gāze is actively getting ready for the opening of the natural gas market on April 3. Legal entities will receive offers of further cooperation in March, while households will have an option to keep receiving natural gas for a tariff approved by the PUC. * EBITDA – earnings before interest, corporate income tax, depreciation and amortisation, and impairment of fixed assets.


The year 2016 saw a low price level on the natural gas market, which helped increase the sales volume by 14%. Under the influence of the natural gas price, the revenue dropped by 11% against the previous year and amounted to 392.3 million euros. However, the EBITDA*, owing to the sales volume, grew by 11% to 76.5 million euros. The company’s net profit in the past year was 37.5 million euros, up from 30.5 million euros in 2015. The performance was boosted by the inception of natural gas trading in the neighbouring countries, which was a strategic step by Latvijas Gāze to get acquainted with the open market and competitive circumstances. The customers abroad were sold 132 million cubic metres of natural gas or 9% of the total annual sales volume. The Latvian consumers were sold 1.375 million cubic metres of natural gas, which is 4% more than in 2015. The investment amount in 2016 remained at the level of previous years – 29.6 million euros. Latvijas Gāze still prioritises safety and makes further investments in the modernisation of infrastructure to improve efficiency and reduce the environmental impact. Nevertheless, the year 2016 also saw a decrease by 2.1 million euros in the profit gained from the transmission and storage services spun off. This primarily stems from the decrease in storage volumes and the tariffs which have not changed since 2008. Latvijas Gāze is actively getting ready for the opening of the natural gas market on April 3. Legal entities will receive offers of further cooperation in March, while households will have an option to keep receiving natural gas for a tariff approved by the PUC. * EBITDA – earnings before interest, corporate income tax, depreciation and amortisation, and impairment of fixed assets.


News Article | February 15, 2017
Site: www.renewableenergyworld.com

The Maine Public Utilities Commission (PUC) this week approved revisions to the state’s rules on net metering.


The year 2016 saw a low price level on the natural gas market, which helped increase the sales volume by 14%. Under the influence of the natural gas price, the revenue dropped by 11% against the previous year and amounted to 392.3 million euros. However, the EBITDA*, owing to the sales volume, grew by 11% to 76.5 million euros. The company’s net profit in the past year was 37.5 million euros, up from 30.5 million euros in 2015. The performance was boosted by the inception of natural gas trading in the neighbouring countries, which was a strategic step by Latvijas Gāze to get acquainted with the open market and competitive circumstances. The customers abroad were sold 132 million cubic metres of natural gas or 9% of the total annual sales volume. The Latvian consumers were sold 1.375 million cubic metres of natural gas, which is 4% more than in 2015. The investment amount in 2016 remained at the level of previous years – 29.6 million euros. Latvijas Gāze still prioritises safety and makes further investments in the modernisation of infrastructure to improve efficiency and reduce the environmental impact. Nevertheless, the year 2016 also saw a decrease by 2.1 million euros in the profit gained from the transmission and storage services spun off. This primarily stems from the decrease in storage volumes and the tariffs which have not changed since 2008. Latvijas Gāze is actively getting ready for the opening of the natural gas market on April 3. Legal entities will receive offers of further cooperation in March, while households will have an option to keep receiving natural gas for a tariff approved by the PUC. * EBITDA – earnings before interest, corporate income tax, depreciation and amortisation, and impairment of fixed assets.

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