News Article | February 22, 2017
Researchers in London have just released their findings on a new prognostic tool designed to help them select mesothelioma patients for Phase I clinical trials. Surviving Mesothelioma has just posted an article on the new tool. Click here to read it now. Scientists at the Royal Marsden Hospital analyzed the cases of 65 mesothelioma patients who participated in Phase I clinical trials between 2003 and 2015. According to their report in the European Journal of Cancer, mesothelioma patients who scored a one on a three point criteria scale had a median survival of 13.4 months, compared to just 4 months for patients who scored a two or three. “The m-RPS is a useful tool to assess MM patient suitability for phase I trials and should now be prospectively validated,” writes oncologist Dionysis Papadatos-Pastos, MD. “There are a number of prognostic tools designed to help predict mesothelioma survival but, because this one is specifically about suitability for a clinical trial, it could be very useful for patients who have exhausted other treatment options,” says Alex Strauss, Managing Editor for Surviving Mesothelioma. All the details of the new study, including the three criteria on which the new prognostic tool is based, can be found in the article Scoring Tool Helps Doctors Select Mesothelioma Patients for Clinical Trials, now available on the Surviving Mesothelioma website. Papadatos-Pastos, D, et al, “Clinical outcomes and prognostic factors of patients with advanced mesothelioma treated in a phase I clinical trials unit”, February 16, 2017, European Journal of Cancer, Epub ahead of print, http://www.ejcancer.com/article/S0959-8049(17)30042-4/references For more than a decade, Surviving Mesothelioma has brought readers the most important and ground-breaking news on the causes, diagnosis and treatment of malignant mesothelioma. All Surviving Mesothelioma news is gathered and reported directly from the peer-reviewed medical literature. Written for mesothelioma patients and their loved ones, Surviving Mesothelioma news helps families make more informed decisions.
News Article | February 15, 2017
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 14, 2017
If at First You Don’t Succeed… In May 2016, renewable energy advocates were surprised to see Governor Hogan veto the Clean Energy Jobs Act (SB 921/ HB 1106), which had passed the legislature with strong bipartisan support. The Clean Energy Jobs Act would have increased the states renewable portfolio standard and provided a modest increase to the solar carve-out. However, after the Governor’s veto, hope was not lost. After passing with a veto proof majority, legislators were confident that an override would occur in early 2017. After months of waiting, the state legislature was successful in overriding Governor Hogan’s veto last week, and the Clean Energy Jobs Act will now become law. The Maryland Senate overrode the Governor’s veto in a 32-13 vote, and the veto override passed with a 88-15 vote in the House of Delegates. What Does This Mean for Renewables? With the Clean Energy Jobs Act approved as law, Maryland’s renewable portfolio standard will now be raised to 25% by 2020. This means that by 2020, 25% of the state’s electricity needs will be met from clean energy sources like solar and wind. This is a bump from the previous standard of 20% by 2022. The solar carve-out will also increase slightly from 2% by 2022 to 2.5% by 2020. Such a modest increase in the solar carve-out may provide some initial relief to Maryland’s solar renewable energy credit (SREC) market, which plummeted in 2016 for a number of reasons, mainly higher than expected residential build, and to a lesser extent, the perception of the PJM interconnection queue. Before the passage of the override, Maryland SRECs were trading at $18, only slightly higher than Pennsylvania and Ohio, two markets that have experienced lackluster solar growth over the last several years. For reference, prices in Maryland were at $100/SREC only one year ago. According to the Chesapeake Climate Action Network, the Act will incentivize 1.3GW of new clean energy in Maryland and could reduce greenhouse gas emissions by more than 2.7 million metric tons per year. And, while the override will not bring SREC values to early 2016 levels, this victory is an important first step in providing some relief to the market which is home to over 5,400 in-state solar jobs. More importantly, it is yet another win for strong, local renewable portfolio standards. With this new act, Maryland joins other renewable policy success stories from 2016. Notably, we saw Ohio put an end to its RPS freeze, New York and Rhode Island aim for high renewable targets of 50% and 38.5% respectively, and Illinois sign into law a bill to make their RPS more effective. D.C., Oregon, and Michigan also increased their RPS standards in 2016. As other leadership states look to increase their renewable standards to 40% or even 50%, will Maryland lead or follow? Only time will tell. Sol Systems, a national solar finance and development firm, delivers sophisticated, customized services for institutional, corporate, and municipal customers. Sol is employee-owned, and has been profitable since inception in 2008. Sol is backed by Sempra Energy, a $25+ billion energy company. Over the last eight years, Sol Systems has delivered more than 500MW of solar projects for Fortune 100 companies, municipalities, universities, churches, and small businesses. Sol now manages over $650 million in solar energy assets for utilities, banks, and Fortune 500 companies. Inc. 5000 recognized Sol Systems in its annual list of the nation’s fastest-growing private companies for four consecutive years. For more information, please visit www.solsystems.com.
News Article | February 25, 2017
The Sol SOURCE is a monthly journal that our team distributes to our network of clients and solar stakeholders. Our newsletter contains energy statistics from current real-life renewables projects, trends, and observations gained through monthly interviews with our team, and it incorporates news from a variety of industry resources. Below, we have included excerpts from the February 2017 edition. To receive future Journals, please subscribe or email email@example.com. The following statistics represent some high-quality solar projects and portfolios that we are actively reviewing for investment. Have a solar project in need of financing? Our team can provide a pricing quote for you here. Maryland – It’s official. This month, the Maryland state legislature voted to override Governor Hogan’s veto to HB1106, the Clean Energy Jobs Act. With the override, the state’s renewable energy goal has increased to 25% by 2020 (up from 20% by 2022), and the solar carve-out increased from 2% by 2022 to 2.5% by 2020. While short-term SREC pricing did not increase, the override prevented a further dip in values. Its primary benefit will be a boost to 2019 and 2020 demand, which may result in higher pricing for those SREC vintages. Perhaps SREC prices will rise in coming years, but for now, $20/SREC is the new normal in Maryland, where SREC values have plummeted over the last year given rapid build, most notably of the residential sector. At press time, 493MW of behind-the-meter (<2MW) solar has been installed in Maryland, as compared to 171MW of projects over 2MW in size. More recently, two bills have been introduced to examine the oversupply in the SREC market: one that would expand the solar carve-out to 4% (HB1457) and another that would require a study to examine possible “bigger picture” changes to the RPS (HB1414). Meanwhile, energy storage is a hot topic at the state legislature this session, where several storage bills will soon be heard in committee. Proposed legislation could create an energy storage income tax credit (HB0490/SB0758) and an energy storage grant program (HB1395). Introduced legislation would also require the Maryland Clean Energy Center to study possible incentives and regulatory constructs to encourage energy storage (HB0773/SB0715). Massachusetts – After months of stakeholder engagement, the ever-patient, ever-diligent Massachusetts Department of Energy Resources (DOER) announced the design of Solar Massachusetts Renewable Target (SMART) program, the next iteration of the state’s solar incentive regime. As a refresher, commercial projects in the nation’s #7 solar market have come to a halt [with few exceptions] since the SREC II program closed. With SMART, Massachusetts will transition away from an SREC program and toward a declining block incentive. SMART will also incentivize rooftop solar, canopy structures, and storage – and provide a lower incentive to greenfield development. Land use and siting requirements will be more stringent than in SREC I and SREC II. Transitioning from one program to the next takes time, and DOER acknowledged this at the January 31 “reveal”. In order to avoid further disruptions in renewable energy investments in the Commonwealth (Massachusetts actually lost solar jobs this last year, according the latest Solar Jobs Census), the DOER will extend SREC II to provide a “bridge” to SMART. In order to qualify for SREC II at a discounted incentive level, projects must reach mechanical completion by the start of the new program, which is now estimated to begin in January 2018 at the earliest. These details are subject to change; comments on the SREC II extension were due February 17. While SREC II has been extended, the net metering caps have not been lifted; legislation is required to lift the caps (again). The SMART program aims to circumvent this by providing developers with an “on-bill crediting” alternative to net metering. Notably, the Board of Public Utilities – not DOER – must lead this process and so there is a degree of uncertainty here. Details are still to be determined. The Massachusetts market is experiencing many changes. Sol Systems is following the market transition closely and would be happy to talk them through with you. Feel free to give us a call at (202) 349-2085. South Carolina – Solar incentive programs for non-residential projects up to 1MW AC in Duke Progress and Duke Carolinas territory have filled, and South Carolina Gas & Electric is soon to follow. While cumbersome fee in lieu of taxes (FILOT) negotiations have hindered economics for commercial and industrial solar projects in the Palmetto state, project economics could improve vastly if property tax abatement legislation is passed this year. The Renewable Energy Property Tax Act (S.44) passed its third and final reading in the Senate in early February and now sits with House Ways & Means. If passed, South Carolina would offer an 80% property tax abatement for non-residential systems, much like its neighbor to the North. Property tax abatement nearly passed last year, but failed after a last minute “poison pill.” Sol Systems, a national solar finance and development firm, delivers sophisticated, customized services for institutional, corporate, and municipal customers. Sol is employee-owned, and has been profitable since inception in 2008. Sol is backed by Sempra Energy, a $25+ billion energy company. Over the last eight years, Sol Systems has delivered more than 500MW of solar projects for Fortune 100 companies, municipalities, universities, churches, and small businesses. Sol now manages over $650 million in solar energy assets for utilities, banks, and Fortune 500 companies. Inc. 5000 recognized Sol Systems in its annual list of the nation’s fastest-growing private companies for four consecutive years. For more information, please visit www.solsystems.com.
News Article | February 22, 2017
In case you missed it, a recent investigative piece in the LA Times unearthed the shocking fact that California retail electricity prices are high, about 50% higher than the national average. The article’s main focus is on the fact that California has a lot more installed nameplate generation capacity then has historically been the norm. There are several causes identified in the piece. Deregulation of the market in the late 1990’s is pointed to as a culprit. Somewhat inconsistently, the construction of regulated, rate-based plants also takes much of the blame. One factor that was barely mentioned, however, was California’s renewable electricity policy. The story of how California’s electric system got to its current state is indeed a long and gory one going back at least to the 1980’s. The system still suffers from some of the after effects of the 2000 era crisis. The Long Term Procurement Process (LTPP) put in place in the wake of the crisis, and overseen by the CPUC, has been criticized from many sides. However, since the power crisis of the early 2000’s settled down, the dominant policy driver in the electricity sector has unquestionably been a focus on developing renewable sources of electricity generation. As is well known (outside of the LA Times apparently), California has one of the country’s most aggressive renewable portfolio standards (RPS). The RPS requires each firm that sells electricity to end-users to procure an increasing fraction (33% by 2020, 50% by 2030) of the energy they sell from renewable sources. The Times article’s focus on generation capacity does (a bit unwittingly) provide a nice starting point for a discussion about the cost and implications of this renewable energy policy. The policy, while undoubtedly effective at reducing the carbon intensity of the power sector, has also been quite disruptive to the economics of the sector. It is forcing a rapid (and early) replacement of conventional sources with renewable, but variable, generation sources such as solar and wind. Since 2010, about 80% of new capacity has come from renewable sources and it’s likely that much of that capacity would not have been built if not for the RPS. (Much of the remaining 20% has been coming online to replace the retired SONGS nuclear plant or capacity slated for retirement due to environmental issues with their water cooling processes.) Proponents of strong renewable standards have pointed to the fact that new contracts for renewable energy carry price tags that are (at worst) only modestly above those for a new conventional natural gas power plant. However comparing the cost of a brand-new solar plant to that of a brand-new gas plant overlooks two important facts. First, renewable, variable output sources offer very different operational capabilities than conventional sources. Second, right now we don’t really need new capacity of any kind, and are in fact struggling to find ways to compensate the generators that are already here. The renewable portfolio standard provides an interesting contrast to the federal mileage standards on vehicles. Both require the replacement of older legacy, high-carbon sources with newer, lower-carbon ones. However automobile standards work by requiring people to buy more fuel-efficient cars when they decide to buy a new car. Renewable portfolio standards require utilities to buy low-carbon energy by a certain deadline rather than when they are deciding to “trade-in” their old power plants. In California at least, the result has been a much more rapid turnover of legacy sources to the newer, cleaner ones. Another implication, however is the fact that the system now has a large amount of what can appear to be excess capacity. This is because renewable policies are rapidly forcing new “green” capacity into a market that was more or less fully resourced before the mandates really started taking effect. I don’t mean to imply that the “replace it now” approach is definitively worse. Research has shown that standards applied only to new purchases can inefficiently extend the lifetimes of older technology, from cars to power plants. This can significantly dilute the environmental benefits of a technology mandate. In contrast, instead of extending the lifetimes of old plants, the RPS is in effect forcing the early mothballing of legacy capacity. This improves the environmental impact, but also increases costs, sometimes in subtle ways. The effect grows larger with stricter mandates. At higher percentages, the RPS starts to displace increasingly newer (and cleaner) sources of generation. The economic effects can be mitigated by allowing for renewable energy generated elsewhere in the country to count toward RPS compliance, but California has largely rejected such policies. Largely due to the RPS, we have a surge of new, low marginal cost energy, flooding into a wholesale market that already had enough generic energy, thereby driving down wholesale prices. Since wholesale prices cannot support the cost of this much generation (new and old), increasingly the gap must be made up through rising margins between wholesale and retail prices. Utilities and other retailers have to pay high market prices for new renewables instead of being able to “buy low” on the wholesale market. Because all retailers face the same regulation, they pass these costs on to end users. And this doesn’t even consider the costs of new transmission, most of which is being added to boost the power system’s ability to access and absorb large amounts of renewable energy. Transmission costs, which are also charged through to electricity end users as part of the retail prices cited in the Times article, will continue to grow in coming years. The Tehachapi transmission project alone is projected to cost over $2 Billion. The result is the seemingly perverse situation where customer rates are rising while (conventional) generation sources are simultaneously struggling for revenue and threatening to retire. Such conditions are a recurring theme on this blog and are often drivers of significant change. Unfortunately, despite the glut of electrical energy, we will likely still need the conventional capacity to handle the ramping and back-up needs created by the increased reliance on variable sources (wind and solar). One of the debates lurking in the background is who should be responsible for the cost of these disruptions. Richard Schmalensee has observed that deregulation may make it easier for State policy makers and regulators to ignore wholesale market effects. This is because the assets being stranded today are largely owned by non-utility generation companies in contrast to the late 1990’s when the stranded assets were a joint problem of regulated utilities and their rate payers. California led the way with developing renewable energy in the 1980’s, with the deregulation of the power sector in the 1990’s and 2000’s, and now with high-volume renewable mandates since 2010. We are learning a lot about how to physically manage and finance a cleaner energy system. We also need be realistic about the costs of such policies. When you combine the cost of policies of the past with the aggressive goals for the future, you get retail electricity prices that, yes, continue to be pretty darn high.
News Article | February 2, 2017
The legislature overrode a veto blocking expansion of the state's renewable portfolio standard. The Maryland General Assembly voted to override Gov. Larry Hogan’s veto of the Clean Energy Jobs Act today. That means more jobs, economic development and clean energy for Maryland families and businesses. State Sens. Brian Feldman and Catherine Pugh, along with Del. William Frick, were instrumental in pushing the measure through successfully. In April of last year, the state’s lawmakers voted to increase Maryland’s renewable portfolio standard (RPS) to 25 percent by 2020. Today’s actions mean that target now becomes law. The Clean Energy Jobs Act is appropriately named. Today, wind energy supports over 100,000 well-paying jobs, and by 2030 there could be 380,000 wind power positions. By choosing to raise its RPS, Maryland is using a policy with a long track record of success. Researchers from top national laboratories have found that renewable energy projects built to help states meet RPS targets resulted in billions of dollars in economic and environmental savings, while creating over 200,000 jobs. Wind power will play an important role in helping Maryland hit its clean renewable energy target, and has already provided the state with an economic boost. The state’s landowners already receive up to $1 million in lease payments every year for hosting turbines, and wind has attracted $380 million of private investment into the state’s economy.
News Article | February 9, 2017
MINNEAPOLIS, Feb. 09, 2017 (GLOBE NEWSWIRE) -- GWG Holdings, Inc. (Nasdaq:GWGH), a financial services company committed to transforming the life insurance industry, announced that its board of directors has approved the payment of a special cash dividend of $2.50 per share to holders of its Redeemable Preferred Stock (RPS). The dividend will be paid on April 14, 2017 to stockholders of record at the close of business on April 5, 2017. CEO Jon Sabes said, “We are offering this special dividend in conjunction with the expected closing of our current $100 million RPS offering.” Additional details can be found in the Company's Form 8-K filed with the Securities and Exchange Commission on Feb. 9, 2017. GWG Holdings, Inc. (Nasdaq:GWGH) is a financial services company committed to applying advanced epigenetic mortality prediction technology to the life insurance and related industries. Already a recognized disruptor in the life insurance secondary market, GWG seeks to further transform the industry by continuing to create innovative products and services. As of September 30, 2016, GWG’s growing portfolio consisted of $1.27 billion in face value of policy benefits and paid consumers $357 million for their life insurance. For more information about GWG Holdings, Inc. email firstname.lastname@example.org or visit www.gwgh.com. This press release contains forward-looking statements that involve substantial risks and uncertainties. All statements, other than statements of historical facts, included in this press release regarding our strategy, future operations, future financial position, future revenue, projected costs, prospects, plans and objectives of management are forward-looking statements. The words "anticipate," "believe," "estimate," "expect," "intend," "may," "plan," "would," "target" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words. These forward-looking statements include, among other things, statements about our estimates regarding future revenue and financial performance. We may not actually achieve the expectations disclosed in our forward-looking statements, and you should not place undue reliance on our forward-looking statements. Actual results or events could differ materially from the expectations disclosed in the forward-looking statements we make. More information about potential factors that could affect our business and financial results is contained in our filings with the Securities and Exchange Commission. Additional information will also be set forth in our future quarterly reports on Form 10-Q, annual reports on Form 10-K and other filings that we make with the Securities and Exchange Commission. We do not intend, and undertake no duty, to release publicly any updates or revisions to any forward-looking statements contained herein.
News Article | February 16, 2017
Almost immediately after the funds of the American Recovery and Reconstruction Act, ARRA, became available, many states, including Vermont, distributed some of the funds to a number of government and private renewable energy entities. Government programs with federal and state subsidies were created to attract in-state and out-of-state investments in renewable energy projects to create jobs and boost the economy. In Vermont, the media were enlisted to build up an image of Vermont as a “renewable energy leader”. Well-known foreign renewable energy leaders were invited to Vermont to give lectures about their renewable energy achievements. A 520-page report of the Vermont’s Comprehensive Energy Plan, CEP, was created, which states an aspirational goal of “90% Renewable Energy of All Primary Energy by 2050”; electrical energy is only about 35% of all primary energy. NOTE: No nation in the world, except Denmark, has such an extreme goal, however, Denmark is a special case, because of its proximity to Norway’s hydro plants to balance its wind energy. In the real world, almost all political entities have much lower RE goals for primary energy than Vermont. Relatively few political entities have high RE goals for electrical energy. NOTE: The German Energiewende goal is at least 80% of electricity production and 60% of primary energy from RE by 2050, which is much less extreme than Vermont’s 90%. Denmark and German Household Electric Rates: Denmark and Germany implementing higher renewable energy percentages has led to higher household electric rates. The same would happen in Vermont. The below graph shows German household electric rates are the second highest in Europe, about 28.69 eurocent/kWh in 2015; Denmark is the leader with about 30 eurocent/kWh, Ireland is at 25 c/kWh, Spain 24 c/kWh, France, about 80% nuclear generation, 17 c/kWh. From Aspirational Goal to Mandate: Senator Bray introduced Bill S.51, titled “Consolidated Clean Energy Planning and Economic Opportunity Act” The bill proposes: to establish a statutory goal (a mandate), that, by 2050, 90 percent of Vermont’s total energy consumption be from renewable energy. It also proposes to establish additional supporting goals and to require State plans that affect energy to recommend measures to achieve these goals. State and local bureaucrats would exhort Vermonters to spend $33.3 billion on various government-directed measures and programs that would cause their energy consumption to decrease, but the cost of their remaining energy consumption likely would be about 2 – 3 times present costs. An Easy Task for Utilities: It would be an easy task for Vermont utilities to achieve a Renewable Portfolio Standard, RPS, of “90% RE of their electricity supply”. They merely would have additional contracts to buy RE from in-state and out-of-state producers, and pass any costs onto ratepayers, per VT-Public Service Board, PSB, approval. An Expensive Task for Vermonters: It would be extremely expensive for Vermonters to achieve “90% RE of All Primary Energy by 2050”, as that would require a significant transformation of the Vermont economy. Vermonters would have to make investments of about $33.3 billion* during the 2017 – 2050 period, as estimated by the Vermont Energy Action Network. Vermont’s stakeholders prefer the renewable energy to be from mostly in-state sources, as that would maximize their revenues and profits. Federal subsidies for wind, solar, and other renewable sources likely would be decreasing in future years. * If the US were to adopt Vermont’s 90% RE goal, the capital cost would be: US 325 million people/Vermont 0.625 million x 33.3 = $17,316 billion, which is in the same ballpark as the US national debt. Reducing the 90% Goal to 40% is an Economic Necessity: Reducing the 90% goal to 40% would be more affordable, and it could be implemented by means of: – Significantly increased efficiency of buildings (such as net zero energy buildings) and of transportation (such as by adherence to federal CAFE standards), which would be much better for Vermont, as it would decrease the energy bills for already-struggling households and businesses, and would decrease CO2. Both measures would be the lowest-cost and quickest way to reduce CO2, and would have minimal impact on the Vermont environment. They would be much better for Vermont, instead of additional, subsidized wind turbine systems on more than 200 miles of pristine ridgelines and solar systems in thousands of acres of fertile meadows, which produce energy, that is variable, intermittent, grid disturbing, health damaging, property value-lowering, environment-damaging, social-discord-creating, and expensive at 3 – 5 times NE wholesale prices of 5 c/kWh. The 40% goal would be more in line with other New England states and much less costly. See Table 2. There would be no need for a regressive carbon tax. With the 40% goal, source energy would be reduced, similar to the 90% goal, by getting more, low-cost, near CO2-free, hydro energy from Hydro-Quebec*. *About 200 MW of a 1000 MW HVDC line, under construction, is reserved for Vermont, which could provide about 1.3 million MWh/y from H-Q in addition to the present H-Q supply, equivalent to 7 Lowell wind turbine plants. Future HVDC lines, in various planning and approval stages, could provide more hydro electricity. Source Energy Factors: The ratio of the energy from well, mine, forest, etc., to user is defined as the source energy factor. The source factors of hydro is 1.0, NE grid energy 2.63, nuclear 3.08, and biomass 3.33*. Whereas the source factors of variable wind and solar are 1.0, they require grid-connected generators for balancing, as in Germany and Denmark. The source energy would also be reduced by significantly increased efficiency of buildings and transportation. * McNeil and Ryegate wood-fired power plants have source factors of 4.2, because of their poor efficiency. Closing them would significantly reduce Vermont’s source energy (3.2 out of 4.2 trees are wasted), and toxic pollution, and CO2 emissions (which are not counted, because burning trees is “declared” CO2-neutral within about 50 to 100 years). NOTE: Vermont Public Issues Research Group, VPIRG, mostly financed by RE stakeholders, commissioned a study by REMI, a consultant, which provided VPIRG, legislators, et al, with a report with pretty photographs, a rosy pro-carbon tax rationale, and various talking points, to bamboozle voters regarding the merits of the proposed carbon tax. NOTE: In 2011, the electricity supplied to Vermont utilities was 6119.1 GWh, or 20.88 TBtu. That electricity required about 50.8 TBtu of primary energy, for an average conversion factor of 20.88/50.8 = 0.41, per the VT-Department of Public Service 2013 Utility Facts Report. Vermont’s 2010 total primary energy was 147.6 TBtu, thus electricity was 50.8/147.6 = 34.4% of total primary energy. NOTE: “The Department of Public Service, DPS, in conjunction with other State agencies designated by the Governor, shall prepare a State Comprehensive Energy Plan covering at least a 20-year period”, per Vermont statute $202b. DPS, et al, arbitrarily selected the goal of “90% RE of All Primary Energy by 2050”, without any feasibility and cost analysis. DPS correctly stated during a public information hearing: “It does not matter what Vermont does, because it would not make any difference regarding climate change and global warming”. Thus far, after waiting for years, Vermonters have not received any rational explanation of why that goal was selected. That goal is greatly in excess of what other New England states have as their goals. Huge Capital Requirements: Vermont’s goal of attaining 90% of its energy from renewables by 2050 would require capital investments of at least $33.3 billion during the 2017-2050 period, about $1 billion per year, according to Vermont Energy Action Network’s 2015 annual report. That’s not counting interest and finance charges and replacements and refurbishments due to wear and tear. See Page 6 of annual report. That burden is far in excess of what the near zero, real-growth Vermont economy could afford. It took at least $900 million to go from 11.53% total renewable energy (EAN number) in 2010 to about 15% in 2016. That includes electricity, transportation energy and heating and cooling. This was made easier because it was highly subsidized. That level of subsidies will be less going forward, because wind, solar and other subsidies are being reduced. Most of that spending affected the electrical part. As a result, Vermont utilities likely will meet 55% RE of their electricity supply by 2017, and 75% by 2032. It would require a minimum of about $950 million per year between 2017 and 2050 to meet the 90% renewable goal. See Table 1, which is based on estimates by EAN, a consultant for Vermont Energy Investment Corporation, VEIC, and DPS. See URL. *EAN uses source energy (from mine or well to as delivered to user) and DPS uses primary energy (as delivered to user), which is slightly less than source energy. Year 2016 obtained by interpolation. Where would the many billions of additional money come from for the remaining electrical part, plus the much more expensive thermal and transportation parts? Vermont is a relatively poor state with a stagnant population; a growing population of elderly and dependent people; state budget deficits year after year; a near zero, real-growth economy; and a very poor business climate. The last thing Vermont households and businesses need is a doubling or tripling of energy prices to make the Vermont economy even less competitive. If we were to reduce the goal to 40% renewable by 2050, it would still be a formidable task. That goal would require a minimum of about $420 million per year between 2017 and 2050. See Table 2. Renewable Portfolio Standards: Renewable portfolio standards require utilities to have a percentage of their electricity supply from renewable sources. Two states, Hawaii and Vermont, require much higher percentages of renewable energy than any other state in the nation. Hawaii requires 30% by 2020, 40% by 2030, 70% by 2040, and 100% by 2045. Unlike Vermont, Hawaii is much closer to the equator, has steady trade winds and much sunshine, and has the highest electric rates in the United States. The Hawaii goal is reasonable, but the Vermont goal is economically unwise. See URLs and Table 3. *MA percent to increase by 1%/y after 2020; the ME and VT goals are higher because of hydro being counted as renewable. Vermont utilities could satisfy the 75% requirement within a few years (well before 2032) by buying more hydro energy from Hydro-Quebec. That would require no subsidies and near-zero capital costs, because private corporations would design, build, own and operate the high voltage transmission lines from Quebec to Vermont. However, Green Mountain Power, which controls 77% of Vermont’s electricity market, refuses to buy more hydro energy for business reasons, i.e., it would not increase its asset base on which it earns about 9% per year.
News Article | February 22, 2017
RALEIGH, N.C., Feb. 22, 2017 (GLOBE NEWSWIRE) -- PRA Health Sciences, Inc. (“PRA” or the “Company”) (NASDAQ:PRAH) today reported financial results for the quarter ended December 31, 2016. For the three months ended December 31, 2016, service revenue was $413.6 million, which represents growth of 14.2%, or $51.3 million, compared to the fourth quarter of 2015 at actual foreign exchange rates. On a constant currency basis, service revenue grew $52.9 million, an increase of 14.6% compared to the fourth quarter of 2015. Net new business for the quarter ended December 31, 2016 was $587.3 million, representing a net book-to-bill ratio of 1.42 for the period. This net new business contributed to an ending backlog of $2.9 billion at December 31, 2016. “We are pleased to have delivered another quarter with double-digit revenue, earnings and net new business growth year-over-year,” said Colin Shannon, PRA’s Chief Executive Officer. “We are well-positioned to deliver at least mid-teens growth during the coming year, as evidenced by our record level of new business awards and backlog. We continue to stay focused on our key strategic objectives, our client deliverables and developing our people, and we look forward to delivering strong results in 2017.” Direct costs were $274.4 million during the three months ended December 31, 2016 compared to $234.9 million for the fourth quarter of 2015. Direct costs were 66.3% of service revenue during the fourth quarter of 2016 compared to 64.8% of service revenue during the fourth quarter of 2015. The increase in direct costs as a percentage of service revenue is due to the continued hiring of billable staff to support our current projects and the hiring of additional staff to ensure appropriate staffing levels to support our future growth. Selling, general and administrative expenses were $70.2 million during the three months ended December 31, 2016 compared to $63.6 million for the fourth quarter of 2015. Selling, general and administrative costs were 17.0% of service revenue during the fourth quarter of 2016 compared to 17.6% of service revenue during the fourth quarter of 2015. The decrease in selling, general and administrative expenses as a percentage of revenue is attributable to our ability to continue to effectively manage our sales and administrative functions as the Company continues to grow. For the three months ended December 31, 2016, we incurred transaction-related expenses of $13.0 million. The costs consist of $12.7 million of one-time stock-based compensation expense related to the release of transfer restrictions on vested options and the vesting of certain performance-based stock options in connection with the November secondary offering. In addition, we incurred $0.3 million of third-party fees associated with the secondary offering. During the fourth quarter of 2016, we also incurred a loss on extinguishment of debt of $16.7 million. This loss is associated with our refinancing on our first lien term debt, which included the write-off of $15.8 million of unamortized debt issuance costs and $0.9 million of other costs associated with the transaction. GAAP net income was $14.0 million for the three months ended December 31, 2016, or $0.22 per share on a diluted basis, compared to GAAP net income of $28.5 million for the three months ended December 31, 2015, or $0.45 per share on a diluted basis. Our GAAP net income for the three months ended December 31, 2016 included transaction-related expenses and the loss on extinguishment discussed above. EBITDA was $54.3 million for the three months ended December 31, 2016, representing a decrease of 22.0% compared to the fourth quarter of 2015. Adjusted EBITDA was $73.9 million for the three months ended December 31, 2016, representing growth of 8.8% compared to the fourth quarter of 2015. Adjusted Net Income was $45.9 million for the three months ended December 31, 2016, representing 22.3% growth compared to the fourth quarter of 2015. Adjusted Net Income per diluted share was $0.71 for the three months ended December 31, 2016, representing 20.3% growth compared to the fourth quarter of 2015. A reconciliation of our non-GAAP measures, including EBITDA, Adjusted EBITDA, Adjusted Net Income, Adjusted Net Income per share and our 2017 guidance, to the corresponding GAAP measures is included in this press release. For the twelve months ended December 31, 2016, service revenue was $1,580.0 million, which represents growth of 14.8%, or $204.2 million, compared to the twelve months ended December 31, 2015 at actual foreign exchange rates. On a constant currency basis, service revenue grew $209.5 million, representing growth of 15.2% compared to the twelve months ended December 31, 2015. GAAP income from operations was $162.3 million, GAAP net income was $68.2 million and GAAP net income per diluted share was $1.06 for the twelve months ended December 31, 2016. Adjusted Net Income was $162.3 million for the twelve months ended December 31, 2016, an improvement of 28.6% compared to the same period in 2015. Adjusted Net Income per diluted share was $2.52 for the twelve months ended December 31, 2016, up 26.0% compared to the same period in 2015. For Full Year 2017, the Company expects to achieve service revenues between $1.795 billion and $1.835 billion, representing constant currency growth of 14% to 16%, GAAP net income per diluted share between $2.46 and $2.56 per share, representing growth of 132% to 142%, Adjusted Net Income per diluted share between $3.08 and $3.18 per share, representing growth of 22% to 26%, and annual effective income tax rate estimates at approximately 27%. For Q1 2017, the Company expects to achieve service revenues between $415 million and $425 million, representing constant currency growth of 11% to 14%, GAAP net income per diluted share between $0.41 and $0.46 per share, Adjusted Net Income per diluted share between $0.57 and $0.62 per share, and annual effective income tax rate estimates at approximately 27%. All financial guidance assumes a EURO rate of 1.11 and a GBP rate of 1.35. All other foreign currency exchange rates are as of January 31, 2017. PRA will host a conference call at 9:00 a.m. ET on February 23, 2017, to discuss the contents of this release and other relevant topics. To participate, please dial (877) 930-8062 within the United States or (253) 336-7647 outside the United States approximately 10 minutes before the scheduled start of the call. The conference ID for the call is 66572766. The conference call will also be accessible, live via audio broadcast, on the Investor Relations section of the PRA website at www.prahs.com/investors. A replay of the conference call will be available online at www.prahs.com/investors. In addition, an audio replay of the call will be available for one week following the call and can be accessed by dialing (855) 859-2056 within the United States or (404) 537-3406 outside the United States. The replay ID is 66572766. PRA (NASDAQ:PRAH) is one of the world’s leading global contract research organizations, or CROs, by revenue, providing outsourced clinical development services to the biotechnology and pharmaceutical industries. PRA’s global clinical development platform includes approximately 70 offices across North America, Europe, Asia, Latin America, South Africa, Australia and the Middle East and over 13,000 employees worldwide. Since 2000, PRA has performed approximately 3,500 clinical trials worldwide. In addition, PRA has participated in the pivotal or supportive trials that led to U.S. Food and Drug Administration or international regulatory approval of more than 70 drugs. PRA has therapeutic expertise in areas that are among the largest in pharmaceutical development, including oncology, central nervous system, inflammation and infectious diseases. PRA believes that it provides its clients with one of the most flexible clinical development service offerings, which includes both traditional, project-based Phase I through Phase IV services, as well as embedded and functional outsourcing services. The Company has invested in medical informatics and clinical technologies designed to enhance efficiencies, improve study predictability and provide better transparency to clients throughout their clinical development processes. To learn more about PRA, please visit www.prahs.com. Internet Posting of Information: The Company routinely posts information that may be important to investors in the ‘Investor Relations’ section of the Company’s website at www.prahs.com. The Company encourages investors and potential investors to consult the Company’s website regularly for important information about the Company. This press release contains forward-looking statements that reflect, among other things, the Company’s current expectations and anticipated results of operations, all of which are subject to known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements, market trends or industry results to differ materially from those expressed or implied by such forward-looking statements. For this purpose, any statements contained herein that are not statements of historical fact may constitute forward-looking statements. Without limiting the foregoing, words such as “anticipates,” “believes,” “estimates,” “expects,” “guidance,” “intends,” “may,” “plans,” “projects,” “should,” “targets,” “will” and the negative thereof and similar words and expressions are intended to identify forward-looking statements. Actual results may differ materially from the Company’s expectations due to a number of factors, including that most of the Company’s contracts may be terminated on short notice and that the Company may be unable to maintain large customer contracts or to enter into new contracts; the historical indications of the relationship of backlog to revenues may not be indicative of their future relationship; the market for the Company’s services may not grow as the Company expects; the Company may under price contracts or overrun its cost estimates, and if the Company is unable to achieve operating efficiencies or grow revenues faster than expenses, operating margins will be adversely affected; the Company may be unable to maintain information systems or effectively update them; customer or therapeutic concentration could harm the Company’s business; the Company’s business is subject to risks associated with international operations, including economic, political and other risks; the Company is also subject to a number of additional risks associated with its business outside the United States, including foreign currency exchange fluctuations and restrictive regulations, as well as the risks and uncertainties associated with the United Kingdom’s expected withdrawal from the European Union; government regulators or customers may limit the scope of prescription or withdraw products from the market, and government regulators may impose new regulations affecting the Company’s business; the Company may be unable to successfully develop and market new services or enter new markets; the Company’s failure to perform services in accordance with contractual requirements, regulatory standards and ethical considerations may subject it to significant costs or liability, damage its reputation and cause it to lose existing business or not receive new business; the Company’s services are related to treatment of human patients, and it could face liability if a patient is harmed; the Company has substantial indebtedness and may incur additional indebtedness in the future, which could adversely affect the Company’s financial condition; and other factors that are set forth in the Company’s filings with the Securities and Exchange Commission, including our most recent Annual Report on Form 10-K filed with the SEC on February 25, 2016. The Company undertakes no obligation to update any forward-looking statement after the date of this release, whether as a result of new information, future developments or otherwise, except as may be required by applicable law. Use of Non-GAAP Financial Measures This press release includes EBITDA, Adjusted EBITDA, Adjusted Net Income and Adjusted Net Income per share, each of which are financial measures not prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). Management believes that these measures provide useful supplemental information to management and investors regarding our operating results as they exclude certain items whose fluctuation from period- to period do not necessarily correspond to changes in the operating results of our business. As a result, management and our board of directors regularly use EBITDA and Adjusted EBITDA as a tool in evaluating our operating and financial performance and in establishing discretionary annual bonuses. Adjusted EBITDA is also the basis for covenant compliance EBITDA, which is used in certain covenants in the credit agreement governing our senior secured credit facilities and the indenture governing the senior notes. In addition, management believes that EBITDA, Adjusted EBITDA and Adjusted Net Income (including diluted adjusted net income per share) facilitate comparisons of our operating results with those of other companies by backing out of GAAP net income items relating to variations in capital structures (affecting interest expense), taxation, and the age and book depreciation of facilities and equipment (affecting relative depreciation expense), which may vary for different companies for reasons unrelated to operating performance. We believe that EBITDA, Adjusted EBITDA and Adjusted Net Income (including diluted adjusted net income per share) are frequently used by securities analysts, investors, and other interested parties in the evaluation of issuers, many of which also present EBITDA, Adjusted EBITDA and Adjusted Net Income (including diluted adjusted net income per share) when reporting their results in an effort to facilitate an understanding of their operating results. These non-GAAP financial measures have limitations as analytical tools, and you should not consider these measures in isolation, or as a substitute for analysis of our results as reported under GAAP. Additionally, because not all companies use identical calculations, these presentations of EBITDA, Adjusted EBITDA and Adjusted Net Income (including diluted adjusted net income per share) may not be comparable to similarly titled measures of other companies. EBITDA represents net income before interest, taxes, depreciation and amortization. Adjusted EBITDA and Adjusted Net Income (including diluted adjusted net income per share) represent EBITDA and net income (including diluted net income per share), respectively, adjusted to exclude stock-based compensation expense, loss (gain) on disposal of fixed assets, loss on modification or extinguishment of debt, foreign currency losses and gains, other (expense) income, equity in (gains) losses of unconsolidated joint ventures, transaction-related cost, acquisition-related costs, severance costs and restructuring charges, prior year foreign research and development credits, lease termination costs, non-cash rent adjustments and other charges. Adjusted Net Income is also adjusted to exclude amortization of intangible assets, amortization of terminated interest rate swaps, and amortization of deferred financing costs. EBITDA, Adjusted EBITDA and Adjusted Net Income are not measurements of our financial performance under GAAP and should not be considered as alternatives to net income or other performance measures derived in accordance with GAAP or as alternatives to cash flow from operating activities as measures of our liquidity. EBITDA, Adjusted EBITDA and Adjusted Net Income have limitations as analytical tools, and you should not consider such measures either in isolation or as substitutes for analyzing our results as reported under GAAP. Some of these limitations are: Because of these limitations, EBITDA and Adjusted EBITDA should not be considered as discretionary cash available to us to reinvest in the growth of our business or as a measure of cash that will be available to us to meet our obligations. Constant currency comparisons are based on translating local currency amounts in the current year period at actual foreign exchange rates for the prior year. The Company routinely evaluates its financial performance on a constant currency basis in order to facilitate period- to- period comparisons without regard to the impact of changing foreign currency exchange rates. (a) Stock-based compensation expense represents the amount of recurring non-cash expense related to the Company’s equity compensation programs, excluding transaction-related stock-based compensation discussed in footnote (g). (b) Loss on disposal of fixed assets represents the costs incurred in connection with the sale or disposition of fixed assets, primarily IT equipment and furniture and fixtures. We exclude these losses from Adjusted EBITDA and Adjusted Net Income because they result from investing decisions rather than from decisions made related to our ongoing operations. (c) Loss on extinguishment of debt relates to costs incurred in connection with changes to our long-term debt. We exclude these losses from Adjusted EBITDA and Adjusted Net Income because they result from financing decisions rather than from decisions made related to our ongoing operations. (d) Foreign currency (gains) losses, net primarily relates to gains or losses that arise in connection with the revaluation of short-term inter-company balances between our domestic and international subsidiaries. In addition, this amount includes gains or losses from foreign currency transactions, such as those resulting from the settlement of third-party accounts receivable and payables denominated in a currency other than the local currency of the entity making the payment. We exclude these gains and losses from Adjusted EBITDA and Adjusted Net Income because they result from financing decisions rather than from decisions made related to our ongoing operations and because fluctuations from period- to- period do not necessarily correspond to changes in our operating results. (e) Other non-operating (income) expense, net represents income and expense that are non-operating and whose fluctuations from period- to -period do not necessarily correspond to changes in our operating results. (f) The foreign research and development credits are the result of a comprehensive analysis we have been performing across the organization to determine whether expenditures incurred qualify as research and development as defined by the respective jurisdiction. The amounts recorded in this line item represent amounts recorded in the current period that related to a prior period. (g) Transaction-related costs primarily relate to costs incurred in connection with the March, May and November 2016 secondary offerings and receivables financing agreement. These costs include $32.0 million of non-cash stock-based compensation expense related to the vesting and release of the transfer restrictions of certain performance-based stock options and $10.1 million of stock-based compensation expense associated with the release of the transfer restrictions on a portion of service-based vested options in connection with the announcement of our March, May and November 2016 secondary offerings. In addition, we incurred $2.7 million of third-party fees associated with the secondary offerings and the closing of our accounts receivable financing agreement. (h) Acquisition-related costs primarily relate to costs incurred in connection with purchase of the assets of Value Health Solutions, Inc., the acquisition of Nextrials, Inc., and the integration cost for the Takeda joint venture, as well as costs related to other potential acquisitions to enhance our strategic objectives. (i) Lease termination expenses represent charges incurred in connection with the termination of leases at locations that are no longer being used by the Company. (j) Severance and restructuring charges represent amounts incurred in connection with the elimination of redundant positions within the organization, including positions eliminated in connection with the KKR Transaction and the acquisitions of ClinStar, RPS and CRI Lifetree. (k) We have escalating leases that require the amortization of rent expense on a straight-line basis over the life of the lease. The non-cash rent adjustment represents the difference between rent expense recorded in the consolidated statement of operations and the amount of cash actually paid. (l) Represents charges incurred that are not considered part of our core operating results. (m) Represents the tax effect of the total adjustments at our estimated effective tax rate.
News Article | February 28, 2017
Update and Q4 2016 Financial Statements and MD&A Wentworth Resources Limited, the Oslo Stock Exchange (OSE: WRL) and London Stock Exchange (AIM: WRL) listed independent, East Africa-focused oil & gas company, today announces an operational update along with its unaudited results for the fourth quarter and twelve months ended 31 December 2016. The following should be read in conjunction with the Q4 2016 Management Discussion and Analysis ("MD&A") and Condensed Consolidated Interim Financial Statements which are available on the Company's updated website at http://www.wentworthresources.com. Wentworth shall be issuing its audited 2016 Annual Consolidated Financial Statements and MD&A following publication of the results of an annual independent evaluation of the gas reserves at 31 December 2016 within the Mnazi Bay Concession in Tanzania, carried out by RPS Energy Canada Ltd. ("RPS"), Calgary, Canada which is expected during March 2017. "Fourth quarter gas sales volumes were in line with our guidance of 40 and 50 MMscf/d and we remain confident this level is achievable for 2017, as we anticipate new demand from a local cement factory and a ceramics facility. We expect a material increase in gas demand beginning in 2018 when the new Kinyerezi-I expansion and Kinyerezi-II power plants are commissioned. The Company has taken prudent steps in order to reduce administrative and overhead costs coinciding with the reduction in capital activity expected in 2017. During the quarter we have also had productive discussions with our external lenders, amending the timing of principal payments on the existing $20.0 million facility, to better align repayments with the current production profile. We are confident in the Company's ability to generate positive cashflow at the existing production levels, allowing any upside in demand during 2017 to directly benefit the bottom line." "The Company is focused on advancing a new 2D seismic acquisition program over the Tembo appraisal area in Mozambique and will be looking to secure an industry partner to share the costs and risk on the appraisal of the gas discovery." "We enter 2017 with a positive outlook and with a business which is well positioned to take full advantage of the growing gas to power energy sector in Tanzania." A conference call for investors, analysts and other interested parties will be held this morning at 01:30 MST (Calgary) / 08:30 GMT (London) / 09:30 CET (Oslo). Call in numbers: The participants will be asked for their name, company and confirmation code. The Wentworth Resources confirmation code is: 3878585. The following primary statements have been extracted from the Q4 2016 unaudited condensed consolidated financial statements which are located on the Company's website at www.wentworthresources.com. WENTWORTH RESOURCES LIMITED Unaudited Condensed Consolidated Interim Statement of Financial Position United States $000s, unless otherwise stated WENTWORTH RESOURCES LIMITED Unaudited Condensed Consolidated Interim Statement of Comprehensive Loss United States $000s, unless otherwise stated WENTWORTH RESOURCES LIMITED Unaudited Condensed Consolidated Interim Statement of Changes in Equity United States $000s, unless otherwise stated WENTWORTH RESOURCES LIMITED Unaudited Condensed Consolidated Interim Statement of Cash Flows United States $000s, unless otherwise stated Wentworth Resources is a publicly traded (OSE:WRL, AIM:WRL), independent oil & gas company with: natural gas production; exploration and appraisal opportunities; and large-scale gas monetisation initiatives, all in the Rovuma Delta Basin of coastal southern Tanzania and northern Mozambique. This press release may contain certain forward-looking information. The words "expect", "anticipate", believe", "estimate", "may", "will", "should", "intend", "forecast", "plan", and similar expressions are used to identify forward looking information. The forward-looking statements contained in this press release are based on management's beliefs, estimates and opinions on the date the statements are made in light of management's experience, current conditions and expected future development in the areas in which Wentworth is currently active and other factors management believes are appropriate in the circumstances. Wentworth undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless required by applicable law. Readers are cautioned not to place undue reliance on forward-looking information. By their nature, forward-looking statements are subject to numerous assumptions, risks and uncertainties that contribute to the possibility that the predicted outcome will not occur, including some of which are beyond Wentworth's control. These assumptions and risks include, but are not limited to: the risks associated with the oil and gas industry in general such as operational risks in exploration, development and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the imprecision of resource and reserve estimates, assumptions regarding the timing and costs relating to production and development as well as the availability and price of labour and equipment, volatility of and assumptions regarding commodity prices and exchange rates, marketing and transportation risks, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in applicable law. Additionally, there are economic, political, social and other risks inherent in carrying on business in Tanzania and Mozambique. There can be no assurance that forward-looking statements will prove to be accurate as actual results and future events could vary or differ materially from those anticipated in such statements. See Wentworth's Management's Discussion and Analysis for the year ended December 31, 2015, available on Wentworth's website, for further description of the risks and uncertainties associated with Wentworth's business. Notice Neither the Oslo Stock Exchange nor the AIM Market of the London Stock Exchange has reviewed this press release and neither accepts responsibility for the adequacy or accuracy of this press release. This information is subject of the disclosure requirements pursuant to section 5-12 of the Norwegian Securities Trading Act. This announcement contains inside information as defined in EU Regulation No. 596/2014 and is in accordance with the Company's obligations under Article 17 of that Regulation.