Sioux Falls, SD, United States
Sioux Falls, SD, United States

NorthWestern Corporation owns NorthWestern Energy, a utility company that serves South Dakota, Nebraska, and Montana that is based in Sioux Falls. As of December 31, 2007, the company serves approximately 650,000 customers.The company's corporate headquarters are located in Sioux Falls while the headquarters for the South Dakota operations are in Huron, SD. The Montana operations were acquired around 2000 after that state passed some legislation allowing the electric utility industry to be 'unbundled'. Out of state investors then immediately acquired the generation assets of Montana Power, leaving that part of the territory vulnerable to high "spot" prices on the energy market . Wikipedia.

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Servaites J.D.,NorthWestern Energy | Savoie B.M.,Northwestern University | Savoie B.M.,NorthWestern Energy | Brink J.B.,NorthWestern Energy | And 5 more authors.
Energy and Environmental Science | Year: 2012

We propose a model for geminate electron-hole dissociation in organic photovoltaic (OPV) cells and show how power conversion efficiencies greater than those currently achieved might be realized via design strategies employing moderate optical bandgaps and enhanced charge delocalization near the donor-acceptor interface. Applying this model to describing geminate electron-hole dissociation via charge transfer (CT) states, we find good agreement with recently published high-efficiency experimental data. The optimal bandgap for current-generation organic active layer materials is argued to be ∼1.7 eV - significantly greater than in previous analyses, including the Shockley-Queisser approach based upon non-excitonic solar cell dynamics. For future higher efficiency OPVs, the present results show that the optimal bandgap should be slightly lower, ∼1.6 eV. Finally, these results support design strategies aimed at enhancing mobility near the donor-acceptor interface and reducing the electron-hole binding energy, rather than striving to further reduce the bandgap. This journal is © The Royal Society of Chemistry 2012.

News Article | December 16, 2016

LITTLE ROCK, AR--(Marketwired - December 16, 2016) - On Dec. 7, America commemorated the 75th anniversary of the bombing of Pearl Harbor. Nine days later, an organization in Little Rock, Ark., will likewise celebrate 75 years of existence. On Dec. 16, 1941, in support of the American war effort, 11 electric utilities agreed to pool their resources to keep power flowing to Jones Mill -- an aluminum production facility outside Malvern, Ark. President Franklin Roosevelt's wartime goal to produce 50,000 airplanes per year had created the need for huge quantities of aluminum, and Jones Mill's operation would require 120 megawatts of power -- exceeding its home state's installed capacity of 100 MW at the time. From the utilities' partnership, Southwest Power Pool (SPP) was formed, and the new organization was successful in pooling power to support the plant. After the war, SPP continued as a leader providing safe, reliable power to U.S. homes. SPP today is a regional transmission organization (RTO): a not-for-profit, federally regulated service organization that ensures the reliable operation of a portion of the nation's power grid on behalf of its member companies, with more than 50,000 MW in capacity. SPP describes itself as the air-traffic controller of the power grid. Air-traffic controllers do not own the airports in which they operate or the planes they direct but are responsible for ensuring air travelers depart, fly and land safely. Similarly, SPP does not own the power stations it directs or the transmission lines across which electricity flows in its footprint, but it partners with generators, transmission owners, municipalities, power marketers, state and federal agencies, electric cooperatives and others to ensure the cost-effective and reliable delivery of power across a 14-state region. Though SPP works at the wholesale level and thus doesn't directly serve end users and ratepayers, it does benefit them. A recent study conducted by SPP and validated by the Brattle Group showed transmission investments in the SPP region had, on average, a benefit-to-cost ratio of 3.5-to-1. That means every dollar spent to build or upgrade transmission lines throughout SPP's region will ultimately produce $3.50 in electricity production cost savings and other benefits. In addition to planning transmission infrastructure, SPP facilitates the sale and purchase of electricity through its Integrated Marketplace, a wholesale electric market. SPP's marketplace launched in 2014 and has since reduced the cost of electricity in the organization's region by more than $1 billion. These and other services provide net benefits to SPP's members in excess of $1.4 billion annually at an overall benefit-to-cost ratio of more than 10-to-1. For the typical end-use customer using 1,000 kWh per month that means $68 of benefits a year at the cost of just 62 cents monthly. Or, put another way, without the services SPP provides its members, a ratepayer's $100 electric bill would be $105.65. Throughout its 75 years, SPP has evolved and grown from an affiliation of 11 companies with a common goal in 1941 to an organization employing about 600 professionals in support of nearly 100 member companies across a region spanning from the Canadian border in the north to Louisiana in the south and from southeastern Missouri to northwestern Montana. SPP attributes its legacy of success to the strength of its stakeholder relationships. In the foreword to a book published this year chronicling SPP's history, its President and CEO Nick Brown said, "Reliability is job one for SPP. We exist to help our members keep the lights on, today and in the future. We do so not through hard work, innovation or efficiency, though each is a necessary component of our success. For SPP, reliability is accomplished through strong, healthy relationships with those we serve." Because of the strength of those relationships, its legacy of success and deliberate focus on continuous improvement and building consensus among its members, SPP has every reason to think its future is just as bright as its history. Southwest Power Pool, Inc. manages the electric grid and wholesale energy market for the central United States. As a regional transmission organization, the nonprofit corporation is mandated by the Federal Energy Regulatory Commission to ensure reliable supplies of power, adequate transmission infrastructure and competitive wholesale electricity prices. Southwest Power Pool and its diverse group of member companies coordinate the flow of electricity across 60,000 miles of high-voltage transmission lines spanning 14 states. The company is headquartered in Little Rock, Ark. Learn more at Acciona Wind Energy USA, LLC; American Electric Power (AEP Oklahoma Transmission Company, Inc.; AEP Southwestern Transmission Company, Inc.; Public Service Company of Oklahoma, Southwestern Electric Power Company); Arkansas Electric Cooperative Corporation; Basin Electric Power Cooperative; Board of Public Utilities of Kansas City, Kansas; Boston Energy Trading and Marketing, LLC; Calpine Energy Services, L.P.; Cargill Power Markets LLC; Central Power Electric Cooperative, Inc.; Cielo Wind Services, Inc.; City of Coffeyville; City of Independence, Missouri; City Utilities of Springfield; Clarksdale Public Utilities Commission; Cleco Power, LLC; Corn Belt Power Cooperative; CPV Renewable Energy Company, LLC; Dogwood Energy, LLC; DTE Energy Trading, Inc.; Duke Energy Transmission Holding Company, LLC; Duke-American Transmission Company, LLC; Dynegy Power Marketing, Inc.; East River Electric Power Cooperative, Inc.; East Texas Electric Cooperative, Inc.; EDP Renewables North America LLC; El Paso Marketing Company, LLC; Enel Green Power North America, Inc.; Entergy Asset Management; Entergy Services, Inc.; Exelon Generation Company, LLC; Flat Ridge 2 Wind Energy, LLC; Golden Spread Electric Cooperative, Inc.; Grain Belt Express Clean Line LLC; Grand River Dam Authority; Harlan Municipal Utilities; Heartland Consumers Power District; Hunt Transmission Services, LLC; ITC Great Plains, LLC; Kansas City Power & Light Company (KCP&L Greater Missouri Operations Company); Kansas Electric Power Cooperative, Inc.; Kansas Municipal Energy Agency; Kansas Power Pool (KPP); Lafayette Utilities System; Lea County Electric Cooperative, Inc.; Lincoln Electric System; Louisiana Energy and Power Authority; Luminant Energy Company, LLC; Mid-Kansas Electric Company, LLC; Midwest Energy, Inc.; Midwest Gen, LLC; Missouri Joint Municipal EUC; Missouri River Energy Services; Mountrail-Williams Electric Cooperative; Municipal Energy Agency of Nebraska; Nebraska Public Power District, NextEra Energy Resources, LLC; NextEra Energy Transmission, LLC; Noble Americas Gas & Power Corp; Northeast Nebraska Public Power District; Northeast Texas Electric Cooperative, Inc.; Northwest Iowa Power Cooperative; NorthWestern Energy; NRG Power Marketing, LLC; OGE Transmission, LLC; Oklahoma Gas and Electric Company; Oklahoma Municipal Power Authority; Omaha Public Power District, Plains and Eastern Clean Line LLC; Prairie Wind Transmission, LLC; Public Service Commission of Yazoo City; Public Service Company of Oklahoma; Rayburn Country Electric Cooperative; Shell Energy North America (US), L.P.; South Central MCN, LLC; Southwestern Electric Power Company; Southwestern Power Administration; Sunflower Electric Power Corporation; Tenaska Power Services Co.; Tex-La Electric Cooperative of Texas, Inc.; The Central Nebraska Public Power & Irrigation District; The Empire District Electric Company; Transource Energy, LLC; Transource Missouri, LLC; Tri-County Electric Cooperative, Inc.; Tri-State Generation and Transmission Association, Inc.; Westar Energy, Inc. (Kansas Gas and Electric Company); Western Area Power Administration - Upper Great Plains Region; Western Farmers Electric Cooperative; Williams Power Company, Inc.; Xcel Energy (Southwestern Public Service Company, Xcel Energy Southwest Transmission Company, LLC); XO Energy SW, LP.

News Article | August 22, 2016

North America stole the spotlight last month when the United States, Mexico and Canada committed to producing 50 percent of their power from "clean" energy resources, including hydropower, wind, solar and nuclear plants, by 2025. The goal could also apply to fossil fuel plants with carbon capture, as well as energy storage and energy efficiency measures. The initiative is considered ambitious but achievable, and a key part of reaching each nation's pledge under the Paris climate accord. Sierra Club Executive Director Michael Brune said the agreement demonstrates "North American unity behind a consensus for strong global climate action," Bloomberg reports. How the U.S. clean energy transition plays out depends in large part on policy changes at the state and local level, however. Below we chronicle some of the most significant state-level policy developments from recent weeks on the topics of distributed energy resources, net metering, community solar, grid modernization, renewable portfolio standards, resource planning and mergers (click to jump to a section). In June, the Montana Public Service Commission voted to suspend the avoided cost rates for small-scale solar power guaranteed under the federal Public Utility Regulatory Policies Act (PURPA), local news outlet KPAX News reports. Four years ago, Montana’s PSC set the rate for projects 3 megawatts and below at $66 per megawatt hour. NorthWestern Energy argued that that rate is unfair to its customers, and the PSC granted the utility’s request to suspend the state's guaranteed rate in a 3-2 vote. Solar company FLS Energy of Asheville, North Carolina, which has invested over $700,000 in Montana projects, is now seeking a rehearing of the PSC decision. "Well, if the decision stands as issued, that will be the end of our development activities in Montana. None of our projects will go forward," Steve Levitas, a vice president at FLS, told Montana Public Radio. On June 9, Texas regulators agreed to open a docket related to distributed energy resources and interconnection agreements. According to Advanced Energy Economy’s PowerSuite, the rulemaking will address which type of entity -- the end-use customer, the owner of the DG facility, the owner of the rights to the energy produced from the facility, or the owner of the location where the DG facility is located -- should sign an interconnection agreement with an electric utility for the operation of on-site distributed generation. Initial comments on the proposal are due by July 29 and reply comments are due by August 12, 2016. On June 13, the CPUC held a workshop on Commissioner Michael Florio's April 4 proposal to offer utilities a better rate of return for DER projects that replace more expensive capital upgrades. This is the first CPUC proposal to specifically attempt to resolve the "conflict between the commission’s policy objectives and the utilities’ financial imperatives.” Florio leads the CPUC’s distribution resources plan proceeding (14-08-013), which is creating values for DERs as potential replacements for grid investments. Post-workshop comments were due by July 8. Also in California, regulators recently issued a decision revising the state’s Self-Generation Incentive Program, which has some significant flaws. The new structure seeks to clarify which types of resources qualify for the incentive program and how the incentives are awarded. It also includes a 15 percent carve-out for residential systems. Separately, on June 23, the CPUC adopted a new model and five-year pilot process to accelerate the interconnection of renewable and distributed energy resources to the electric grid. The proposal is available here. On June 30, New York's six regulated utilities filed their Initial Distributed System Implementation Plans (DSIPs) as part of the state’s Reforming the Energy Vision (REV) proceeding. The filings, each more than 300 pages, highlight which technologies utilities see as fundamental to remaking the operation of the electric system and integrating distributed energy resources. Among the findings utilities identified the potential to invest in three advanced distribution management systems, 6.8 million smart meters, 14 non-wires alternatives, such as ConEd’s Brooklyn Queens Demand Management Program. While integral to the REV process, the DSIP filings do not explicitly address how technology investments will combine with price signals in the future to create new markets, which means the end goal of REV is still a long way off. However, stakeholders have started to grapple with questions around price signals for distributed energy resources in a related proceeding on the value of DERs. In April, a wide array of parties submitted proposals for alternatives to New York’s current retail-rate net metering policy. The filings offered DER valuation proposals that can be adopted before the end of 2016 and a methodology and process for establishing a full value of DERs based on the LMP+D approach -- where “LMP” represents the location-based marginal price of energy and “D” represents the value provided to the electric distribution system. GTM Squared recently chronicled several of the proposals in a multi-part series. Part 1 looked at a landmark agreement between six utilities and three major solar players dubbed the Solar Progress Partnership. Part 2 looked at proposals from the Solar Energy Industries Association and Vote Solar; the Environmental Defense Fund; and the Advanced Energy Economy Institute in partnership with the Alliance for Clean Energy New York and the Northeast Clean Energy Council. On June 10, stakeholders submitted reply comments, some of which are detailed in Part 3. Rather than have regulatory staff write a report on the proposals, an administrative law judge announced in late May that key players in the docket are to participate in “informal and collaborative talks” on the valuation of DERs and produce recommendations on an interim NEM alternative for regulators to act on before the end of the year. On June 17, the commission announced the creation of an Interconnection Policy Working Group to explore non-technical issues relevant to the interconnection of distributed generation. According to AEE’s PowerSuite, stakeholders that wish to participate in the working group were asked to provide a brief description of their interest to the commission by June 27. The Pennsylvania Public Utility Commission continues to weigh changes to the state’s net metering rules after alternative energy regulations were rejected, revised, and then rejected again by an independent review board, the Pittsburgh Post-Gazette reports. The most controversial section of the rules proposes to drop the cap on the size of alternative energy systems that qualify for net metering and can be reimbursed at retail rates for the excess electricity they send back to the grid. Despite the Independent Regulatory Review Commission’s recent rejection, the rules may not be dead. Pennsylvania’s Regulatory Review Act allows the PUC to proceed with the regulations as they are written, despite the review board’s disapproval. Committees in the state House and Senate could then block the rules, but it’s currently unclear if lawmakers would take action. The PUC has not said what it will do next. “We will carefully review IRRC’s disapproval order when it is published, and then determine the most appropriate course of action,” PUC spokesperson Nils Hagen-Frederiksen said. In April, Maine Gov. Paul LePage vetoed a landmark solar energy bill that would have ended conventional retail-rate net metering but provided a significant boost to overall solar development in the state. In January, Central Maine Power, the dominant utility in the state, filed a notice that it had reached its net metering cap (1 percent of peak demand) at the end of 2015. In the absence of legislation governing the next step, the focus now shifts to the state regulators. According to EQ Research, the Maine PUC is currently seeking comments and information regarding net energy billing rules (Chapter 313). Comments on whether the current rules should be modified or whether any other action should be taken are due by July 22. The PUC is specifically seeking comments on the following issues: The New Hampshire PUC has opened a new docket (DE 16-576) to develop alternative net energy metering tariffs pursuant to H.B. 1116, which increased the state’s net metering cap from 50 megawatts to 100 megawatts. Gov. Hassan signed H.B. 1116 into law in early May. In addition to raising the cap, the bill directed regulators to initiate and conclude a proceeding to develop new alternative net metering tariffs or other regulatory mechanisms applicable to customer-sited generation. According to EQ Research, the PUC must consider numerous issues in this proceeding, including: In June, San Diego Gas & Electric became the first investor-owned utility in California to meet its net metering cap. SDG&E will now move to NEM 2.0, in which PV customers will continue to receive a net metering credit, but they will be required to transition to time-of-use rates in 2017. Customers who installed rooftop solar prior to the limit being reached are grandfathered in under the existing rules for 20 years from the date they installed solar. The Colorado PUC approved a community solar proposal from the state’s largest utility, Xcel Energy, and three solar companies last month, after rejecting the plan earlier this year. The PUC reversed its initial ruling following a hearing on June 1 and the submission of further evidence. Regulators determined that the parties had successfully demonstrated that the proposal was in the public interest, and found that the scheme would benefit low-income individuals and businesses that wished to promote solar energy, PV Tech reports. The approved proposal will add 60 megawatts of community solar through a request for proposals this year. It also includes a carve-out for Xcel to own up to 4 megawatts of community solar, exclusive to serving low-income customers and nonprofit organizations. The agreement stemmed from criticisms that Xcel has been slow-rolling Colorado’s community solar program, and that the program structure led to negative renewable energy credit prices in a bid for 29.5 megawatts of solar 2015. With the commission’s recent approval, development of the 29.5 megawatts -- to be built by SunShare, Clean Energy Collective and Community Solar Energy, the three winners of Xcel’s 2015 tender -- can progress. Nearly every proposed solar garden project in Minnesota has faced delays under Xcel Energy’s community solar program, The Minneapolis Star Tribune reports. A year and a half after the program launched -- and with more than 900 active applications pending -- only three gardens are on-line, generating a total of less than 1 megawatt of power. Solar developers blame Xcel for the delays and have filed a complaint with regulators over Xcel’s high interconnection costs. An independent engineering report backed up some of the solar companies’ claims. The utility, meanwhile, says it has attempted to speed up the program rollout, and that some delays are the fault of developers. Commonwealth Edison has introduced comprehensive and controversial legislation with its parent company, Exelon, that the utilities say is intended to enhance the grid and drive the adoption of clean energy technologies. The utilities launched the Next Generation Energy Plan (SB 1585) in May after a previous version of the bill failed to win support. The new bill contains a controversial provision providing assistance to Exelon’s struggling nuclear power plants, but includes a number of other alternative energy measures that the utilities hope will help it pass. The utilities claim the new bill will help to jump-start the Illinois clean energy market by doubling energy-efficiency programs, creating roughly $4.1 billion in energy savings for customers, including $650 million in efficiency savings for low-income customers. The bill also includes a smart inverter rebate and more than $140 million per year in new funding for solar development, $250 million to develop five microgrids around critical infrastructure, and calls for strengthening and expanding the state’s renewable portfolio standard. ComEd is hopeful that the Illinois General Assembly will take up and pass its energy plan when the new session begins this fall, but that outcome is not assured. The bill still faces pushback on the nuclear income guarantee issue. In addition, solar companies and advocates have been critical of the proposal because it would end net metering, introduce universal demand charges, and allow ComEd to own community solar projects and compete with other developers. These critics allege a new solar advocacy group founded by ComEd was created specifically to advance the utility-backed legislation. “We don’t see that there needs to be a competing nonprofit to do this work,” Lesley McCain, executive director of the Illinois Solar Energy Association, told Midwest Energy News. “It appears they would be starting this group during bill negotiations to advance their own agenda.” The Indiana Utility Regulatory Commission has approved a settlement agreement allowing Duke Energy to advance its $1.4 billion modernization plan. The utility reached a consensus with industry, consumer and environmental groups on the seven-year plan in March after regulators denied Duke’s original proposal the previous year, citing a lack of specifics. As part of the settlement, Duke Energy will reduce the level of capital investments recovered through the plan's customer bill tracker by approximately $400 million. Part of the reduction comes from $192 million earmarked for new advanced digital meters. Duke will not recuperate smart meter costs through the monthly bill tracker, but retains the ability to pursue the meters and defer their costs for consideration in a future rate case. If the utility decides to pursue smart meters, as part of the settlement, it has committed to exploring energy-efficiency pilot programs made possible with smart meter technology. Consumer benefits from the plan include updating and replacing aging energy grid infrastructure and installing “self-healing” systems to allow for fewer and shorter power outages. New equipment such as line sensors will enable the company to provide customers more information about power outages affecting them and estimated restoration times. The grid system will also see energy savings from technology that optimizes voltage and reduces overall power consumption by about 1 percent on upgraded power lines. As a result of the plan, customers will see a gradual rate increase averaging 0.75 percent per year between 2017 and 2022. Stakeholders in the settlement included the Indiana Office of Utility Consumer Counselor, the Duke Energy Indiana Industrial Group, Companhia Siderurgica Nacional, Steel Dynamics, Wabash Valley Power Association, Indiana Municipal Power Agency, Hoosier Energy Rural Electric Cooperative and the Environmental Defense Fund. The District of Columbia City Council unanimously approved legislation to increase the city’s renewable portfolio standard from 20 percent by 2020 to 50 percent by 2032, and to increase D.C.’s solar requirements by 5 percent by the same year. The bill now awaits the signature of Mayor Muriel Bowser. The Chesapeake Climate Action Network (CCAN) expects the legislation to create incentives for 1.5 gigawatts of new solar and wind power and to quadruple the number of jobs in D.C.’s solar industry, which currently employs 1,000 people, Solar Industry reports. According to the summary of the bill, the legislation also “increases financial penalties for electricity suppliers who fail to comply with the renewable energy portfolio standard for the applicable year; and establishes a program within the Department of Energy and the Environment to assist low-income homeowners with installing solar systems on their homes.” In late June, the Rhode Island legislature passed a bill (S.2185/H.7413) to increase the state's renewable energy target from 14.5 percent by 2019 to 38.5 percent by 2035. Governor Gina Raimondo is expected signed the bill into law. Rhode Island’s original RPS target was for 16 percent renewable energy by 2019. However, in December 2014, the PUC decided to delay the program for one year, reducing the 2019 goal from 16 percent to 14.5 percent. An amendment attached to new legislation allows the PUC more flexibility to delay the RPS if there is a shortage of renewable energy credits. The wind industry praised the legislation. Wind farm investment in Rhode Island has already attracted $20 million in total capital investment to the state economy, according to the American Wind Energy Association. According to the Wind Energy Foundation, growing wind power in Rhode Island could result in $240 million in electricity bill savings by 2050. On June 30, National Grid announced it had brought a 20-mile-long, 5-million-pound underwater cable between the Rhode Island mainland and Block Island to shore. The cable will bring power from the five-turbine Deepwater Wind Block Island Wind Farm project to the mainland power grid, Renewable Energy World reports via Generation Hub. On June 30, the Massachusetts State Senate passed a bill (S.2372) that would require utilities to purchase 2,000 megawatts of offshore wind and a minimum of 12,450,000 megawatt-hours (roughly 1,800 megawatts) of hydropower and onshore wind by 2027. Environmentalists and clean energy advocates praised the passage, while power generators expressed concern, MassLive reports. "We are extremely disappointed and concerned about key provisions in this energy bill, which carves out nearly 50 percent of Massachusetts' electricity market in the form of subsidized long-term contracts," said Dan Dolan, president of the New England Power Generators Association, said in a statement. "Not only will this lead to a dramatic increase in electricity costs for Commonwealth businesses and consumers, it will hurt local energy innovation and undermine billions of dollars in new investments being made here today." The Senate will now conference with the House, which passed its own clean energy bill (H. 4385) last month. The House bill would require utilities to enter into 15- to 20-year contracts for 1,200 megawatts of offshore wind and roughly 1,200 megawatts of hydropower. Talks are expected to begin immediately and to wrap up before the legislative session ends July 31. On June 28, the Vermont Public Service Board announced the implementation of the state’s renewable energy standard (RES) that requires utilities to procure 55 percent of the electricity sold to customers from renewable sources in 2017, increasing gradually to 75 percent in 2032. In 2017, at least 1 percent must come from new, distributed renewable resources, such as net-metered solar systems, rising to 10 percent by 2032. According to the release: “The RES also establishes an energy transformation category under which utilities can either invest in projects that directly reduce the fossil-fuel consumption of their customers, through measures like weatherization, the installation of cold-climate heat pumps, or clean vehicle technologies, or procure additional distributed renewable generation. To meet the requirements of this category, utilities must demonstrate fossil-fuel savings equivalent to 2 percent of their annual retail sales or procure an equal amount of additional renewable generation. This amount will increase to 12 percent by 2032.” Georgia Power plans to add 1,200 megawatts of renewable energy to its electrical generation portfolio over the next five years under an agreement with the state's Public Service Commission, The Atlanta Business Chronicle reports. Georgia Power agreed to add 1,050 megawatts of utility-scale renewable power through two separate requests for proposals -- the first 525 megawatts would go into service in 2018 and 2019, and the other 525 megawatts would go into service in 2020 and 2021. Most of the renewable commitments will come in the form of solar power, but the initiative calls for up to 300 megawatts of wind energy. In addition, Georgia Power agreed to make its biggest commitment to distributed generation to date, with 150 megawatts of renewable distributed energy resources installed by the end of 2018. The PSC is scheduled to vote on the agreement in late July. California Last month, Pacific Gas & Electric announced a plan to replace Diablo Canyon’s 2.3 gigawatts of generation capacity, about 8.6 percent of the state’s electricity production, with a host of zero-carbon emissions resources over the next nine years. Diablo Canyon, the state’s last working nuclear reactor, will close by 2025. The nuclear capacity will be replaced by lots of new solar and wind power, as well as other greenhouse-gas-free energy resources such as energy efficiency, demand response, energy storage, and other reliable demand-side resources. This is the first time a U.S. nuclear reactor closure has come with the guarantee of promoting carbon-free resources. It represents an enormous opportunity for the renewable energy sector, but advocates for climate action argue that keeping the carbon-free nuclear plant on-line is actually the best thing the utility could do to mitigate emissions. Critics say the plan diverts money from climate change and is really designed to make PG&E money. Others argue that closing the plant will save money and carbon. Last month’s proposal will now go to the California Public Utilities Commission for review and possible approval. The proposal can be read in its entirety here. Virginia Gov. Terry McAuliffe issued an executive order on June 28 directing the creation of a state climate commission to advise the governor on how to reduce greenhouse gas emissions and incorporate clean energy into the state’s power grid. Virginia Secretary of Natural Resources Molly Ward will convene the workgroup and recommend concrete steps to reduce carbon pollution from Virginia’s power plants. Gov. David Ige announced the appointment of attorney Thomas Gorak to the Hawaii PUC on June 29, just days before the three-member regulatory body is expected to rule on NextEra Energy’s $4.3 billion acquisition of Hawaiian Electric Co. Analysts believe Gorak is skeptical of the deal, which could affect the outcome. Some are calling the appointment illegal and unethical, but the attorney general’s office says the appointment is valid, KHON News reports. Gov. Ige said he waited to announce a replacement because he thought a decision on the NextEra-HECO merger would have been issued by now. Meanwhile, billionaire Warren Buffett may be interested in purchasing HECO if state regulators don't approve of NextEra’s acquisition, Pacific Business News reports. MidAmerican Energy Services LLC, owned by Buffett’s Berkshire Hathaway Energy Company, was recently registered as a new business in Hawaii, according to public records.

Savoie B.M.,Northwestern University | Savoie B.M.,NorthWestern Energy | Jackson N.E.,Northwestern University | Jackson N.E.,NorthWestern Energy | And 4 more authors.
Physical Chemistry Chemical Physics | Year: 2013

We present results showing that common approximations employed in the design and characterization of organic photovoltaic (OPV) materials can lead to significant errors in widely adopted design rules. First, we assess the validity of the common practice of using HOMO and LUMO energies in place of formal redox potentials to characterize organic semiconductors. We trace the formal justification for this practice and survey its limits in a way that should be useful for those entering the field. We find that while the HOMO and LUMO energies represent useful descriptive approximations, they are too quantitatively inaccurate for predictive material design. Second, we show that the excitonic nature of common organic semiconductors makes it paramount to distinguish between the optical and electronic bandgaps for materials design. Our analysis shows that the usefulness of the "LUMO-LUMO Offset" as a design parameter for exciton dissociation is directly tied to the accuracy of the one-electron approximation. In particular, our results suggest that the use of the "LUMO-LUMO Offset" as a measure of the driving force for exciton dissociation leads to a systematic overestimation that should be cautiously avoided. © 2013 the Owner Societies.

WattzOn, a leading provider of web and mobile engagement tools that help people save energy and money, has partnered with the City of Bozeman to assist residents in saving energy through the Bozeman Energy Smackdown. The Bozeman Energy Smackdown connects residents to resources and information needed to save energy and make their homes more comfortable. WattzOn supports the Energy Smackdown by providing a one-stop shop for automated utility bill tracking, personalized recommendations and links to relevant rebates. “We’re excited to engage our residents in the Bozeman Energy Smackdown,” said Heather Higinbotham, Energy Conservation Technician for the City of Bozeman. “Ultimately, the goal of the Bozeman Energy Smackdown is to connect residents to the resources and information that help them save money by using energy wisely. Partnering with WattzOn adds an online engagement platform and data tracking to our offline outreach efforts. They help our program be more effective.” "Bozeman is committed to helping its residents find ways to reduce energy usage and save money on their utilities, and WattzOn is excited about adding online engagement and data-tracking to their efforts” said Jon Enberg, VP of Partnerships for WattzOn. “We both have the mission of helping residents be smarter about using energy. It's a natural partnership." The Bozeman Energy Smackdown is a City of Bozeman initiative, with support from the Montana Department of Environmental Quality and NorthWestern Energy. Learn more HERE. WattzOn provides web and mobile tools that help people and communities save energy and money. Our platform combines software, powerful data analytics and local branding to engage residents by translating utility data into an interesting, personalized experience that delivers energy savings. WattzOn supports local programs -- with their variety of strategies and goals -- via a rich set of customization options. The platform connects to over 185 utilities nationwide to enable data-driven targeting and tracking of energy use, savings, and savings opportunities. Product features include an energy rebate database by zip code and program-level reporting that quantifies community impact. Learn more at

Midwest ENERGY Association (MEA) is proud to announce that six (6) energy operations members from NorthWestern Energy have received Life Sustaining Awards. Each year, MEA sponsors the Life Sustaining Awards program to recognize industry employees who have performed service "above and beyond" the call of duty by saving or attempting to save the life of another. Applicants for these awards are approved by the Executive Committee of MEA's Board of Directors. The 2015 Life Sustaining Awards went to Dusty Hendrickson, Mike McCabe, Casey Rocco, Cody Yurek, Pete Torgerson, and Melanie Pickens for helping an injured arborist in a remote area of the Little Belt Mountain in Montana. Read their Life Sustaining story here: About MEA: MEA serves the people that delivery electricity and natural gas to homes and businesses. MEA (Midwest ENERGY Association) was founded as a trade association over 100 years ago by distribution utilities, whose vision was to improve safety and efficiency. Today, energy delivery companies around the globe benefit from MEA's industry learning seminars, operations summits, and other events. Members collaborated to develop EnergyU, the world's premier online training and testing system for gas and electric distribution utilities.

SIOUX FALLS, S.D. and BUTTE, Mont., Dec. 6, 2016 /PRNewswire/ -- NorthWestern Corporation d/b/a NorthWestern Energy (NYSE: NWE) today announced that Tony Clark is joining the company's Board of Directors. Clark is a former Commissioner with the Federal Energy Regulatory Commission (FERC)...

News Article | February 23, 2017

When the Public Utility Regulatory Policies Act of 1978 was first enacted, it was a bit of an abstraction. A response to the energy crisis of the early 1970s, and championed by renewable energy advocate President Jimmy Carter, PURPA was designed to encourage energy conservation and support domestic renewable energy sources. PURPA compelled utilities to purchase energy produced by so-called Qualified Facilities (QFs) if they were developed at cost equal or below what a utility would have to pay for a traditional power plant -- in PURPA parlance, that is what’s known as the utility’s avoided cost. From the late 1970s through even the past few years, solar and wind energy were so expensive that no utility had to worry about them matching or besting their avoided cost. But circumstances have changed dramatically, thanks to precipitous declines in the cost of renewables. In many states, contracted solar prices have fallen below 5 cents per kilowatt-hour. The result: PURPA has become a significant driver in the development of utility-scale solar projects, particularly in states like Utah, Idaho and Montana, which have not traditionally been among the leaders in solar and wind deployment. Put simply, PURPA has become a big deal, particularly for utility solar. “We expect PURPA to be the No. 1 driver of utility solar in 2017, and we still expect it to drive significant new utility capacity additions in 2018,” said Colin Smith, a solar analyst with GTM Research. Now utilities in states such as North Carolina, Oregon, Utah and Montana are pushing back by proposing new contract lengths, rates and other changes that solar developers claim would make it impossible to finance projects. “Utilities have to take these contracts. They can’t say no. There’s no legal pushback to say this is beyond the load forecast or more than they can handle on their transmission network,” said Smith. “There is no feedback mechanism to curb PURPA, which led to explosive growth in projects and, oftentimes, pushback from utilities.” A contentious and ongoing PURPA squabble that erupted last spring in Montana has attracted considerable attention. Utilities and developers disagree over rates and terms that should apply to a number of solar projects in the state -- resulting in a declaratory order from the Federal Energy Regulatory Commission (FERC), which has oversight over PURPA. FERC issued its order last December, saying that the Montana Public Service Commission had ruled in a way that was inconsistent with PURPA. Nevertheless, FERC failed to go to court to enforce the law. It’s a sequence of events that raises questions for GTM’s Smith. “What is really interesting are the precedents being set by FERC in terms of how much they will intervene,” he said. “In a circumstance where FERC is saying the local utility commission has acted illegally but they’re not willing to intervene, there’s a big question around how they uphold PURPA and what happens moving forward.” Last May, Montana’s largest investor-owned utility, NorthWestern Energy, filed an application with the state’s public service commission to begin the process of revising QF avoided-cost rates. Almost everyone agreed that the rates, pegged at $66 per megawatt-hour, were out of date, having last been updated in 2013. As NorthWestern explained in a filing, the rates did not reflect the utility’s current avoided costs for a number of reasons. “This inaccuracy is largely due to changes in market prices and forecasts and in NorthWestern’s resource portfolio,” the utility wrote. “First, there has been a substantial decrease in natural gas and electricity market prices and forecasts since the Commission set the rates in the 2013 Tariff. Second, NorthWestern acquired wind and hydroelectric resources after 2013 resulting in a decrease of the cost of the Company’s avoidable resources.” Two weeks later, NorthWestern went back to the commission and filed an emergency motion, asking regulators for a complete suspension of QF rates for solar projects above 100 kilowatts. The utility expressed concern that because the avoided cost rate of $66 per megawatt-hour was so out of date, it would result in a flood of requests for new solar PPAs. NorthWestern’s case for an emergency motion was buttressed by the Montana Consumer Counsel, which argued that the state’s ratepayers were going to get buried by an avalanche of costly solar projects. According to a filing by FLS Energy/Cypress Creek earlier this month, the emergency motion came at a time when the developers were “on the verge” of entering into a total of 16 PPAs at the QF avoided cost rate of $66 per megawatt-hour. “NorthWestern represented to Movants (FLS and Cypress Creek) prior to the hearing on the motion that the utility would execute the PPAs that had been tendered,” the filing read. That meant QF projects totaling 108.5 megawatts would have received the rate of $66 per megawatt-hour. By a vote of 3-2, the commission granted NorthWestern’s emergency motion and altered the terms under which projects between 100 kilowatts and 3 megawatts were allowed to receive the existing QF rate. It included only those that had a signed PPA and executed interconnection agreements by June 16, 2016. None of FLS/Cypress Creek projects in the pipeline met the standard of the commission’s order. After efforts to get the Montana Public Service Commission to reconsider its ruling, FLS filed a petition with FERC last October. The company argued that both the commission and NorthWestern were not implementing PURPA in a way that was consistent with the law or FERC’s own regulations. The petition asked FERC to begin an enforcement action against both the utility and the commission. FERC’s December response declined FLS’ request to launch an enforcement action, instead saying that FLS could pursue it in court. But FERC also weighed in on a declaratory order about the Montana commission’s decision to only grandfather in projects under the $66 per megawatt-hour QF rate that had both a signed PPA and an executed interconnection agreement before June 16, 2016. Requiring both a signed PPA and an executed interconnection agreement was the commission’s legally enforceable obligation (LEO) standard, which basically ensures that a project is real and will deliver on its promises. But FERC said that standard was incompatible with PURPA because, essentially, they were terms that could be manipulated by the utility. “Such a requirement allows the utility to control whether and when a legally enforceable obligation exists -- for example, by delaying the facilities study or by delaying the tendering by the utility to the QF of an executable interconnection agreement,” wrote FERC. “Thus, the Montana Commission’s legally enforceable obligation standard is inconsistent with PURPA and our regulations under PURPA.” With FERC’s declaratory order as ammunition, FLS/Cypress Creek filed a motion this month seeking relief from the previous QF rate suspension with the Montana commission, as part of the ongoing process of developing a new QF rate. The developers revised their request for projects they believed were eligible for the $66 per megawatt-hour rate, from 108.5 megawatts down to 40.2 megawatts. Granting the request for relief would accord with NorthWestern’s original proposal for accepting grandfathered projects and fall well below the 54-megawatt cap commission staff had proposed, argued FLS/Cypress. The developer also called into question how much of an emergency Montana was actually facing with PURPA-driven solar projects. “Granting Movants’ request for relief would not result in a huge influx of new solar capacity onto NorthWestern’s system -- the purported 'emergency' that led to Order 7500,” the companies wrote. “To the extent that there ever was the threat of a 'flood' of solar projects in Montana, Order 7500 effectively prevented that from occurring. The only remaining questions pertain to those projects that were under development at the time of the Commission’s June 16, 2016 decision.” What happens now? According to a spokesperson for the Montana Public Service Commission, interveners in the QF avoided-cost docket must submit briefs by March 10, and a final decision about a new rate should come by mid-April. The last time NorthWestern applied to change the rate in 2014, the commission declined to do so. That's why the rate was so high. It’s unclear whether the commission will rule on FLS/Cypress Creek’s request for their grandfathered projects to move forward. If the commission doesn’t rule, the developers can pursue their case in federal court. It's also unclear what this means for PURPA solar projects. One legal expert interviewed for this story said it’s normal for FERC to decline pursuing PURPA enforcement actions, and that the declaratory order the commission issued was helpful to solar developers. But it’s also clear that PURPA is under attack on many fronts and will likely be tested further -- perhaps even from within FERC itself, as President Trump changes the makeup of the regulatory body through new appointments.

News Article | February 16, 2017

SIOUX FALLS, S.D., Feb. 16, 2017 /PRNewswire/ -- Company reports GAAP diluted earnings per share of $3.39 for 2016 Non-GAAP Adjusted diluted earnings per share of $3.30 within guidance range of $3.20-3.35 Announces 5% increase to the quarterly dividend to $0.525 per share...

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