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Silver Spring Networks co-founder and EVP of global development Eric Dresselhuys is leaving after almost 15 years with the firm. Silver Spring has moved from advanced metering infrastructure to adding distributed intelligence and “internet of things” capabilities to its networks. Silver Spring went public in 2013 after raising more than $300 million from Foundation Capital, KPCB, Northgate Capital Partners, Google, EMC and Hitachi. Dresselhuys has not yet revealed his next move. Electric-bus builder Proterra named Matt Horton as chief commercial officer. Prior to joining Proterra, Horton was the CEO of Propel Fuels. Proterra has sold more than 380 vehicles to 36 different municipal, university, and commercial transit agencies throughout North America. According to the company, by 2030, every single transit bus sold in the U.S. will run on electricity. (Here's the recent Energy Gang podcast interview with Proterra CEO Ryan Popple.) Hannah Masterjohn was promoted to VP of policy and regulatory affairs at Clean Energy Collective. In 2014, First Solar made its entry into the U.S. residential solar market by becoming the single largest investor in Clean Energy Collective's community solar business with the purchase of a 28 percent ownership interest for $21.8 million. CEC builds and sells community solar projects to residential and small business customers on behalf of utilities. In 2012, CEC won $13 million in equity financing from the New Energy Capital Cleantech Infrastructure Fund, Black Coral Capital and other investors. “Our model is not supplanting people who want to and can put solar on their house, but rather opening the market to the other 75 percent of electricity users,” explained CEC's president, Paul Spencer, in a previous interview. As we've reported, the model is simple on paper, but it's very complex in practice. Corporate structure, securities and tax issues, tracking, and utility-bill crediting all need to be up and running to allow this model to scale. GTM's Cory Honeyman beatboxes and professes his passion for community solar here. Vivint Solar promoted Thomas Plagemann to chief commercial officer and head of capital markets. Vivint also promoted Erica Dahl to VP of public policy and government affairs. Solar project developer Nautilus Solar Energy named Stefanie Padgett, previously with First Solar, as VP of asset management. Renew Financial, a property-assessed clean energy (PACE) funding provider, added Gaurav Kohli, most recently VP of merchant and acquirer processing at Visa, as executive VP of technology. Renew Financial recently surpassed $1 billion in funded projects through PACE loans which allow property owners to finance the cost of efficiency and renewable energy upgrades and repay those costs via their property-tax bill. President Donald Trump named Kristine Svinicki as chair of the Nuclear Regulatory Commission. The commission still has two more vacancies. Steven Schwartz, formerly with Parker Hannifin, is now the lead for distributed energy resources, microgrids and energy storage, a new engineering practice at consulting firm Advisian. Bill Baker, managing director at EverStream Capital Management, is now a board member at Synnove Energy, a U.S.-based startup with a focus on generating clean renewable energy in Africa. Adrian De Luca, a partner at Twenty First Century Utilities, is now on the board of directors at GridPoint, a smart buildings platform that provides visibility into facility operations. Enertech Search Partners, an executive search firm with a dedicated cleantech practice, is the sponsor of the GTM jobs column. Among its many active searches, Enertech is looking for a Demand Response Operations Manager. The client is one of the world’s leading integrated energy companies looking to expand the team for an internal startup. The parent company is expecting to invest about $1 billion into this early-stage business focused on distributed energy for large energy users. By combining traditional and renewable power, energy efficiency, demand response, generation, advisory services and big data and other digital assets, they help their customers capitalize on the new and more flexible energy landscape and move from consumers to prosumers and even grid service providers. This client is currently seeking a Demand Response Operations Manager who will reside on the Customer Success Team. They are looking for an individual who will lead the North American team responsible for demand response retail operations in utilities and all ISOs, including PJM, NYISO, ISO-NE, MISO and ERCOT. Andrew Gilligan was promoted to senior director for investments at solar development and finance firm Sol Systems. Cheryl Cox, previously with the Office of Ratepayer Advocates, is now senior analyst for RPS at the California Public Utilities Commission. Meghan Vincent-Jones, previously with Quick Mount PV, is now marketing and development director at solar advocacy organization CALSEIA. The number of jobs created to make, sell and install solar panels in the U.S. grew at a record pace last year, and grew much faster than the overall American job market, as per a new report from The Solar Foundation. The report found that there were 260,077 solar workers as of November 2016 -- an increase of 51,000 jobs, up 25 percent over 2015. The report estimates that the job growth rate will be closer to 10 percent this year. Alice Busching Reynolds, a Democrat, has been appointed senior adviser to Governor Edmund G. Brown Jr. for climate, the environment and energy. She has served as deputy secretary for law enforcement and counsel at the California Environmental Protection Agency since 2011. This position does not require Senate confirmation, and the compensation is $172,008. On January 30 Enphase reduced its workforce by approximately 18 percent "to lower operating expenses." That's roughly 80 jobs. This cut follows a layoff of 11 percent of its workforce in September 2016. Residential PV installer American Solar Direct had a round of layoffs, as well as some office consolidation, according to CEO Andrew Schneider. He noted that despite the layoffs, the situation was full speed ahead at the company, which had its first cash-flow positive months in November and December and partnered with Swell Energy on energy storage. Peter Thiel is not running for governor of California, a spokesperson told the Los Angeles Times. New York's top utility regulator, Audrey Zibelman, is moving on from her position. Australia's energy market operator announced that Zibelman will be taking over as chief executive. The organization, called AEMO, operates wholesale power markets, wholesale natural-gas markets, trading hubs and gas transmission systems throughout Australia. Zibelman leaves New York's Public Service Commission at a delicate time. The state is two and a half years into Reforming the Energy Vision, the utility reformation plan announced by Governor Andrew Cuomo in 2014. Last Thursday, FERC Chair Norman Bay announced his early resignation. He broke the news after President Trump chose Cheryl LaFleur to serve as the new chair next year. Carolyn Elefant tells NPR: "I think [Bay] was perhaps disappointed that Commissioner LaFleur was elevated above him. The resignation could mean costly delays for some major pipeline projects." Energy storage provider Sunverge named former Nexant CTO and GM Martin Milani as its first COO.


News Article | February 23, 2017
Site: www.businesswire.com

Dynegy Inc. (NYSE: DYN) reported a net loss for 2016 of $1.24 billion, compared to net income of $50 million for 2015. The year-over-year decrease was primarily driven by asset impairments related to the Baldwin, Newton and Stuart plants in 2016 and a second quarter 2015 deferred tax valuation allowance reversal which benefited 2015, but did not reoccur in 2016. This decrease was partially offset by the first quarter 2016 contribution from the Duke and EquiPower plants acquired in April 2015. The Company reported 2016 consolidated Adjusted EBITDA of $1,007 million, compared to $850 million for 2015. The $157 million increase was primarily due to full-year contributions from the Duke and EquiPower plants in 2016 versus nine months in 2015. Partially offsetting this benefit were lower energy margins, net of hedges, across the majority of the segments primarily due to mild temperatures in the first quarter 2016 and lower capacity revenues at the PJM and NY/NE segments as a result of lower capacity prices. The Company reported a fourth quarter 2016 net loss of $180 million, compared to a net loss of $134 million for 2015. The quarter-over-quarter change was primarily driven by Genco reorganization items, primarily due to the write-off of the remaining unamortized discount related to the Genco bonds. The Company reported fourth quarter 2016 consolidated Adjusted EBITDA of $219 million, compared to $222 million for the fourth quarter 2015 as improved energy margins, net of hedges, and lower O&M costs at the PJM and MISO segments were offset by lower energy and capacity revenues in the NY/NE and PJM segments. “The ENGIE acquisition solidified the transformation of our wholesale generation business we began in 2013. We have built the most efficient and lowest-cost platform in the industry while migrating our portfolio to a gas-dominated fleet in the ERCOT, NE-ISO and PJM markets. Our portfolio today has the longevity required for success,” said Dynegy President and Chief Executive Officer Robert C. Flexon. “Looking ahead to 2017, our efforts are aimed at optimizing our portfolio in conjunction with improving our balance sheet and capital structure and today’s announcement with LS Power is a step in that direction,” Flexon continued. “In keeping with our integration track record, we now expect to deliver $120 million in synergies related to the ENGIE acquisition, a step up from our initial $90 million estimate.” PJM - The 2016 operating income was $414 million, compared to $423 million for 2015. The change was due to lower capacity revenues, non-cash mark-to-market losses on derivatives, higher O&M costs and 2016 impairment charges. Partially offsetting this was the full-year contribution of the Duke and EquiPower plants acquired in April 2015. Adjusted EBITDA totaled $757 million during 2016 compared to $649 million in 2015, primarily due to the positive impact of the Duke and EquiPower plants which was partially offset by lower capacity prices and higher planned outage O&M costs. NY/NE - The 2016 operating loss was $29 million, compared to $56 million for 2015. The change was attributable to a full-year 2016 contribution from the EquiPower plants versus nine months of 2015, lower impairment charges, lower depreciation due to a 2015 impairment and non-cash mark-to-market gains on derivatives. Adjusted EBITDA totaled $171 million in 2016 compared to $175 million in 2015. MISO - The 2016 operating loss was $745 million, compared to a loss of $92 million in 2015, due to higher impairment charges. Adjusted EBITDA totaled $27 million for both 2016 and 2015. IPH - The 2016 operating loss was $87 million, compared to 2015 operating income of $49 million as higher capacity revenues and lower O&M costs were offset by higher 2016 impairment charges. Adjusted EBITDA totaled $102 million in 2016, compared to $77 million in 2015 due to higher capacity revenues and lower O&M costs from fewer planned outages. CAISO - The 2016 operating loss was $5 million, compared to $8 million for 2015 as a result of lower energy margin, net of hedges. Adjusted EBITDA totaled $59 million in 2016 compared to $44 million in 2015, primarily due to higher capacity revenues and a supplier settlement. PJM - The fourth quarter 2016 operating income was $137 million, compared to $101 million for the fourth quarter 2015. The increase was due to higher energy margin, net of hedges, and non-cash mark-to-market gains on derivatives, partially offset by lower capacity revenues. Adjusted EBITDA totaled $181 million in 2016 versus $171 million in 2015 as lower O&M and higher retail margins benefited results. NY/NE - The fourth quarter 2016 operating loss was $7 million, compared to $55 million for the fourth quarter 2015 due to lower impairment charges and non-cash mark-to-market gains on derivatives, partially offset by lower energy margin, net of hedges. Adjusted EBITDA totaled $29 million in 2016 compared to $56 million in 2015 primarily due to lower energy margins, net of hedges. MISO - The fourth quarter 2016 operating loss was $42 million, compared to $28 million for the fourth quarter 2015. The decrease was due to lower energy margin, net of hedges, and non-cash mark-to-market losses on derivatives. Adjusted EBITDA increased to $8 million in 2016 compared to ($1) million in 2015 primarily due to lower O&M expense from fewer planned outages. IPH - The fourth quarter 2016 operating income was zero, compared to $10 million for the fourth quarter 2015 primarily due to higher O&M costs. Adjusted EBITDA was $20 million in 2016 and $16 million in 2015. CAISO - The fourth quarter 2016 operating loss was $5 million, compared to $6 million for the fourth quarter 2015. Adjusted EBITDA in 2016 was $14 million versus $12 million in 2015 primarily due to higher capacity revenues in the most recent period. Dynegy’s total available liquidity is reflected in the table below. Cash provided by operations for the full year of 2016 was $676 million. During the full year 2016, our power generation facilities and retail operations provided cash of $1.02 billion. Corporate and other activities used cash of $557 million primarily for interest payments on various debt agreements of $538 million and acquisition-related costs of $19 million. In addition, changes in working capital and other provided cash of $216 million during the period. Cash used in investing activities totaled $2.15 billion for the full year of 2016. During the period, restricted cash increased by $2.0 billion from proceeds from the tranche C term loan being held in escrow for the ENGIE acquisition and $21 million related to the original issuance discount and interest income. Additionally, we paid $326 million in capital expenditures, received $176 million from asset sales, received $14 million in distributions from our unconsolidated investment in Elwood and received $10 million in proceeds from an insurance claim. Cash provided by financing activities totaled $2.74 billion for the full year of 2016 primarily due to $2 billion in proceeds related to the tranche C term loan, $750 million in proceeds from our 2025 bonds, $443 million in net proceeds from our tangible equity units and $198 million of proceeds related to our forward capacity agreement. This was partially offset by $18 million in financing costs related to our debt issuances, $550 million in voluntary repayments associated with our tranche B-2 term loan, $39 million in other scheduled debt payments, $22 million in dividend payments on our preferred stock and $17 million in interest rate swap settlement payments. Dynegy has reached an agreement to sell two peaking facilities in PJM to LS Power for $480 million in cash. The assets to be sold include the Armstrong and Troy facilities totaling 1,269 MW. Proceeds will be used for debt reduction. Dynegy reached an agreement with AEP to realign and consolidate the ownership of the Conesville and Zimmer Power Stations in Ohio. Dynegy agreed to sell its 40% ownership interest (312 MW) in Conesville Power Station and acquire AEP’s 25.4% ownership interest in Zimmer. No additional consideration will be paid to either party, however AEP will return a $58 million letter of credit previously posted by Dynegy to AEP. As a result, Dynegy will own 71.9% (971 MW) of the Company-operated Zimmer Power Station, a reliable and fully controlled coal plant and will no longer have an ownership interest in Conesville. The overall capacity for the Conesville and Zimmer generating stations is 780 MW and 1,350 MW, respectively. Our co-owner of Killen Station, AES, is involved in an Electric Security Plan proceeding in Ohio in which AES has reached a settlement that, if approved, includes a plan to retire the Killen Station. Dynegy has agreed with AES to retire that plant by mid-2018. The Stuart Power Station, jointly owned by Dynegy, AES, and AEP, is also under advanced review for potential retirement. If both retirements occur, 2,900 MW of baseload coal generation would leave PJM. Dynegy continues to look to optimize its ownership structure in jointly owned units, Miami Fort and Zimmer Power Stations. Genco emerged from its prepackaged Chapter 11 restructuring on February 2, 2017. As a result, Genco’s $825 million in unsecured bonds were eliminated. Participating bondholders exchanged $757 million in bonds thus far for $113 million in cash, $182 million in new Dynegy unsecured bonds due 2024 and 8.7 million seven-year warrants for Dynegy Inc. common stock with a strike price of $35. Bondholders who did not participate have 165 days post-emergence to file a claim and receive consideration, after which time their claim will be permanently extinguished. As a result of the restructuring, Dynegy’s annual consolidated interest expense has been reduced by approximately $45 million. At year end, IPH had $84 million in cash on hand and $79 million in cash collateral posted, providing Dynegy with more than sufficient funding to pay bondholders. Upon return of all previously posted cash collateral and payment of advisor fees, approximately $38 million of cash will be retained by Dynegy. On February 7, Dynegy completed its acquisition of ENGIE’s US portfolio. Dynegy repriced its term loan C resulting in approximately $100 million in interest savings over the next seven years. The Company also upsized the loan by $224 million to refinance the existing term loan B due in 2020, extending the maturity by four years to 2024. Simultaneous with closing, Dynegy upsized its liquidity facilities by $170 million to $1.65 billion and extended the maturity date on $450 million in existing revolver capacity from 2018 to 2021. Separately, Dynegy has increased ENGIE synergy targets from $90 million to $120 million with 75% of the synergies secured at closing and a full 90% to be achieved by year end 2017. PRIDE Energized (Producing Results through Innovation by Dynegy Employees) launched in early 2016 with goals of $250 million in EBITDA contributions and $400 million in balance sheet improvements by the end of 2018. Through the end of 2016, Dynegy achieved $150 million in contributions to EBITDA and $422 million in balance sheet improvements, reaching all balance sheet goals two years ahead of schedule. Dynegy’s earnings presentation and management comments on the earnings presentation will be available on the “Investor Relations” section of www.dynegy.com later today. Dynegy will answer questions about its 2016 financial results during an investor conference call and webcast tomorrow, February 24, 2017 at 9 am ET/8 am CT. Participants may access the webcast from the Company’s website. At Dynegy, we generate more than just power for our customers. We are committed to being a leader in the electricity sector. Throughout the Northeast, Mid-Atlantic, Midwest and Texas, Dynegy operates power generating facilities capable of producing enough energy to power about 25 million American homes. We’re proud of what we do, but it’s about much more than just output. We’re always striving to generate power safely and responsibly for our wholesale and retail electricity customers who depend on that energy to grow and thrive. This news release contains statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements,” particularly those statements concerning Dynegy’s beliefs and expectations regarding transformation of its wholesale generation business; its industry platform and portfolio optimization and longevity, including sale of peaking facilities, realignment and consolidation of Ohio power stations, and anticipated power station retirements; its balance sheet and capital structure improvements; synergies related to the ENGIE acquisition; execution of its PRIDE Energized target in balance sheet and operating improvements by year-end 2018; anticipated earnings and cash flows and Dynegy’s 2017 Adjusted EBITDA and Adjusted Free Cash Flow guidance. Historically, Dynegy’s performance has deviated, in some cases materially, from its cash flow and earnings guidance. Discussion of risks and uncertainties that could cause actual results to differ materially from current projections, forecasts, estimates and expectations of Dynegy is contained in Dynegy’s filings with the Securities and Exchange Commission (the SEC). Specifically, Dynegy makes reference to, and incorporates herein by reference, the section entitled “Risk Factors” in its 2016 Form 10-K (when filed). In addition to the risks and uncertainties set forth in Dynegy’s SEC filings, the forward-looking statements described in this press release could be affected by, among other things, (i) beliefs and assumptions about weather and general economic conditions;(ii) beliefs, assumptions, and projections regarding the demand for power, generation volumes, and commodity pricing, including natural gas prices and the timing of a recovery in power market prices, if any; (iii) beliefs and assumptions about market competition, generation capacity, and regional supply and demand characteristics of the wholesale and retail power markets, including the anticipation of plant retirements and higher market pricing over the longer term; (iv) sufficiency of, access to, and costs associated with coal, fuel oil, and natural gas inventories and transportation thereof; (v) the effects of, or changes to the power and capacity procurement processes in the markets in which we operate; (vi) expectations regarding, or impacts of, environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts, and other laws and regulations that we are, or could become, subject to, which could increase our costs, result in an impairment of our assets, cause us to limit or terminate the operation of certain of our facilities, or otherwise have a negative financial effect; (vii) beliefs about the outcome of legal, administrative, legislative, and regulatory matters, including any impacts from the change in administration to these matters; (viii) projected operating or financial results, including anticipated cash flows from operations, revenues, and profitability; (ix) our focus on safety and our ability to efficiently operate our assets so as to capture revenue generating opportunities and operating margins; (x) our ability to mitigate forced outage risk, including managing risk associated with CP in PJM and performance incentives in ISO-NE; (xi) our ability to optimize our assets through targeted investment in cost effective technology enhancements; (xii) the effectiveness of our strategies to capture opportunities presented by changes in commodity prices and to manage our exposure to energy price volatility; (xiii) efforts to secure retail sales and the ability to grow the retail business; (xiv) efforts to identify opportunities to reduce congestion and improve busbar power prices; (xv) ability to mitigate impacts associated with expiring reliability must run “RMR” and/or capacity contracts; (xvi) expectations regarding our compliance with the Credit Agreement, including collateral demands, interest expense, any applicable financial ratios, and other payments; (xvii) expectations regarding performance standards and capital and maintenance expenditures; (xviii) the timing and anticipated benefits to be achieved through our company-wide improvement programs, including our PRIDE initiative; (xix) expectations regarding strengthening the balance sheet, managing debt and improving Dynegy’s leverage profile; (xx) efforts to divest assets and the associated timing of such divestitures, and anticipated use of proceeds from such divestitures; (xxi) anticipated timing, outcome and impact of the expected retirements of Brayton Point; (xxii) beliefs about the costs and scope of the ongoing demolition and site remediation efforts at the Vermilion and Wood River facilities and any potential future remediation obligations at the South Bay facility; and (xxiii) expectations regarding the synergies and anticipated benefits of the Delta Transaction. The following table reflects the significant components of our weighted average shares outstanding used in basic and diluted loss per share calculations for the twelve months ended December 31, 2016 and 2015: The following table provides summary financial data regarding our PJM, NY/NE, MISO, IPH and CAISO segment results of operations for the three and twelve months ended December 31, 2016 and 2015, respectively. The following table provides summary financial data regarding our Adjusted EBITDA by segment for the twelve months ended December 31, 2016: The following table provides summary financial data regarding our Adjusted EBITDA by segment for the twelve months ended December 31, 2015: The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended December 31, 2016: The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended December 31, 2015: The 2017 guidance was prepared using reasonable efforts and based on currently available information assuming the following: (a) the Delta transaction closed on February 7, 2017, (b) all of the purchase price is allocated to property, plant and equipment, (c) property, plant and equipment is depreciated over an average useful life of 20 years, and (d) Genco restructuring completed on February 2, 2017. The following table provides summary financial data regarding our 2017 Adjusted EBITDA and Adjusted Free Cash Flow guidance, updated based on February 7, 2017 forward curves, as presented on February 23, 2017:


News Article | February 9, 2017
Site: www.theenergycollective.com

It’s that time again. Texas leaders are meeting in Austin for the 85th Legislative Session and the next five months will be an interesting wrestling match over human rights, voting rights, bathroom rights, and local rights. But what about our economic rights? A new report Environmental Defense Fund (EDF) issued to the Texas Legislature, Texas’ Clean Energy Economy: Prioritizing Jobs, Investments, and Growth, shows the Lone Star State’s evolving electricity landscape has created enormous economic growth and jobs. The report explores the policies put in place years ago that has allowed Texas’ power market to become cleaner and more affordable, and it outlines the state’s impressive job growth in energy efficiency, wind, and solar power. The report urges our leaders to develop and implement a bold, comprehensive Texas energy plan to create well-paid jobs, drive innovation and investment, make us more energy independent, and protect our water supplies, while improving the health of Texans and the environment. The electricity sector in Texas and across the U.S. is experiencing dramatic change. In the past few years, less electricity has come from coal because of cheaper natural gas and renewables. Unprecedented energy innovation and a robust, competitive market are rapidly transitioning Texas to a clean energy economy. In fact, national economic consulting firm The Brattle Group recently concluded 85 percent of Texas’ electricity in 2035 will come from natural gas and renewables. Moreover, coal’s share will fall to 6 percent if gas prices remain below $4 per MMBTU and if solar prices continue to decline as forecasted. Additionally, as the state’s wind industry continues to thrive, solar is poised for liftoff. The U.S. Department of Energy Wind Vision Scenario projects that Texas could produce enough wind energy by 2030 to power the equivalent of 15.4 million homes. And the state’s primary grid operator, the Electric Reliability Council of Texas (ERCOT), forecasts an approximately 70-fold increase in solar energy capacity from 2015 to 2030 under business as usual conditions. Fortunately, the Lone Star State more than any other is uniquely positioned to benefit from the global transition to cleaner energy: We produce more natural gas and wind power, and we have more potential for solar power, energy efficiency, and demand response (an innovative mechanism that rewards customers and businesses for saving energy). Harnessing the full potential of our clean resources will lead Texas to billions in savings in electricity, water, and healthcare. Here’s a closer look at the benefits we can expect: As we consider our economic rights this Session, we should remember that Texas has a global competitive advantage because it’s a big state with ample wind, solar, and natural gas resources, and we have the potential to save considerable money through energy efficiency. Moreover, 85 percent of Texas voters support increasing clean power. State leaders need to leverage Texas’ outstanding clean energy assets to achieve our full potential as the nation’s economic powerhouse – with an electricity system that’s cleaner and healthier, as well as less water-intensive and wasteful. EDF’s new report shows that by developing and implementing a bold, comprehensive Texas energy plan, legislators can grow the state’s economy, create jobs, attract investment, and save billions of dollars.


News Article | February 27, 2017
Site: www.businesswire.com

NEW YORK--(BUSINESS WIRE)--Ares Capital Corporation (NASDAQ:ARCC) is providing additional details on its new financing commitments closed during the fourth quarter, which totaled approximately $1.2 billion. “In the fourth quarter, we leveraged the breadth of our platform to originate $1.2 billion of commitments across 24 transactions in a variety of industries,” said Kipp deVeer, Chief Executive Officer of Ares Capital. “Having over 80% of our investment activity in the quarter in support of our existing borrowers is a testament to the significant advantages we provide to our borrowers.” Below is a description of eight transactions that closed during the fourth quarter. Ares Capital served as administrative agent for a $305.0 million second lien credit facility to support the management-led buyout of Acrisure. Ares Capital also made a co-investment in an ABRY Partners-led preferred stock investment in connection with the transaction. Based in Grand Rapids, Michigan, Acrisure is a leading retail insurance brokerage offering comprehensive risk management and consulting solutions, including property and casualty, employee benefits, human resource outsourcing, loss and claims management, surety bonding and personal lines coverage. Ares Capital served as administrative agent for a $250.0 million senior secured credit facility to support a dividend recapitalization of Riverview Power LLC, a 1,559-MW natural gas-fired and landfill gas power portfolio located throughout NYISO, PJM and ERCOT. Ares Capital served as administrative agent, lead arranger and bookrunner for a $176.2 million senior secured credit facility to support the acquisition of National Seating & Mobility (NSM) by Court Square Capital Partners. Founded in 1992, and headquartered in Franklin, Tennessee, NSM has grown into North America’s premier Complex Rehab Technology provider. NSM designs and assembles customized wheelchairs and adaptive seating systems that play an essential role in improving the lives of patients by enhancing their functionality, maximizing their independence and providing an ability to participate in the community. Ares Capital served as second lien administrative agent and collateral agent for a $75.0 million incremental second lien term loan to support a dividend recapitalization of Varsity Brands, a Charlesbank Capital Partners portfolio company. With a mission to inspire achievement and create memorable experiences for young people, Varsity Brands elevates the student experience, promotes participation, and celebrates achievement through three unique businesses: Herff Jones, BSN SPORTS, and Varsity Spirit. Together, these assets promote personal, school, and community pride through customizable products and programs to elementary and middle schools, high schools, and colleges and universities, as well as church organizations, professional and collegiate sports teams, and corporations. Ares Capital served as administrative agent and collateral agent for a $17.8 million upsize to Crown Laundry’s senior secured credit facility to support the buildout of a new plant in Bishopville, South Carolina. Crown Laundry is an independent full-service healthcare laundry processor and linen rental company serving healthcare providers in the southeastern United States. Ares Capital served as administrative agent for a holdco bridge loan in connection with the acquisition of the Broad River Energy Center by affiliates of Arroyo Energy Investors. Broad River is a 850-MW dual-fuel, simple-cycle generating facility located in Cherokee County, South Carolina that is fully committed to Duke Energy Progress under two long-term tolling agreements. Ares Capital served as administrative agent for an incremental second lien term loan to support the recapitalization of Young Innovations, a Linden Capital Partners portfolio company. Young Innovations develops, manufactures and markets supplies and equipment used by dentists, dental hygienists, dental assistants and consumers. Ares Capital served as the administrative agent, collateral agent, sole lead arranger and sole bookrunner for a senior secured credit facility to support a financing of Zywave, an Aurora Capital Group portfolio company. Zywave is the leading provider of technology-enabled content and analytical solutions on a software as a service (SaaS) basis that drive improved performance in sales, marketing and customer retention for P&C and benefits insurance brokerages. Zywave’s products deliver demonstrable value to its customers, leading to more initial prospect meetings, better close rates, and shortened selling cycles in the competitive independent brokerage market. Zywave's complementary product portfolio includes tools related to marketing communications, data analytics, employer resources and benefits agency management, among others. Ares Capital is a leading specialty finance company that provides one-stop debt and equity financing solutions to U.S. middle market companies, venture capital backed businesses and power generation projects. Ares Capital originates and invests in senior secured loans, mezzanine debt and, to a lesser extent, equity investments through its national direct origination platform. Ares Capital’s investment objective is to generate both current income and capital appreciation through debt and equity investments primarily in private companies. Ares Capital has elected to be regulated as a business development company (“BDC”) and as of December 31, 2016, was the largest BDC by total assets and market capitalization. Ares Capital is externally managed by a subsidiary of Ares Management, L.P. (NYSE:ARES), a publicly traded, leading global alternative asset manager. For more information about Ares Capital, visit www.arescapitalcorp.com. However, the contents of such website are not and should not be deemed to be incorporated by reference herein.


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

PRINCETON, N.J.--(BUSINESS WIRE)--NRG Energy, Inc. (NYSE:NRG) today reported full year 2016 net loss of $891 million, or $2.22 per diluted common share. The loss and resulting loss per share were driven by a $1.2 billion impairment of goodwill and fixed assets as forecasted gas and power prices continue to decline. Adjusted EBITDA for the full year 2016 was $3.3 billion, cash from operations was $2.1 billion and FCFbG was $1.2 billion. Additionally, NRG realized its second best safety year in company history with a full year top decile recordable rate of 0.624. “Our business delivered a year of strong results, both EBITDA and Free Cash Flow, driven by Retail, which had a record 2016 adjusted EBITDA and its third consecutive year of EBITDA growth,” said Mauricio Gutierrez, NRG President and Chief Executive Officer. “Our focus on strategic priorities and strong execution in 2016 sets the foundation for 2017, allowing us to seize market opportunities while continuing to streamline the business, strengthen the balance sheet and deliver value to shareholders.” As part of its streamlining strategy, NRG has realigned its reporting segments to more clearly report Generation and Retail activities. Accordingly, customer-facing businesses will now reside in the Retail segment. The Company's Retail segment will now include Business Solutions which includes Commercial & Industrial (C&I) previously in Generation, and the Generation segment now includes BETM. The results of the Company have been recast to reflect these changes. The net loss for the twelve months of 2016 was driven by a $1.2 billion impairment of goodwill and fixed assets as forecasted gas and power prices continue to decline. The net loss for the twelve months of 2015 includes non-cash charges of $3.3 billion5 and $3.0 billion for asset impairments net of taxes and income tax valuation allowance expense, respectively. Generation: Full year 2016 Adjusted EBITDA was $1.5 billion, $254 million lower than 2015 primarily driven by: Fourth quarter Adjusted EBITDA was $160 million, $140 million lower than the fourth quarter 2015 primarily driven by: Retail: Full year 2016 Adjusted EBITDA was $811 million, $18 million higher than 2015 driven by lower costs, increased retail margins and favorable settlement of a Texas sales tax audit, partially offset by unfavorable impacts from selling back excess supply due to milder weather conditions in 2016 as compared to 2015 and lower volumes driven by lower average customer usage. Fourth quarter Adjusted EBITDA was $134 million, $15 million lower than the fourth quarter 2015 due primarily to an increase in spend associated with customer growth initiatives. Renewables: Full year 2016 Adjusted EBITDA was $187 million, $29 million higher than 2015 due mainly to increased generation at Ivanpah and Mountain Wind and lower operating expenses while fourth quarter Adjusted EBITDA was $1 million higher than the prior year due primarily to increased generation at Ivanpah. NRG Yield: Full year 2016 Adjusted EBITDA was $899 million, $141 million higher than 2015 due primarily to increased wind production from Renewables, full year contributions from the acquisitions of Desert Sunlight and Spring Canyon which closed in 2015, and a receipt of insurance proceeds from a 2014 wind outage claim. Fourth quarter Adjusted EBITDA was $207 million, $18 million higher than the fourth quarter 2015 due primarily to increased production in the Renewables segment and a receipt of insurance proceeds from a 2014 wind outage claim. Corporate: Full year 2016 Adjusted EBITDA was $(145) million, $157 million better than 2015 due to reduced operating expenses at Residential Solar and other expense reductions, also driving the fourth quarter Adjusted EBITDA which was $48 million favorable to 2015. NRG-Level cash as of December 31, 2016, was $570 million, a decrease of $123 million from the end of 2015, and $1.2 billion was available under the Company’s credit facilities at the end of 2016. Total liquidity was $3.6 billion, including restricted cash and cash at non-guarantor subsidiaries (primarily GenOn and NRG Yield). In December 2016, NRG offered NRG Yield the opportunity to purchase the following assets: (i) the Minnesota Portfolio, a 40 MW portfolio of wind projects; (ii) the 30 MW Community wind projects; (iii) the 50 MW Jeffers wind projects; and (iv) a 16% interest in the 290 MW Agua Caliente solar facility, pursuant to the ROFO Agreement. In addition to these ROFO Assets, NRG also offered NRG Yield the opportunity to purchase NRG's 50% interests in seven utility-scale solar projects located in Utah, representing 265 net MW of capacity6. On February 24, 2017, NRG entered into a definitive agreement with NRG Yield to drop down the Agua Caliente and Utah utility-scale solar projects (311 net MW) for cash consideration of $130 million, plus assumed non-recourse project debt of approximately $464 million7, excluding working capital and other adjustments. Details of the projects, which are expected to close in the second quarter of 2017, include: NRG Yield elected not to pursue the acquisition of the Minnesota, Community and Jeffers wind projects at this time, but may continue its evaluation of the projects. NRG Yield has retained the right with NRG, pursuant to the ROFO Agreement, to participate in any third party process to the extent NRG elected to pursue a third party sale of these assets. In connection with the execution of the definitive agreement, NRG and NRG Yield entered into an amendment to the ROFO Agreement to expand the ROFO Assets pipeline with the addition of 234 net MW of utility-scale solar projects. These assets include: NRG achieved a significant milestone in its fleet optimization strategy, completing coal-to-gas projects at three generation facilities across its fleet. The modified units can generate approximately 2.2 GW. The three plants include the Joliet Generating Station (three units converted by fourth quarter 2016 for a total of 1,326 MW), the Shawville Generating Station (all four units are currently in final commissioning following modification for a total of 597 MW) and the New Castle Generating Station, (all three units have been modified by second quarter 2016 for a total of 325 MW). Over 2016, NRG continued to grow renewables development opportunities with acquisitions of 1.7GW of wind and solar assets. As of December 2016, NRG held 543 MW of backlog in execution across the utility wind and solar, community solar and DG solar businesses. Over the fourth quarter 2016, NRG accelerated utility project origination across CAISO, ERCOT and ISO-NE, growing the project pipeline to approximately 3.3 GW, a 25% increase over the previous quarter. NRG successfully transitioned 2.7 GW of the combined NRG and NYLD fleet (approximately 26 wind and 7 solar projects) to self-perform operations in 2016, including Alta and CVSR. On December 29, 2016, NRG completed, on time and on budget, construction and final acceptance of performance testing at the Petra Nova project, the world's largest post-combustion carbon capture system. During performance testing, the facility captured more than 90% of CO2 from a 240 MW equivalent slipstream of flue gas off an existing coal-fueled electrical generating unit at the WA Parish power plant in Fort Bend County, southwest of Houston. At this level of operation, Petra Nova can capture more than 5,000 tons of CO2 per day, which is the equivalent of taking more than 350,000 cars off the road. In 2016, NRG completed the installation of environmental control upgrades at its 638 MW Avon Lake Unit 9 facility (COD June 2016) and its 1,538 MW Powerton coal facility (COD December 2016). NRG is reaffirming its guidance range for 2017 with respect to Adjusted EBITDA, cash from operations and FCFbG as set forth below. On January 24, 2017, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 2.25%. In 2016, NRG reduced corporate debt by $792 million10. Combined with the debt repurchases in 2015 and the extension of debt maturities at a lower average coupon rate, NRG has realized annual interest savings of approximately $87 million, plus an additional $10 million in dividend savings from the repurchase of 100% of its outstanding $345 million, 2.822% convertible perpetual preferred stock. NRG is also announcing $200 million of additional capital reserved for debt reduction bringing total 2017 allocation to discretionary debt reduction to $600 million. On January 18, 2017, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable February 15, 2017, to stockholders of record as of February 1, 2017, representing $0.12 on an annualized basis. The Company’s common stock dividend, corporate level debt reduction and share repurchases are subject to available capital, market conditions and compliance with associated laws and regulations. On February 28, 2017, NRG will host a conference call at 8:00 a.m. Eastern to discuss these results. Investors, the news media and others may access the live webcast of the conference call and accompanying presentation materials by logging on to NRG’s website at http://www.nrg.com and clicking on “Investors.” The webcast will be archived on the site for those unable to listen in real time. NRG is the leading integrated power company in the U.S., built on the strength of the nation’s largest and most diverse competitive electric generation portfolio and leading retail electricity platform. A Fortune 200 company, NRG creates value through best in class operations, reliable and efficient electric generation, and a retail platform serving residential and commercial customers. Working with electricity customers, large and small, we continually innovate, embrace and implement sustainable solutions for producing and managing energy. We aim to be pioneers in developing smarter energy choices and delivering exceptional service as our retail electricity providers serve almost 3 million residential and commercial customers throughout the country. More information is available at www.nrg.com. Connect with NRG Energy on Facebook and follow us on Twitter @nrgenergy. In addition to historical information, the information presented in this communication includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act. These statements involve estimates, expectations, projections, goals, assumptions, known and unknown risks and uncertainties and can typically be identified by terminology such as “may,” “should,” “could,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “expect,” “intend,” “seek,” “plan,” “think,” “anticipate,” “estimate,” “predict,” “target,” “potential” or “continue,” or the negative of these terms or other comparable terminology. Such forward-looking statements include, but are not limited to, statements about the Company’s future revenues, income, indebtedness, capital structure, plans, expectations, objectives, projected financial performance and/or business results and other future events, and views of economic and market conditions. Although NRG believes that its expectations are reasonable, it can give no assurance that these expectations will prove to be correct, and actual results may vary materially. Factors that could cause actual results to differ materially from those contemplated herein include, among others, general economic conditions, hazards customary in the power industry, weather conditions, including wind and solar performance, competition in wholesale power markets, the volatility of energy and fuel prices, failure of customers to perform under contracts, changes in the wholesale power markets, changes in government regulations, the condition of capital markets generally, our ability to access capital markets, unanticipated outages at our generation facilities, adverse results in current and future litigation, failure to identify, execute or successfully implement acquisitions, repowerings or asset sales, our ability to implement value enhancing improvements to plant operations and companywide processes, our ability to proceed with projects under development or the inability to complete the construction of such projects on schedule or within budget, risks related to project siting, financing, construction, permitting, government approvals and the negotiation of project development agreements, our ability to progress development pipeline projects, GenOn’s ability to continue as a going concern, our ability to obtain federal loan guarantees, the inability to maintain or create successful partnering relationships, our ability to operate our businesses efficiently including NRG Yield, our ability to retain retail customers, our ability to realize value through our commercial operations strategy and the creation of NRG Yield, the ability to successfully integrate businesses of acquired companies, our ability to realize anticipated benefits of transactions (including expected cost savings and other synergies) or the risk that anticipated benefits may take longer to realize than expected, our ability to close the Drop Down transactions with NRG Yield, and our ability to execute our Capital Allocation Plan. Debt and share repurchases may be made from time to time subject to market conditions and other factors, including as permitted by United States securities laws. Furthermore, any common stock dividend is subject to available capital and market conditions. NRG undertakes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law. The adjusted EBITDA and free cash flow guidance are estimates as of February 28, 2017. These estimates are based on assumptions the company believed to be reasonable as of that date. NRG disclaims any current intention to update such guidance, except as required by law. The foregoing review of factors that could cause NRG’s actual results to differ materially from those contemplated in the forward-looking statements included in this Earnings press release should be considered in connection with information regarding risks and uncertainties that may affect NRG’s future results included in NRG’s filings with the Securities and Exchange Commission at www.sec.gov. 1 $100 million savings driven by reduction of debt since 3rd quarter of 2015, preferred stock redemption and extension of maturities at lower interest rates 2 Subject to working capital and other adjustments 5 Total impairments of $5.1 billion net of taxes of $1.8 billion 6 Reflects NRG's net interest based on cash to be distributed in tax equity partnership with Dominion 7 Approximately $328 million on balance sheet and $136 million pro-rata share of unconsolidated debt 9 61 of the 80 MWs have been contracted as of February 28, 2017 10 Cash cost of $874 million, including $120 million of debt extinguishment fees; Additional 2015 corporate debt reduction of $246 MM (cash cost of $226 MM) completed in 2015 bringing total debt reduction under program to $1 billion Appendix Table A-1: Fourth Quarter 2016 Adjusted EBITDA Reconciliation by Operating Segment The following table summarizes the calculation of Adj. EBITDA and provides a reconciliation to net (loss)/income: The following table reconciles the condensed financial information to Adjusted EBITDA: Appendix Table A-2: Fourth Quarter 2015 Adjusted EBITDA Reconciliation by Operating Segment The following table summarizes the calculation of Adjusted EBITDA and provides a reconciliation to net (loss)/income: The following table reconciles the condensed financial information to Adjusted EBITDA: Appendix Table A-3: Full Year 2016 Adjusted EBITDA Reconciliation by Operating Segment The following table summarizes the calculation of Adj. EBITDA and provides a reconciliation to net (loss)/income: The following table reconciles the condensed financial information to Adjusted EBITDA: Appendix Table A-4: Full Year 2015 Adjusted EBITDA Reconciliation by Operating Segment The following table summarizes the calculation of Adjusted EBITDA and provides a reconciliation to net (loss)/income: The following table reconciles the condensed financial information to Adjusted EBITDA: Appendix Table A-5: 2016 and 2015 Three Months Ended December 31 and Full Year Adjusted Cash Flow from Operations Reconciliations The following table summarizes the calculation of adjusted cash flow operating activities providing a reconciliation to net cash provided by operating activities: Appendix Table A-6: Fourth Quarter 2016 Regional Adjusted EBITDA Reconciliation for Generation The following table summarizes the calculation of Adjusted EBITDA and provides a reconciliation to net loss: The following table reconciles the condensed financial information to Adjusted EBITDA: Appendix Table A-7: Fourth Quarter 2015 Regional Adjusted EBITDA Reconciliation for Generation The following table summarizes the calculation of Adjusted EBITDA and provides a reconciliation to net loss: The following table reconciles the condensed financial information to Adjusted EBITDA: Appendix Table A-8: Full Year 2016 Regional Adjusted EBITDA Reconciliation for Generation The following table summarizes the calculation of Adjusted EBITDA and provides a reconciliation to net income/(loss) The following table reconciles the condensed financial information to Adjusted EBITDA: Appendix Table A-9: Full Year 2015 Regional Adjusted EBITDA Reconciliation for Generation The following table summarizes the calculation of Adjusted EBITDA and provides a reconciliation to net income/(loss) The following table reconciles the condensed financial information to Adjusted EBITDA: Appendix Table A-10: Full Year 2016 Sources and Uses of Liquidity The following table summarizes the sources and uses of liquidity for the full year 2016: Appendix Table A-11: 2017 Adjusted EBITDA Guidance Reconciliation The following table summarizes the calculation of Adjusted EBITDA providing reconciliation to net income: Appendix Table A-12: 2017 FCFbG Guidance Reconciliation The following table summarizes the calculation of Free Cash Flow before Growth providing reconciliation to Cash from Operations: EBITDA and Adjusted EBITDA are non-GAAP financial measures. These measurements are not recognized in accordance with GAAP and should not be viewed as an alternative to GAAP measures of performance. The presentation of Adjusted EBITDA should not be construed as an inference that NRG’s future results will be unaffected by unusual or non-recurring items. EBITDA represents net income before interest (including loss on debt extinguishment), taxes, depreciation and amortization. EBITDA is presented because NRG considers it an important supplemental measure of its performance and believes debt-holders frequently use EBITDA to analyze operating performance and debt service capacity. EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our operating results as reported under GAAP. Some of these limitations are: Because of these limitations, EBITDA should not be considered as a measure of discretionary cash available to use to invest in the growth of NRG’s business. NRG compensates for these limitations by relying primarily on our GAAP results and using EBITDA and Adjusted EBITDA only supplementally. See the statements of cash flow included in the financial statements that are a part of this news release. Adjusted EBITDA is presented as a further supplemental measure of operating performance. As NRG defines it, Adjusted EBITDA represents EBITDA excluding impairment losses, gains or losses on sales, dispositions or retirements of assets, any mark-to-market gains or losses from accounting for derivatives, adjustments to exclude the Adjusted EBITDA related to the non-controlling interest, gains or losses on the repurchase, modification or extinguishment of debt, the impact of restructuring and any extraordinary, unusual or non-recurring items plus adjustments to reflect the Adjusted EBITDA from our unconsolidated investments. The reader is encouraged to evaluate each adjustment and the reasons NRG considers it appropriate for supplemental analysis. As an analytical tool, Adjusted EBITDA is subject to all of the limitations applicable to EBITDA. In addition, in evaluating Adjusted EBITDA, the reader should be aware that in the future NRG may incur expenses similar to the adjustments in this news release. Management believes Adjusted EBITDA is useful to investors and other users of NRG's financial statements in evaluating its operating performance because it provides an additional tool to compare business performance across companies and across periods and adjusts for items that we do not consider indicative of NRG’s future operating performance. This measure is widely used by debt-holders to analyze operating performance and debt service capacity and by equity investors to measure our operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. Management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations, and for evaluating actual results against such expectations, and in communications with NRG's Board of Directors, shareholders, creditors, analysts and investors concerning its financial performance. Adjusted cash flow from operating activities is a non-GAAP measure NRG provides to show cash from operations with the reclassification of net payments of derivative contracts acquired in business combinations from financing to operating cash flow, as well as the add back of merger, integration and related restructuring costs. The Company provides the reader with this alternative view of operating cash flow because the cash settlement of these derivative contracts materially impact operating revenues and cost of sales, while GAAP requires NRG to treat them as if there was a financing activity associated with the contracts as of the acquisition dates. The Company adds back merger, integration related restructuring costs as they are one time and unique in nature and do not reflect ongoing cash from operations and they are fully disclosed to investors. Free cash flow (before Growth) is adjusted cash flow from operations less maintenance and environmental capital expenditures, net of funding, preferred stock dividends and distributions to non-controlling interests and is used by NRG predominantly as a forecasting tool to estimate cash available for debt reduction and other capital allocation alternatives. The reader is encouraged to evaluate each of these adjustments and the reasons NRG considers them appropriate for supplemental analysis. Because we have mandatory debt service requirements (and other non-discretionary expenditures) investors should not rely on free cash flow before Growth as a measure of cash available for discretionary expenditures. Free Cash Flow before Growth is utilized by Management in making decisions regarding the allocation of capital. Free Cash Flow before Growth is presented because the Company believes it is a useful tool for assessing the financial performance in the current period. In addition, NRG’s peers evaluate cash available for allocation in a similar manner and accordingly, it is a meaningful indicator for investors to benchmark NRG's performance against its peers. Free Cash Flow before Growth is a performance measure and is not intended to represent net income (loss), cash from operations (the most directly comparable U.S. GAAP measure), or liquidity and is not necessarily comparable to similarly titled measures reported by other companies.


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

The Southwest Power Pool said last week that it met 52.1 percent of the electricity demand in the sprawling transmission organization’s service territory with windpower during a portion of the overnight period on Feb. 13, marking the first time SPP had topped the 50 percent mark. What’s even bigger news is that hardly anyone noticed—these records have been falling consistently for the past several years with the steady increase in wind farm construction across the Midwest; SPP set its prior record of 49.2 percent just last year. The real news, however, wasn’t the percentage itself, but what Bruce Rew, SPP’s vice president of operations, said later in the same press release concerning the changes that have occurred in the past 10 years. Then, the SPP release noted, a goal of 25 percent would have been deemed unrealistic. “Since then,” Rew said, “we’ve gained experience and implemented new policies and procedures. Now we have the ability to reliably manage greater than 50 percent wind penetration. It’s not even our ceiling. We continue to study even higher levels of renewable, variable generation as part of our plans to maintain a reliable and economic grid of the future.” In journalism, that’s called burying the lede, but it is indicative of the changes that have swept across the utility industry in the past decade. As I noted in a January post (which you can read here), the concerns in the utility industry about windpower’s impact on the grid’s reliability were palpable. From the outside, the degree of unease often seemed over the top, but for those charged with operating the system, the concerns were indeed real. Experience has changed those attitudes. SPP’s latest wind integration analysis, completed in 2015 and released early last year (you can find it here) looks at what system changes or hardware additions would be required to run the system reliably at wind penetration levels of 30 percent, 45 percent and 60 percent. (As of year-end 2016 there was slightly more than 16,000 megawatts of installed wind generating capacity in SPP’s territory; in 2015, the latest full year of data, wind accounted for just under 14 percent of the system’s electric output.) The report’s findings are technical in nature and cover a range of needed upgrades and operational changes, but the upshot is straightforward: If the changes are made, they “would enable the SPP transmission system to reliably handle up to the 60 percent wind penetration levels studied.” That type of matter-of-fact finding 10 years ago would have been almost unthinkable, but today it is common across the utility industry. In Texas, the transmission system operators at ERCOT have successfully integrated a surge of new windpower capacity in the last five years: Wind accounted for 15.1 percent of the state’s generation in 2016, up from 8.5 percent in 2011. And the growth is slated to continue. According to data from the American Wind Energy Association (which can be found here), there is an additional 5,401 MW of windpower capacity under construction in the state, which is already far and away the largest wind generator in the U.S., with 20,321 MW of installed capacity. As with the SPP approach, what’s important to note is the matter-of-fact way this capacity is being integrated. In its 2016 annual report (which is available here), ERCOT notes: “In 2016, wind and solar projects accounted for the majority of new generation built in the ERCOT region. As renewable energy and other new technologies continue to grow in Texas, ERCOT is adapting to ensure the reliability and efficiency of the electric system.” There are issues, as ERCOT points out, citing in particular the need to cope with sudden shifts in generation output and reduced inertia on the system, but they are just that, issues, not insurmountable problems. These changing attitudes toward wind are reflected in the political arena as well. ERCOT and SPP span all or parts of 14 states (covering the Plains and beyond), 12 of which voted solidly for Donald Trump in the 2016 presidential election. But it would be a mistake to assume that the new president’s antipathy for renewable energy is widely shared in these red states. The chart below illustrates this dichotomy: Start with Texas in the south and move due north to North Dakota, all six of those states voted for Trump, and yet they have been prime beneficiaries of the windpower industry’s development in the past 10 years. Sen. Charles Grassley (R-IA) is perhaps the best-known GOP windpower backer, proudly noting that he wrote the original production tax credit legislation that helped the industry get off the ground in 1992. He was also quoted last year warning candidate Trump that any changes to the PTC would only make it through Congress “over my dead body.” Less well known, the industry also enjoys the backing of Kansas’ conservative governor, Sam Brownback. The staunch anti-tax Brownback has pushed through a series of supply side economic policies in Kansas that has thrown the state economy into a tailspin. At the same time, he is vice chair of the Governors’ Wind and Solar Energy Coalition, and is lobbying on behalf of continued federal support for the investment and production tax credits that have done so much to spur development of both the wind and solar industries. In a recent letter to President Trump, Brownback and Gina Raimondo, the Democratic governor from Rhode Island who currently chairs the coalition, wrote: “The nation’s wind and solar energy resources are transforming low-income rural areas in ways not seen since the passage of the Homestead Act over 150 years ago. For example, U.S. wind facilities pay rural landowners $222 million a year, with more than $156 million going to landowners in areas with below-average incomes. In addition, $100 billion has been invested by companies in low-income counties, where some 70 percent of the nation’s wind farms are located.” More broadly, the two continued: “Members of the coalition have seen the benefits of renewable energy firsthand, and agree that expanding renewable energy production is one of the best ways to meet the country’s growing demand for energy. Today’s wind and solar resources offer consumers nearly unlimited electric energy with no fuel costs, no national security impacts, and a number of environmental benefits. The boons of renewable energy can be virtually endless with your administration’s and Congress’ support of the key initiatives detailed here. Your support of these initiatives will allow our nation to capitalize on renewable resources, meet the needs of Americans and bolster the economy.” (The complete letter can be found here.) Broad support can also be found for windpower in Texas—just don’t call it an environmental thing. For starters, while there is debate about former Gov. Rick Perry’s overall role in pushing wind’s development in the state, he did sign the 2005 legislation establishing the renewable energy transmission zones that has made the Texas “wind rush” a possibility. And Perry is certainly not the technology’s only backer across the state as this story from The Guardian makes abundantly clear. Call it what you want—experience, economics, environmental protection—it all means the same thing: windpower is here to stay, regardless of who sits in the Oval Office.


News Article | February 14, 2017
Site: www.rechargenews.com

The Southwest Power Pool (SPP) has become the first of North America’s 10 grid operators to source more than half of its power from wind at a given moment, setting a continental wind-penetration record of 52.1% on the morning of 12 February. The Little Rock, Arkansas-based SPP oversees the bulk electric grid and wholesale power market across a 14-state, 550,000-square mile (885,000 sq km) area in the central US, a region that has seen huge growth in its operating wind capacity over the past few years. At the beginning of the century SPP had only a few hundred megawatts of wind on-line in its service area, and wind’s contribution to the electricity mix was so miniscule that it was classified as “Other” in SPP’s fuel-data statistics. Today the region covered by SPP – stretching from the Canadian border in North Dakota down to parts of Texas – has more than 16GW of spinning wind turbines, and wind contributed 15% of the total power on its system last year, behind natural gas and coal. “Ten years ago we thought hitting even a 25% wind-penetration level would be extremely challenging, and any more than that would pose serious threats to reliability,” says Bruce Rew, SPP’s vice president of operations. “Now we have the ability to manage greater than 50% wind penetration, and it’s not even our ceiling,” Rew says. “We continue to study even higher levels of renewable, variable generation as part of our plans to maintain a reliable and economic grid of the future.” SPP’s ability to absorb and balance large amounts of variable wind power stems in part from the vastness of its geographic footprint. SPP covers the entirety of wind-heavy states like Kansas and Oklahoma, as well as portions of other states like Texas and New Mexico. Much of Texas’ wind capacity is overseen by the Electric Reliability Council of Texas (ERCOT), a different grid operator. “We’re able to manage wind generation more effectively than other, smaller systems can because we’ve got a huge pool of resources to draw from,” Rew explains. “Even if the wind stops blowing in the upper Great Plains, we can deploy resources waiting in the Midwest and Southwest to make up any sudden deficits.” SPP says it has approved the construction of more than $10bn in high-voltage transmission infrastructure over the past decade, much of it in the Midwest to connect rural, isolated wind farms to distant population centres.


News Article | February 19, 2017
Site: www.PR.com

Update Report on Congestion in the Texas Panhandle LCG Consulting has updated the report on congestion in the Texas Panhandle. Austin, TX, February 19, 2017 --( In light of this growth, LCG is conducting ongoing modeling of the Panhandle region of Texas and is offering an 2017 updateto last year’s extensive ERCOT Panhandle Renewable Energy Zone Outlook. This update (http://www.energyonline.com/Reports/Files/Panhandle_Intro.pdf) looks at three years, 2017, 2018 and 2021, and considers upgrades suggested by Sharyland Utilities. For more in depth analysis, LCG can provide tailored datasets, such as individualized generator performance, hourly LMPs, Congestion Revenue Rights (CRRs), and much more. Their data is crunched using 5-minute dispatch and the industry’s most sophisticated and long-standing electricity model, the UPLAN Network Power Model. They continuously sustain the most up-to-date information on every detail of the Texas grid, from transmission upgrades to gas prices, weather patterns, and more. About LCG Consulting: Silicon Valley-based LCG Consulting has been modeling electricity for more than 30 years. In that time, energy market participants and research institutions across the United States and internationally have relied on our models for every type of application, from electricity trading, plant siting, asset valuation, and testimony support. If you are interested in more information on LCG’s products and services, please contact us at julie.chien@energyonline.com or 650-962-9670x110. Austin, TX, February 19, 2017 --( PR.com )-- The Texas Panhandle is seeing rapid wind development, as well as extensive transmission development and a possible connection to Lubbock Power & Light (LP&L).In light of this growth, LCG is conducting ongoing modeling of the Panhandle region of Texas and is offering an 2017 updateto last year’s extensive ERCOT Panhandle Renewable Energy Zone Outlook.This update (http://www.energyonline.com/Reports/Files/Panhandle_Intro.pdf) looks at three years, 2017, 2018 and 2021, and considers upgrades suggested by Sharyland Utilities.For more in depth analysis, LCG can provide tailored datasets, such as individualized generator performance, hourly LMPs, Congestion Revenue Rights (CRRs), and much more.Their data is crunched using 5-minute dispatch and the industry’s most sophisticated and long-standing electricity model, the UPLAN Network Power Model. They continuously sustain the most up-to-date information on every detail of the Texas grid, from transmission upgrades to gas prices, weather patterns, and more.About LCG Consulting:Silicon Valley-based LCG Consulting has been modeling electricity for more than 30 years. In that time, energy market participants and research institutions across the United States and internationally have relied on our models for every type of application, from electricity trading, plant siting, asset valuation, and testimony support.If you are interested in more information on LCG’s products and services, please contact us at julie.chien@energyonline.com or 650-962-9670x110. Click here to view the list of recent Press Releases from LCG Consulting


News Article | February 28, 2017
Site: co.newswire.com

Pyxis Energy announced the launch of their Energy Brokerage today. Pyxis Energy (Pyxis) is excited about their entrance into the Energy procurement business.  Pyxis will serve Commercial and Industrial customers as well as aggregated Residential customers in the Mid-Atlantic and Texas regions. “The addition of Energy procurement services directly compliments our Load Response, Energy Consulting and Distributed Generation businesses” stated Del Hilber, Pyxis Energy’s Co-Founder and Principal. Pyxis currently provides commercial and industrial customers with Load Response products in the PJM and ERCOT markets. The Company’s SMB and Residential Distributed Generation products offer solutions for clean and reliable power to customers with no up-front cost. Pyxis will launch the broker business in phases throughout 2017; Maryland markets will be the first served. Entrance into markets will be on a state-by-state basis and subject to state and/or city Public Service Commission approval. To date, Pyxis has been granted a license by the Maryland Public Service Commission to provide broker services in all electric distribution zones.  Christopher Patino, principal at Pyxis Energy responsible for referral partnerships, touted that “Pyxis Energy now offers a variety of products and services to help our clients customize their Energy strategy to work for their business.” Mr. Hilber went on to add that he believes, “all Energy consumers large and small deserve the highest level of guidance and quality products in an ever-changing market. We strive to provide our customers with hands-on service that other providers simply cannot.  Additionally, we have a robust referral program that introduces a steady flow of customers into our Brokerage, Load Response, and Distributed Generation businesses.” About Pyxis Energy​ ​     Pyxis Energy (pyxisenergy.com) is led by Del Hilber and Christopher Patino. Together they offer over thirty-five years of experience in the Energy industry. Areas of business include Energy Procurement, Energy Business Consulting, Load Response and Distributed Generation.  Pyxis was founded in 2014 as an independent Energy company working with Energy market leaders and end customers for the benefit of both. Headquartered in Baltimore, Maryland Pyxis also has offices in Philadelphia, Pennsylvania.


News Article | February 15, 2017
Site: www.aweablog.org

A region stretching from Montana to Texas set a new record this week, hitting a mark many considered impossible just a few years ago: wind supplied the Southwest Power Pool (SPP) with 52 percent of its electricity on Sunday. The SPP is a grid operator for parts of 14 states and manages over 60,000 miles of transmission lines. Sunday’s high-water mark bests the previous record of 49.2 percent, achieved last spring “Ten years ago we thought hitting even a 25 percent wind-penetration level would be extremely challenging, and any more than that would pose serious threats to reliability,” said Bruce Rew, Southwest Power Pool’s vice president of operations. “Now we have the ability to reliably manage greater than 50 percent. It’s not even our ceiling. Wind has been a growing part of SPP’s generation mix, supplying 15 percent of its electricity last year. The SPP’s installed wind generation also increased by over 30 percent in 2016. In states like Kansas and Oklahoma, part of SPP’s region, wind growth has been particularly pronounced. Kansas now generates 30 percent of its electricity using wind, while Oklahoma tops 20 percent “With a footprint as broad as ours, even if the wind stops blowing in the upper Great Plains, we can deploy resources waiting in the Midwest and Southwest to make up any sudden deficits,” said Rew This latest achievement in SPP is only the most recent in a series of wind power setting records in various electricity markets. Just last December, four other grid operators saw wind set new output records. In ERCOT, the grid operator for much of Texas, wind surpassed 16,000 megawatts (MW) on Christmas day. MISO wind output reached 13,599 MW on December 7, while PJM and NE-ISO set new wind output records of 6,249 MW and 871 MW, respectively, in the final days of the year. Following the second strongest quarter for U.S. wind installations in the last three months of 2016, wind is set to continuing breaking records this year. Transmission plays an important role in hitting milestones like these. Studies routinely show that updates to America’s electricity grid and new transmission projects more than pay for themselves. For example, the SPP found transmission upgrades would save $800 for each of its customers in the coming years. Records like these resonate, because they demonstrate wind energy can play a key role in an affordable, reliable, diversified energy mix. That creates a stronger system, and helps keep more money in the pockets of families and businesses.

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