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Donnerstag, 22. Juni 2017

Nevada RPS, Community Solar Bills Vetoed; Net Metering Reinstated

Nevada RPS, Community Solar Bills Vetoed; Net Metering Reinstated

net metering
Nevada Gov. Brian Sandoval vetoed two bills last week that would have increased the state’s renewable energy standard and promoted community solar programs.
Clean energy advocates expressed their disappointment in the vetoes, but applauded Sandoval’s decision to sign a bill that will reinstate Nevada’s net metering standard and bring major solar developers, such as Tesla and Sunrun, back to the state. Sandoval signed eight other clean energy and energy efficiency bills.
Jessica Scott, interior west director for Vote Solar, said in a statement that the adoption of clean energy measures provided a model for other states to follow.
“While Governor Sandoval’s veto to increasing Nevada’s renewable energy goals is a missed opportunity to strengthen the Silver State’s leadership, the nine energy bills signed into law this year signal that Nevada will once again participate in our nation’s growing clean energy economy,” Scott said.
The net metering law restores the ability of homeowners in Nevada to be credited based on the retail rate for the energy they produce and export to the grid. The Nevada Public Utilities Commission in late 2015 issued an order that increased the fixed charges that solar customers in the state would pay over time, while also reducing credits for excess generation. Sunrun and SolarCity subsequently pulled out of Nevada’s solar market.
Following passage earlier this month of the net metering bill by Nevada legislators, Sunrun said in a June 6 statement that it “is coming back to Nevada.”
Sandoval held the bill signing at the Tesla Energy Warehouse in Las Vegas, according to the governor’s website.

The Global Transition to Renewable Energy — Can the Caribbean Lead the Way? Part 1: The Potential

The Global Transition to Renewable Energy — Can the Caribbean Lead the Way? Part 1: The Potential

 
The Caribbean depends on imported oil for approximately 90 percent of its energy needs; the exception is Trinidad and Tobago, which has its own source of oil and natural gas. Although the world currently is benefitting from a relatively low cost of oil, the production of electricity from either diesel or heavy fuel oil is still expensive in the region. The electricity prices in the Caribbean are extremely high, with an average of US$0.34 per kWh and as high as US$0.50 per kWh, which is nearly four times the price paid in the U.S. And if the pendulum swings back to higher priced oil in the years to come, this will make the cost of electricity in the Caribbean still higher.
The price of energy is a heavy burden for these countries and causes problems on a number of fronts. Spending on oil imports is a tremendous drain on the hard currency reserves of these islands and can account for up to 10 percent of their GDP. Any spikes upward in the price of oil can cause a major shock to their economies.
Island nations also are the countries most vulnerable to the devastating effects of climate change. Rising sea-levels, higher temperatures and increased natural disasters from changing weather patterns is a calamity for these islands. These are grave threats to the Caribbean even though the islands as a whole have extremely low emissions of greenhouse gases relative to larger countries, responsible for less than 1 percent of total worldwide carbon emission. The islands are not responsible for global warming, yet they face the most immediate threat from it.
Although countries in the region differ in their renewable resources, they have enough in common to discuss the promise of the region as a whole. Overall, they have enormous potential for successfully pursuing renewable energy for four principal reasons.
Dramatic Cost Savings are Possible
First, they can achieve substantial reductions in the cost of energy, which helps the households in those islands, particularly those in lower income brackets. The reduction in cost also benefits hotels and resorts, which pay a large portion of their operating costs for electricity for air conditioning and ice-making. This will help the tourism industry — which is so important in the region — to remain competitive. And, it means the countries will be paying far less of their hard currency on fuel oil. The high cost of energy is a major drag on economic growth in the Caribbean.
Small Islands as Laboratories
Second, there is growing interest in the role these islands can play as laboratories to demonstrate how various renewable energy technologies and integration plans can be deployed. They may show larger countries how a transition off fossil fuels from a regulatory, technical, financial and utility business model perspective can be achieved with the appropriate scaling.
Renewable Resources in Abundant Supply
Third, the Caribbean region has an abundance of the resources needed to produce renewable energy: sun, wind, geothermal and in limited cases hydro. At 5.46 kWh/m2, the average annual solar resource for the Caribbean is higher than the largest solar markets of Hawaii, California, Texas and Spain. And for wind, the Caribbean average of 7 m/s is equal to that of Texas and California, the two leading U.S. states for wind. There also is great geothermal potential in the Eastern Caribbean islands of Dominica, St. Kitts-Nevis, Guadeloupe, Martinique, Montserrat, St. Lucia and St. Vincent, and projects already are in various stages of development in these islands. Hydro power has less potential for the region, however, as it is limited to Haiti, Jamaica and the Dominican Republic.
Cost of Technology is Decreasing
Fourth, the cost of renewable energy technology has been declining dramatically while the efficiency of the technology has been increasing steadily. This is especially true for solar and wind energy, and increases the potential for cost savings in the Caribbean. According to New Energy Outlook, Bloomberg’s New Energy Finance 2016 annual report, this trend will continue, making these two technologies the cheapest ways of producing electricity in many countries during the 2020s.
Equally important for Caribbean islands, the cost of energy storage technology is falling significantly. Thus, it is becoming more cost effective to store low cost renewable power generated off-peak and to use it to meet peak electricity demand. This is absolutely critical for wind and solar energy to reach their full potential in the Caribbean as their intermittency challenges the stability of the electrical grid.
Islands Are Setting Aggressive Goals
Many islands have ambitious plans to transition to renewable energy. Aruba has a goal of transitioning off fossil fuels 100 percent by 2020. St. Vincent and the Grenadines plan to generate 60 percent of its electricity from renewable energy by 2020. St. Lucia seeks to reach 35 percent renewable energy penetration and to increase energy efficiency by 20 percent by 2020. Grenada plans to generate 20 percent of its electricity and transport energy from renewable energy by 2020. Barbados has a goal of generating 20 percent of its electricity from renewable energy by 2026.
NGOs are Providing Assistance
A number of non-state actors are working closely with individual islands to develop their renewable energy plans. Two NGOs are particularly active: Carbon War Room (CWR) and Rocky Mountain Institute (RMI). In 2012, the CWR formed the Ten Island Challenge to work with Caribbean islands to accelerate their transition off fossils fuels. So far, the CWR has reached agreements to work with the following countries: Aruba, Anguilla, Bahamas, Belize, British Virgin Islands, Grenada, San Andres and Providencia islands in Colombia, St. Lucia, St. Vincent, and the Grenadines and the Turks and Caicos. Since launching the Ten Island Challenge, CWR merged with RMI in 2014, and the two NGOS adopted the Challenge as their first joint program.
Another NGO increasingly active in the region is the International Renewable Energy Agency (IRENA) based in Dubai, UAE. IRENA is an inter-governmental organization that supports countries in their transition to a sustainable energy future, and serves as the principal platform for international co-operation, and a repository of knowledge on renewable energy.
IRENA’s focus is on helping small island developing states (SIDS) around the world to overcome the vulnerabilities they face from climate challenge and to help them serve as models for the rest of world through rapid renewable energy development. The goal is to enable SIDS to lead by example on climate change. To that end, IRENA established in 2014 its SIDS Lighthouse Initiative to offer a framework for small island developing states to develop a structured and sustainable approach to renewable energy.
Governments Outside the Region are Providing Support
Several governments also are actively seeking to promote renewable energy in the region, including the U.S., the UAE, and the European Union and some of its member countries, such as Germany and Spain. The UAE recently launched a $50M renewable energy fund for the Caribbean. The European Union is active in the region through its Caribbean Investment Facility (CIF), one of the EU’s regional blending facilities, mobilizes funding for development projects, including renewable energy projects. The CIF combines grants from the European Development Fund (EDF) with loans from other sources.
The U.S., of course, not only shares its “third border” with the Caribbean but it has a presence in Puerto Rico and the U.S. Virgin Islands. And its promotion of renewables in the Caribbean has taken several forms from the policy level to the practical.
More should be known about the Trump administration’s strategy for the Caribbean in June 2017, when it submits a report to Congress as required by the United States-Caribbean Strategic Engagement Act, which was signed by President Obama in December 2016. The law directed the U.S. Secretary of State and the U.S. Agency for International Development to devise a multi-year strategy on issues of concern to the region, including security, energy, diplomacy and increased access to educational opportunities.
The report is expected to address energy security in the region and to recast the issue of energy security away from a focus on fighting climate change and instead place greater emphasis on promoting a diversity of supply of energy and expanding the market opportunity for U.S. companies.
The Obama administration had been active in promoting renewable energy on the Caribbean. In May 2016, Vice President Biden chaired the U.S.-Caribbean-Central American Energy Summit in Washington, D.C., bringing together Caribbean and Central American heads of government and energy ministers, multilateral development banks, the private sector, and other international partners. On May 4, 2016, the Caribbean Community formally launched the Caribbean Sustainable Energy Roadmap and Strategy (C-SERMS) Platform as a mechanism to manage regional coordination and action on energy security.
At the policy and diplomatic level, the U.S. Government has been working with Caribbean and Central American countries to create systems that will enable more efficient use of energy at lower costs to their citizens. There is a strategic interest in this because several Caribbean countries depend on assistance from Venezuela’s Petrocaribe, a program that provides financial subsidies for the purchase of oil from Venezuela. As the economic situation deteriorates in Venezuela, Petrocaribe’s future is in doubt with the potential for causing serious disruption in the countries dependent on it. Overnight, they could be cut off and forced to buy oil in the open market, while still owing as much as $20 billion to Venezuela according to some estimates.
The Obama administration recognized the potential crisis on its third border if Petrocaribe falters. Secretary of State John Kerry stated in 2015, “[I]f Petrocaribe were to fall because of events in Venezuela or because of price and so forth, we could wind up with a serious humanitarian challenge on our — in our near neighborhood.”
By assisting these countries to move to renewable energy, the Obama administration reasoned the countries would be better protected from an over dependence on only one source of energy from an erratic supplier. Even if the Trump administration continues these efforts, however, the question remains how quickly this shift could occur, and whether in sufficient magnitude to make a meaningful impact.
The U.S. government also has taken a number of practical steps through various departments and agencies to assist countries in the region over to renewables. For example, the Department of State’s Energy Resources Bureau allocated over $2 million dollars in 2015 for the Caribbean and Central America. Among other initiatives, the Department of State’s Power Sector Program supported the Nevis Island Administration in structuring a competitive tender for geothermal resources.
The U.S. Overseas Private Investment Corporation (OPIC) is available to provide financing and political risk insurance to renewable energy projects in the Caribbean, and has made commitments to a number of wind and solar projects in Jamaica. In 2015, the U.S. created the Clean Energy Finance Facility for the Caribbean and Central America (CEFF-CCA) to encourage regional clean energy investment. The facility is providing $10 million for early-stage funding and draws on the combined resources of the U.S. Agency for International Development, State Department, OPIC, and the U.S. Trade and Development Agency. The Department of Energy also has been active, and in 2015 published Energy Transition: Islands Playbook in partnership with RMI-CWR as a planning tool for Caribbean countries.
Assessing the Challenges
The Caribbean has enormous potential for making a substantial transition to renewable energy. It has the resources of sun, wind, and in some cases geothermal and hydro. With the high cost of fossil fuel electricity generation, there is a strong business case for making the move to renewables. And several governments, development banks and NGOS are actively supporting the move. Progress is being be made, but a number of challenges must be overcome to unlock this great potential. Part 2 will address these: the lack of adequate laws and regulations, the small scale of projects that makes access to financing difficult, the threat to grid stability from intermittent energy sources, the resistance of utility companies to support a large-scale introduction of renewables, and the potential role of natural gas in delaying progress.

Patrick L. Schmidt (left) is Counsel to Hills Stern & Morley LLP, a boutique law firm representing clients in transactions in the Caribbean, Latin America, and other emerging markets.
Nick Sangermano is a Managing Director at CohnReznick Capital, a comprehensive financial advisory firm for the renewable energy and sustainability industries.

India Solar Tariffs: Part 2 — Dude, Where's My Return?

India Solar Tariffs: Part 2 — Dude, Where's My Return?

 
In part one of this article (India Solar Tariffs – Irrational or Misunderstood?), I argued that the current low solar tariffs in India are not necessarily irrational, and nor are they likely to render solar projects unviable.
I had concluded that concerns on this matter seemed overblown and appeared to stem from a misplaced perception of what solar returns needed to be due to an overestimation of risks, most probably a bias that crept in as a result of the experiences of some recent additions to thermal capacity which were fundamentally flawed at conception itself. Even when comparing operational capacity, solar pretty much has zero risk below the top line whereas risk and uncertainty with thermal continues to flow a long way down in its P&L statement. Furthermore, there also appears to be some confusion on the concept of returns itself specifically pertaining to internal rate of return (IRR), which could do with some clarification.
Return expectations for solar need to be de-linked from thermal and can be best understood from the perspective of “natural floors”
Any analysis of solar returns therefore has to be first de-linked from return expectations for thermal. Rather than chip away at a thermal derived returns benchmark, return expectations need to be assessed from the perspective of what I like to call a “natural floor,” for only if they pierce it do they really drift into irrational territory. But more about this natural floor business later, as it’s worthwhile to spend a moment on IRR first.
Pitting IRR against sponsor cost of capital or some other fixed hurdle rate is the shortest route to a portfolio of value destroying assets, missed investment opportunities, or both
IRR is really not a return figure in the classic sense. It is actually the discount rate that equates the sum of the present value of future cash flows available to the equity investor with the up-front equity investment. A high IRR on equity doesn’t necessarily mean a project merits investment, just like a low IRR on equity by itself doesn’t necessarily signal lousy economics. The decision to invest (or not) should only be taken by comparing IRR with the project’s (not sponsors) separately calculated cost of equity which is the correct hurdle rate. One should proceed with an investment only if the IRR on equity exceeds this hurdle rate, which can be the case at both high or low absolute IRR levels.
On the other hand, pitting IRR against sponsor cost of capital or some other fixed hurdle rate during the investment decision process is the shortest route to a portfolio of value destroying assets, or missed investment opportunities, or both. This is also the reason why the belief that low cost of foreign sponsor equity capital is driving down solar tariffs in India is just a red herring.
Okay, so does this at least mean that the annual cash flows available to equity investors are predictable and flat or stable? Setting aside curtailment risk for the moment surely makes the top line predictable and flat, and it may lead one to believe that zero input cost and negligible O&M expenses would result in predictable and stable cash flows to equity as well.
But the short answer to this question of stability is that while cash flows to equity are predictable, they are not necessarily flat. This is because of the interplay between cash payments to service interest and principal as well as the fact that whilst the former is tax deductible, the latter is not. And note that even in cases where accelerated depreciation benefit is being sought the project company remains exposed to c.20 percent MAT as per the Income Tax Act.
IRR is not really a return figure in the classic sense and by itself does not provide sufficient guidance on rationality of solar tariffs in the absence of an independent assessment of each project’s cost of equity
By way of example, take the case of a project loan where principal repayments are structured in the most simplistic manner as equated yearly installments. The resulting curve representing annual cash flows available to equity holders is still not flat and in fact, slopes gently upwards in the beginning, then rises steeply until it flattens out once the project loan has been repaid.
One can introduce further elements of complexity here given dividend distribution tax and mitigation of the same under an InvIT umbrella, but this opens up a whole new dimension to project loan structuring which can be addressed in a separate piece on financial optimization and modeling for solar. Suffice it to conclude at this point that absolute yearly cash flow to equity holders is very predictable but not necessarily flat, IRR is not really a return figure, and more importantly, IRR by itself does not provide sufficient guidance on rationality of solar tariffs in the absence of an independent assessment of each project’s cost of equity.
So how should one tackle cost of equity? The theoretical Capital Asset Pricing Model (CAPM) based approach certainly provides some guidance. For solar there appears to be another approach involving the “natural floors” I referred to at the outset of this article, and a good way to explore this is to take the example of a newly operational solar project with off-take by NTPC (via its wholly owned trading subsidiary NVVN).
The natural floors for equity returns for solar are yields on comparable off-taker debt commitments and cost of project debt itself, for only if returns pierce any one do they drift into irrational territory
How much should one pay for such a project, or in other words, at what implied IRR should one acquire the project? The answer to this question first requires an appreciation of what the underlying cash flows of such a project really represent. The way I view it, an equity investor is buying into nothing but a long-term commitment by NTPC to pay out predictable (but not necessarily flat) cash payments at specified intervals.
Sound’s a lot like a bond doesn’t it? And that means there is a market determined benchmark price that an investor demands for such a commitment by NTPC which further translates into an implied return expectation in the form of yield. This represents the first of the two natural floors. Only a tariff which translates to an IRR to equity below off-taker bond yield can truly be considered irrational as one would be better off just buying the bond in such a case.
There is however another natural floor above yield, and that’s the cost of project debt. An equity investment is junior to debt, and the latter also benefits from added security by way of charges over project assets. In the case of this second natural floor, only a tariff which translates into an IRR below the returns on debt would truly qualify as being irrational, as the equity investor would be better off simply lending to the project in that case.
A closer look at cost of borrowing throws up some interesting comparisons. Take the example of NTPC’s INR 2,000 cr (approx US$300 million) 5 Yr Masala Bond issue which has just listed for trade on LSE. Assuming it priced at face value results in a yield of 7.25 percent on the bond, which is markedly below SBI’s 3 Yr MCLR. And the MCLR itself is further subject to a spread; let’s say 200bps for illustrative purposes to make for all in borrowing cost in excess of 10 percent for solar project debt. As Fig 1 depicts, this results in a pretty wide gap between the off-taker going direct to the debt capital markets and the developer raising solar project debt from a bank — for essentially similar underlying risk, i.e., NTPC sticking to its commitment to pay out pre-determined amounts of money at periodic intervals.

Figure 1
The above analysis requires a few qualifications. Execution risk would need to be priced in to any analysis during the tariff bidding stage, but it is nowhere near the same league as for thermal. Return expectations also need to factor in concerns on sanctity of off-take commitments which authorities appear to be making moves to further strengthen even as this piece is being written. The question therefore is how much of a premium is required to be added on to the natural floors at the time of initial tariff bidding to address these two concerns, and in my estimation the answer is nowhere near the levels that skeptics seem to figure.
There appears room yet for tariffs to fall further as a result of streamlining in borrowing costs and benefits to be had under an InvIT umbrella
In a nutshell, higher tariffs and returns are great if one can secure them, but in a highly competitive marketplace like solar with minimal barriers to entry, outsized returns are bound to be bid away by investors who are able to recognize cash flows for what they really represent. In fact, I believe that independent of further reductions in module costs and efficiency there is room yet for solar tariffs to fall further simply as a result of streamlining in borrowing costs as depicted in Figure 1. Not to mention still even further upside which can be had under an InvIT umbrella both from a tax efficiency and structuring perspective.
In closing, it seems to me that those who continue to search for solar returns whilst donning their thermal glasses are setting themselves up to sit on the sidelines while the rest of us make a once in a generation shift in our journey on the road leading to affordable energy security for all.
This article was originally published by the author on LinkedIn and was republished with permission.

Australian Firm Issues Tender for 640 MWh of Energy Storage Services

Australian Firm Issues Tender for 640 MWh of Energy Storage Services

 
Brisbane, Australia-based Lyon Group yesterday said it is seeking interest for contracts to cover up to 640 MWh of storage capacity across Victoria, South Australia and Queensland.
The company said that the market services tender includes a new $600 million combined large-scale solar and battery storage project at Nowingi in north-west Victoria. Construction is set to begin on the Nowingi project this summer.
“Lyon is able to offer multiple services from the same battery system, and flexibility in contract size to accommodate various users,” Lyon Group Partner David Green said in a June 20 statement. “Lyon will enter into commercial contracts for real services provided by physical assets. This is not a theoretical exercise.”
The tender also includes services from the already announced Cape York solar-storage project, with a solar capacity of 55 MW and storage capacity of 20 MW/80 MWh; and the Riverland solar-storage project, with a solar capacity of 330 MW and storage capacity of 100 MW/400 MWh, according to the company’s website.
Lyon Group said that the final configuration of the projects will depend on the outcomes of the market services tender, and batteries will be provided by AES Energy Storage.
Lead image: SDG&E’s Advancion arrays. Credit: AES Energy Storage

Toronto Hydro, Ryerson Launch Pilot Project to Store Energy in Pole-mounted Compact Box

Toronto Hydro, Ryerson Launch Pilot Project to Store Energy in Pole-mounted Compact Box

 
Toronto Hydro is testing pole-mounted energy storage devices that can supplement electricity during peak hours in homes. In a pilot project, a compact white box, a little bigger than a suitcase, has been mounted about six metres up a hydro pole in the Keele St.
Recently, we’ve seen more and more utilities installing containerized batteries at substations to support grid reliability. Now, Toronto Hydro is testing an approach that would distribute smaller containerized batteries into neighborhoods. Check out this novel approach, which the utility says is a first in the world.

Flow Battery Provider Recognized with Green Chemistry Challenge Award

Flow Battery Provider Recognized with Green Chemistry Challenge Award

 
The U.S. Environmental Protection Agency (EPA) recently recognized Mukilteo, Wash.-based flow battery provider UniEnergy Technologies (UET) with a Green Chemistry Challenge Award.
The award acknowledged UET’s work in partnership with Pacific Northwest National Laboratory (PNNL) on an advanced vanadium redox flow battery, which was originally developed by PNNL and commercialized by UET.
“We congratulate those who bring innovative solutions that will help solve problems and help American businesses,” EPA Administrator Scott Pruitt said in a June 8 statement. “These innovations encourage smart and safe practices, while cutting manufacturing costs and sparking investments. Ultimately, these manufacturing processes and products spur economic growth and are safer for health and the environment.”
EPA said the battery works in a broad temperature range with one-fifth the footprint of previous flow battery technologies. In addition, the electrolyte is water-based and does not degrade, and the batteries are non-flammable and recyclable.
In April, the University of Alaska Fairbanks named UET the winner of the Microgrid Project laboratory testing award in the Alaska Center for Microgrid Technologies Commercialization industry competition. The award includes 25 dedicated lab days, consultation with staff and testing in the Power Systems Integration Lab at the UAF Alaska Center for Energy and Power. According to the university, the lab can evaluate equipment under a range of real-world scenarios and emulates the microgrids and operating conditions found in rural Alaska.
“With the accelerating deployment of microgrids globally, including in cold-weather climates, the need for long-duration and long-life energy storage solutions such as UET’s advanced vanadium flow batteries is now widely-recognized,” Russ Weed, UET’s vice president for business development and marketing, said in an April statement.
Lead image: The Alaska Center for Energy and Power’s Power Systems Integration Laboratory in Fairbanks, Alaska. Credit: University of Alaska Fairbanks

Multitalent Gewerbespeicher – 5 Wege zu wirtschaftlichem Erfolg

Multitalent Gewerbespeicher – 5 Wege zu wirtschaftlichem Erfolg

Fenecon Commercial 40-40

In Ihrer Beispielrechnung stellte die Reduktion der Netzentgelte die größte Erlösquelle dar. Kann man mit dieser Erlösquelle der atypischen Netznutzung längerfristig kalkulieren, wenn die Zeiten und Lasten jährlich von Netzbetreiber neu vorgegeben werden?
Antwort Fenecon: Die atypische Netznutzung in der starren Ausprägung wie sie aktuell ist, könnte in den nächsten Jahren geändert werden. Dann jedoch wahrscheinlich zugunsten einer flexibleren Regelung, bei der Stromspeicher durch ihre hohe Flexibilität sogar weitere Vorteile haben werden. Wichtig ist dann, dass das Energiemanagement des Speichers offen ist und entsprechend sich ändernder Anforderungen parametriert werden kann, sowie auch die Einbindung von steuerbaren Erzeugern und Verbrauchern ermöglicht wird.
Fenecon schlägt vor, sich mit dem Speicher am Markt für Primärregelenergie (PRL) zu beteiligen. Gibt es auch Chancen für Gewerbespeicher auf dem im Sekundärregelleistungsmarkt (SRL)?
Antwort Fenecon: Natürlich kann der Speicher auch in der SRL oder anderen Leistungsmärkten vermarktet werden. Dort sind derzeit jedoch die Erträge deutlich geringer als in der PRL. Unsere Philosophie ist, dass man den Speicher zur Flexibilitätsvermarktung einem spezialisierten Direktvermarkter im Rahmen einer virtuellen Kraftwerkslösung an die Hand gibt. Dieser kann dann die jeweils beste Vermarktungsform zu jedem Zeitpunkt wählen und beteiligt den Speicherbetreiber prozentual an den Erlösen. Durch die offene Softwarearchitektur der Speicher findet der Wettbewerb dann zugunsten des Speicherbetreibers unter den Direktvermarktern in Form der höchsten Beteiligungsraten ider Erträge statt.

Wäre der Speicher auch dann wirtschaftlich zu betreiben, wenn er sich nur über den Regelenergiemarkt refinanziert?
Antwort Fenecon: Sollte ein Speicher ausschließlich in der Regelleistungsbereitstellung eingesetzt werden, empfiehlt sich der Anschluss im Netz, sozusagen „vor dem Zähler“. Hier können in der reinen Regelleistungsanwendung die größten Erträge erzielt werden. Dann ist der Speicher jedoch ausschließlich von einem Geschäftsmodell abhängig, während Speichersysteme „hinter dem Zähler“ eine Vielzahl an Anwendungen erlauben und damit weniger abhängig von der Preisentwicklung einzelner Märkte und Anwendungen sind.
Könnte man Ihren Gewerbespeicher auch als Quartierspeicher für Wohneinheiten, Gewerbe, Hotel, Fitness und dergleichen auf einem Grundstück verwenden? Wie schätzen Sie das Potential für solche Lösungen ein?
Antwort Fenecon: Viele unserer Großspeicherlösungen sind auch als Quartierspeicher im Einsatz. Hier bieten die Rahmenbedingungen im Ausland jedoch gegenüber den derzeitigen deutschen Gesetzen Vorteile, da dort weniger starre Umlagen und Netzentgelte erhoben werden. Das Potenzial dieser Quartierspeicherlösungen ist sehr groß und viele unserer Partner positionieren sich bereits jetzt mit Referenzprojekten für den erwarteten lukrativen Markt.
Wie stehen Sie zum Thema Systemnetzdienstleistungen in direkter Kooperation mit den Übertragungsnetzbetreibern? Wird sich da in den nächsten fünf Jahren etwas entwickeln und ließe sich der Speicher dafür einsetzen?
Antwort Fenecon: Spätestens mit dem Atom- und dem darauffolgenden Kohleausstieg und der geringen Einsatzhäufigkeit von Gaskraftwerken sind die Übertragungsnetzbetreiber zunehmend auf Systemdienstleistungen dezentraler Flexibilitäten angewiesen. Leistungsfähige Stromspeicher mit dafür vorbereitetem Energiemanagement sind hierfür bestens geeignet und werden in den kommenden Jahren viele weitere wirtschaftliche Anwendungen im Netz anbieten können. Wir erwarten zudem auch im Verteilnetz weitere Geschäftsmodelle, angefangen von der einfachen Vermeidung des Netzausbaus, bis hin zu Blindleistungskompensation oder Schwarzstartfähigkeit, wo wir jeweils bereits spannende Pilotprojekte von Netzbetreibern begleiten durften.
Wenn ich die sieben Cent Differenz zwischen der Einspeisevergütung und dem aktuellen Strompreis nehme und mit den möglichen Zyklen sowie der Kapazität des Speichers multipliziere komme ich nur auf 638 Euro Erlös aus dem Photovoltaik-Eigenverbrauch. Sie setzen aber 17.382 Euro an. Wie kommen Sie darauf?
Antwort Fenecon:  Der beschriebene Fall ist eine neue Photovoltaik-Anlage mit Stromspeicher, bei der wir die Erlöse weitgehend dem Direktverbrauch von Solarstrom zuordnen. Die Erlöse entstehen dabei im Vergleich mit Gewerbebetrieben ohne Photovoltaik-Anlage. Im Gewerbe ist es kaum möglich, Stromspeicher ausschließlich auf Basis der Erhöhung des Eigenverbrauchs mit Rendite zu betreiben. Aus dieser Perspektive – aber auch, weil wir viele sehr wirtschaftliche weitere Anwendungen von Stromspeichern bereits realisieren durften – haben wir das 5-Säulen-Modell der Speicher-Wirtschaftlichkeit entwickelt und sowohl unsere Stromspeicher, als auch unser Energiemanagementsystem auf maximale Flexibilität in den Anwendungen entwickelt.
Wie hoch veranschlagen Sie die Betriebskosten für den Speicher im Jahr und ändern sich diese abhängig vom jeweiligen Einsatzzweck?
Antwort Fenecon: Gut dimensionierte Speicher können einen Roundtrip-Wirkungsgrad (AC-zu-AC) von bis zu 90 Prozent erreichen. Entsprechend fallen Kosten in Höhe von circa zehn Prozent der durchgesetzten Energiemenge an. Bei notstromfähigen Speichern kann die Verlustenergie auch 15 Prozent oder mehr betragen. Weiterer Stromverbrauch entsteht über den Standby-Verbrauch und bei Containerlösungen beispielsweise über die Klimaanlage und weitere Nebenverbraucher. Dagegen sind die Wartungs- und Servicekosten bei Lithium-Speichern allgemein sehr gering. Während ein einfacher, prozentualer Ansatz an der Investitionssumme wie bei Photovoltaik-Anlagen häufig nicht zielführend ist, unterstützen wir unsere Kunden in der Businessplanerstellung gerne mit Erfahrungswerten für die jeweilige Anwendung.

Technische Umsetzung

Ist das System auch für den Anschluss an die Mittelspannung zertifiziert?
Antwort Fenecon: Ja. Sowohl die 100 Kilowatt Batteriewechselrichter von REFU, als auch die 160/320/480/630 Kilowatt Wechselrichter von BYD, die wir derzeit vorrangig einsetzen, sind für den Anschluss an die Mittelspannung zertifiziert. Der Fenecon Commercial ist dagegen für den Niederspannungseinsatz vorgesehen, wurde in Abstimmung mit den zuständigen Netzbetreibern jedoch auch bereits in Projekten mit Mittelspannungsanschluss eingesetzt.
Funktioniert die Umschaltung auf Notstrom unterbrechungsfrei?
Antwort Fenecon: Die Geschwindigkeit der Umschaltung auf den Notstrombetrieb kann projektspezifisch realisiert werden. Sehr kurze bis hin zu unterbrechungsfreien Umschaltzeiten können mit der geeigneten Leistungselektronik realisiert werden. Manche Projekte setzen dabei ausschließlich auf den Stromspeicher, andere nehmen eine kleine USV-Anlage für kritische Verbraucher dazu und wieder andere erlauben eine Umschaltzeit von bis zu wenigen Sekunden.
Wie wird der Speicher bei der Lastspitzenkappung gesteuert? Welche Geräte sind notwendig?
Antwort Fenecon: In der Lastspitzenkappung wird der Netzbezug über Sensoren erfasst und durch Ausspeisung des Speichers der Restbezug dynamisch auf einen Zielwert reduziert. Das ist ähnlich zur Eigenverbrauchsanwendung, doch während dort der Zielwert die Null ist, liegt der Zielwert der Lastspitzenkappung eben entsprechend höher. Es sind keine zusätzlichen Geräte notwendig. Der Speicher kann über das Energiemanagement auch steuerbare Lasten und Erzeuger intelligent in das Gesamtsystem einbinden und damit höhere Lastreduzierungen als die eigentliche Speicherleistung erreichen.
Kann man mit konstanten 2C Laden/Entladen? Wie wirkt sich das auf die Lebensdauer der Batterie aus?
Antwort Fenecon: Während die Fenecon Commercial-Serie auf eine konstante Lade- und Entladeleistung von 1C ausgerichtet ist, können die Systeme der Fenecon Industrial Serie mit 2C be- und entladen werden. Für dauerhafte 2C-Anwendungen und schnelle Lade-/Entladeabfolgen setzen wir zur Sicherung einer langen Lebensdauer Batteriemodule mit aktiver Belüftung ein, während bei geringerer Häufigkeit der 2C-Anwendung auch die Lebensdauer der normalen Batteriemodule kaum beeinträchtigt wird. Auf Basis der Anwendungsprofile stellen wir gerne projektspezifische Batterie-Degradationskurven zur Verfügung und bieten optional entsprechende Garantie- und Servicepakete an.
Gibt es von Fenecon VDE-konforme Null-Einspeiselösungen? Bei uns ist der Hausanschluss schon mit der Photovoltaik-Volleinspeisung ausgelastet. Wir hätten aber gerne noch 100 Kilowattpeak mit 80-Kilowattstunden-Speicher für den Eigenverbrauch.
Antwort Fenecon: Für genau diese Anforderung haben wir vor sechs Jahren unsere ersten Speicher gebaut. Während sich die Verteilnetzbetreiber in der Frage der Neuinstallation von Photovoltaik-Anlagen bei bereits ausgelasteten Netzanschlüssen in den vergangenen Jahren deutlich bewegt haben, gibt es seitens des VDE oder der Bundesnetzagentur noch keine allgemeingültigen Vorgaben. Manche Verteilnetzbetreiber lassen nunmehr sogar AC-gekoppelte Anlagen mit dynamischer Nullpunktregelung mit oder ohne Speicher zu – diese technische Lösung ist jedoch immer mit dem Netzbetreiber abzustimmen. Bei der konkreten Anfrage nach 100 Kilowattpeak würden wir ein Cluster aus 2 x Commercial Hybrid 60-40-40 empfehlen. Durch die DC-Kopplung der Photovoltaik-Anlage agiert diese batteriegeführt und arbeitet nur so lange bis die Batterie voll ist. Damit kann den Netzbetreibern deren größte Sorge genommen werden, nämlich eine unkontrollierte Einspeisung und damit eine unvorhersehbare Netzbelastung im Fehlerfall von Sensoren, Leistungsreduzierung o.ä. Diese Anlagenkonfiguration wird von den meisten Verteilnetzbetreibern akzeptiert.
Die Spannung im Niederspannungsnetz und teils im Mittelspannungsnetz wird ja erhöht, was Auswirkungen auf die angeschlossenen Geräte hat. Ist die Leistungselektronik der Fenecon-Speicher in der Lage, das hinter dem Zähler (oder auch davor) wieder zu drosseln?
Antwort Fenecon: Die Spannung im Netz ist abhängig von Verbrauch und Erzeugung. Da ein Speicher in beiden Wirkweisen arbeiten kann, kann er auch zur Spannungshaltung beitragen. Zudem kann die Spannungshaltung im Netz durch aktive Blindleistungsregelung erfolgen. Falls im Kundenprojekt auch sehr kurzfristige Spannungsschwankungen auszugleichen sind, würden wir einen speziellen Umrichter einsetzen, der hierfür extrem schnell reagieren kann.

Singulus erhält Anzahlung in Millionenhöhe aus China

Singulus erhält Anzahlung in Millionenhöhe aus China


Die Singulus Technologies AG hat eine einstellige Millionen-Anzahlung erhalten. Dies sei als Teil einer im März geschlossenen Vereinbarung über die Lieferung von CIGS-Produktionsanlagen, teilte das Photovoltaik-Unternehmen aus Kahl am Main bereits am Dienstag mit. Singulus erwarte noch weitere Anzahlungen für die kommenden Wochen. Insgesamt seien Anzahlungen im Gesamtvolumen von mehr als 20 Millionen Euro vertraglich vereinbart worden.
Die Lieferung umfasst Vakuum-Kathodenzerstäubungsanlagen des Typs Vistaris sowie des Typs Tenius II für nasschemische Beschichtungsprozesse für die Herstellung von CIGS-Dünnschichtmodulen, wie Singulus im März bekanntgab. Bei dem Kunden soll es sich um die Tochtergesellschaft eines großen, börsennotierten Energieunternehmens und Produzenten von Solarmodulen aus China handeln.
Für Singulus war es ein weiterer Großauftrag aus China. Im vergangenen Sommer hatte China National Building Materials (CNBM) Maschinen für zwei CIGS-Modulfabriken bestellt. Dieser Auftrag hatte ein Volumen von 110 Millionen Euro. Den Großteil des Umsatzes und Gewinns aus dieser Bestellung kann Singulus in diesem Jahr verbuchen.

Fronius geht in Richtung 100 Prozent Autarkie im Einfamilienhaus

Fronius geht in Richtung 100 Prozent Autarkie im Einfamilienhaus


Seit 25 Jahren ist Fronius mittlerweile in der Solarbranche aktiv. In dieser Zeit hat sich viel verändert, sagt Martin Hackl, der die Division Solar Energy bei Fronius leitet. Heute ginge es nicht mehr darum, Solarstrom ins Netz einzuspeisen sondern ihn direkt selbst zu verbrauchen. Dafür müsse man den Energieverbrauch eines Hauses verstehen. Das gelte nicht nur für den Stromverbrauch sondern zum Beispiel auch für den Wärmebedarf.
Eine Lösung, die diese Ebenen miteinander verbindet, stellte Fronius auf der diesjährigen Intersolar Europe vor. Das Unternehmen bietet ein Hochvoltspeichersystem mit Hybrid-Wechselrichter an, das sowohl AC- als auch DC-seitig gekoppelt werden kann. Dieses können Betreiber mit einem Mikro-BHKW des Kooperationspartners Ökofen kombinieren, dass mit Holzpellets betrieben wird. Damit rückt die Autarkie im Einfamilienhaus in greifbare Nähe.
Weiterführende Details zu dieser Kombination von Strom- und Wärmeerzeugung erfahren Sie im Video-Interview.
Hier gelangen Sie zum Video-Interview.

Eon realisiert Solarpark in Sachsen-Anhalt

Eon realisiert Solarpark in Sachsen-Anhalt


Eon beginnt in den kommenden Tagen mit den Arbeiten an seinem Solarpark mit 7,8 Megawatt Gesamtleistung in Sachsen-Anhalt. Die Photovoltaik-Freiflächenanlage in Hassel sei die größte, die der Energiekonzern bislang in dem Bundesland errichtet habe, hieß es am Mittwoch. Der Bau sei in zwei Etappen aufgeteilt. Der erste Bauabschnitt, der die Installation von Solarmodulen mit insgesamt 4,7 Megawatt Leistung vorsehe, solle im August beendet sein. Im kommenden Jahr sei dann der Bau von weiteren 3,1 Megawatt Photovoltaik-Leistung an dem Standort geplant. Die Realisierung des Projekts in zwei Schritten liege in den verschiedenen Vergütungsmodellen begründet, die für den Solarstrom beansprucht werden, erklärte ein Eon-Sprecher auf Anfrage von pv magazine. So werde der eine Teil über die EEG-Einspeisevergütung und der andere über die Erlöse aus einem Ausschreibungszuschlag finanziert. Die beiden Photovoltaik-Anlagen seien durch eine Bahntrasse voneinander räumlich getrennt. Insgesamt werden knapp 30.000 Solarmodule von Trina Solar installiert, wie der Eon-Sprecher weiter erklärte.
Der Energiekonzern arbeite bei dem Projekt eng mit Partnern vor Ort zusammen. Eon sei zuständig für die Projektentwicklung, Anlagenplanung und auch die technische Betriebsführung nach Fertigstellung. Unweit von Hassel hat Eon im vergangenen Jahr bereits ein Photovoltaik-Projekt realisiert. Dabei waren auf den Dächern eines landwirtschaftlichen Betriebs Solarmodule mit einer Gesamtleistung von 894 Kilowatt installiert worden.
Erst in der vergangenen Woche hat Eon einen neuen Stromtarif aufgelegt. Er sieht 100 Prozent Solarenergie auch für Kunden ohne Photovoltaik-Anlage vor. Dabei verspricht Eon bis zum 30. September 2019 eine volle Preisgarantie. Für einen Zwei-Personen-Haushalt mit 2500 Kilowattstunden jährlichem Verbrauch liegt der Tarif bei 58 Euro im Monat.

Energiewende-Roadmap für das Ruhrgebiet

Energiewende-Roadmap für das Ruhrgebiet


Mit der Broschüre „Die Energiewende regional gestalten“ hat das Wuppertal Institut für Klima, Umwelt, Energie einen Fahrplan für die Energiewende im Ruhrgebiet veröffentlicht. Die Region mit seinen vielen Zentren in Nordrhein-Westfalen hat Modellcharakter und kann bei einer erfolgreichen Umsetzung der Energiewende eine Vorreiterrolle für ähnliche Räume einnehmen, wie Manfred Fischedick, Vize-Präsident des Instituts, erklärte.
Die Energiewende sei mehr als nur die Steigerung der Energieeffizienz und die verstärkte Integration erneuerbarer Energien. Dem Forschungsinstitut zufolge ist sie als ein gesellschaftlicher Transformationsprozess zu verstehen, der alle Bereiche des Lebens erfasst. Für ein Gelingen der Energiewende sei daher nur gemeinsam aus Bund, Länder, Kommune und Bürger möglich. Die am Dienstag veröffentlichte Roadmap für das Ruhrgebiet liefert dazu Politikmaßnahmen und -indikatoren in verschiedenen Handlungsfeldern sowie Hilfestellungen für die Fortführung des politischen Prozesses, die Kommunen, Stadtquartiere und die Gesamtregion einbinde.
Zentrales Thema sei dabei die Anpassung der Energieinfrastrukturen an neue technische und ökonomische Herausforderungen der Energiewende und die Steuerung der Siedlungs- und Verkehrsentwicklung in eine nachhaltige Richtung. Dabei dürfe aber nicht die Einbindung und Mitwirkung der Bürger vergessen werden, die ein unerlässlicher Bestandteil der weiteren Strategieentwicklung in der Region seien. Dem Forschungsinstitut zufolge sind es schließlich die zivilgesellschaftlichen Akteure, die den sozialen Wanden der Energiewende in den Bereichen Mobilität, Konsum und Energieeffizienz tragen.
Neben der Betonung auf die Bündelung aller Energiewende- und Klimaschutzaktivitäten bietet die Broschüre weitere Handlungsempfehlungen. Unter anderem werde die Einrichtung eines übergreifenden regionalen Energiewende-Lenkungskreises sowie eines regionalen Finanzierungs- und Innovationsfonds empfohlen. Dabei sei der erste Schritt ein Roadmapping-Prozess zu initiieren, an dem alle wichtigen Akteurinnen und Akteure der Region beteiligt werden müssen.
Die Roadmap ist ein Teil des von der Stiftung Mercator geförderten Projektes „Energiewende Ruhr“, das von 2014 bis 2017 von Wissenschaftlern des Wuppertal Instituts, des Kulturwissenschaftlichen Instituts Essen (KWI), der Technischen Universität Dortmund, des Büros Spiekermann & Wegener sowie der Bergischen Universität Wuppertal durchgeführt wurde. Neben der Broschüre gebe es zudem die Landkarte Energiewende Ruhr, eine digitale Informationsplattform mit Good-Practice-Beispielen aus der Region.

Photovoltaik-Mieterstromgesetz im Wirtschaftsausschuss diskutiert

Photovoltaik-Mieterstromgesetz im Wirtschaftsausschuss diskutiert


Am Mittwoch gab es eine öffentliche Anhörung zum Photovoltaik-Mieterstromgesetz im Wirtschaftsausschuss des Bundestages. Die geladenen Experten begrüßten nahezu einhellig das Vorhaben, äußerten jedoch auch verschiedene Kritikpunkte. In dem Entwurf ist ein Zuschlag von 2,75 bis 3,8 Cent pro Kilowattstunde vorgesehen, wenn Vermieter den auf dem Dach erzeugten Solarstrom direkt ohne Netznutzung an die Mieter verkaufen. Das Gesetz soll noch vor der Anfang Juli beginnenden Sommerpause von Bundestag und Bundesrat verabschiedet werden.
Andreas Horn von der Vereinigung Sonnenkraft Freising brauchte die Bedenken vieler Umwelt- und Erneuerbaren-Verbände auf den Punkt. Zwar sei das Ziel des Gesetzes, die Mieter an der Energiewende teilhaben zu lassen und so deren Akzeptanz zu steigern, „richtig und wichtig“. Doch werde das vorgeschlagene Gesetz „genau diese Ziele verfehlen“. „Neben einem zu geringen und kurzfristigen Förderanreiz behindern bislang Rechtsunsicherheiten und neue, aufwändige und teure Pflichten als Gesetzesfolgen die praktische Umsetzung von Mieterstromprojekten im gewünschten Umfang“, erklärte Horn. Michael Geißler von der Berliner Energieagentur (BEA) sieht „positive Ansätze in dem Entwurf. Doch es seien „eine Reihe von Bedingungen verankert, die die Inanspruchnahme vom Förderung bei der Umsetzung von Mieterstromprojekten unnötig verkomplizieren und dadurch weiterhin wirtschaftlich erschweren“. Dies bezog er etwa auf die Verengung der Förderung auf einzelne Gebäude. Thomas Engelke von der Verbraucherzentrale Bundesverband (vzbv) forderte ebenfalls in der Anhörung, dass auch „Nachbarschaftslösungen“ in das Gesetz integriert werden müssten.
Lukas Siebenkotten vom Deutschen Mieterbund und Hartmut Gaßner von der Kanzlei GGSC kritisierten, dass Mieterstrom gegenüber dem Photovoltaik-Eigenverbrauch immer noch benachteiligt sei. Gaßner bezeichnete den Entwurf in der Anhörung als „Energiewende in homöopathischen Dosen“. „Mit der grundsätzlichen Gleichstellung von Eigenverbrauch und Mieterstrom könnten die Ziele des Mieterstromgesetzes viel einfacher umgesetzt werden“, so Gaßner weiter. Siebenkotten sprach davon, dass der Entwurf „spürbar nachgebessert“ werden müsse. Dies könne allerdings auch in der kommenden Legislaturperiode erfolgen.
Marc Elxnat von der Bundesvereinigung der kommunalen Spitzenverbände verwies darauf, dass jede Förderung Mehrkosten für die Allgemeinheit verursachten. Diese würden dann zumeist von jeden getragen, die nicht direkt profitierten. Er begrüßte daher die im Entwurf vorgesehene Deckelung der Photovoltaik-Mieterstrom-Zuschüsse auf ein Jahresvolumen von 500 Megawatt. Maren Petersen vom Bundesverband der Energie- und Wasserwirtschaft (BDEW) stufte den Gesetzentwurf als „eher negativ“ ein. Es drohe nun eine „Drei-Klassen-Gesellschaft“ mit privilegierten Eigenheimbesitzer, Mietern, denen die Förderung zugutekommt, und „die weit überwiegende Mehrheit der Mieter, die nicht profitiert“ und am Ende mehr bezahlten. Dieser Kritik schloss sich auch Katherina Reiche vom Verband kommunaler Unternehmen (VKU) an. „Die Förderung von Mieterstrom führt zwangsläufig dazu, dass Verbraucher, die an der Förderung nicht teilhaben, höhere Kosten tragen“. Sie forderte in der Anhörung zudem eine grundlegende Überarbeitung des Umlagen- und Entgeltsystems, um künftig eine faire Lastenverteilung sicherzustellen.

Energy Community urges Serbia to introduce tendering scheme for renewables

Energy Community urges Serbia to introduce tendering scheme for renewables


The Energy Community finds that Serbia’s current Energy Law is not compliant, as it does not envisage a new approach for the design of the support schemes for renewable energy, noting that the old system of feed-in tariffs is not proportionate. In a letter sent to the Serbian Parliament, to which pv magazine had access, the director of the Energy Community Secretariat, Janez Kopac, has suggested a series of measures that are expected to bring Serbia closer to EU standards in terms of renewable energy development.
In the letter, the organization suggests a few fundamental changes, such as: launching the competitive tendering procedure, introducing the contract for differences for successful bidders, abandoning the status of the temporary privileged power producer, new incentive measures in the form of a premium, introducing balancing responsibility for privileged producers, and establishing a renewable energy operator.
The beneficiaries of the support scheme would be determined in a tendering process, open to all producers of electricity from renewable sources, based on clear, transparent and non-discriminatory criteria.
The competitive bidding would not apply to installations with capacity under 1 MW or demonstration projects, except for electricity from wind energy where an installed electricity capacity is of up to 6 MW or six generation units.
Introduced in 2009, the old FIT system applied to solar with rates under the program ranging from € 0.124 to € 0.146/kWh for rooftop arrays depending on system size, and €0.09/kWh for ground-mounted installations, all under a 12 year PPA, and a low quota of a mere 10 MW, whereas wind enjoyed as much as 500 MW quota.
Serbia boasts abundant lignite resources and has considerable hydro capacity, but nevertheless remains dependent on energy imports.
Earlier this year, the Energy Community warned that Serbia should renegotiate its 10-year supply deal with Russia’s Gazprom inked in 2011 in order to align it with European gas market rules. Namely, Serbia should ensure that its companies are not prohibited from selling on the gas they purchase from Gazprom  (whose annual delivery to Serbia stands at 5 billion cubic meters) to other countries, thus failing to comply with the existing competition rules.
Despite solar’s falling costs and rather high irradiation, Serbia expects to see as much as 700 MW of new coal-fired power capacity added by 2025, and 350 MW by 2020. Currently, the country gets around 50% of its electricity from one of its oldest coal power plant Kolubara, built in 1956 as one of the four facilities of the thermal power plant Nikola Tesla.
Meanwhile, Serbia’s 2020 renewable target stands at 27%, and according to the government’s energy statistics for 2017, the share should reach 18%. The bulk of this is hydro, with geothermal, biogas, wind and solar contributing less than 1%.
Established with the aim to extend the EU’s internal energy market to southeastern Europe and the Black Sea region, the Energy Community is an international organization consisting of the EU, represented by the European Commission, and the countries and the would-be member states of Albania, Bosnia and Herzegovina, the former Yugoslav Republic of Macedonia, Kosovo under UNSCR 1244/99, Moldova, Montenegro, Serbia and Ukraine – as the contracting parties.

Philippine developer MRC Allied unveils 1 GW renewable energy target

Philippine developer MRC Allied unveils 1 GW renewable energy target


MRC Allied, a leading property developer based in the Philippines, has revealed a bold ambition to install and own 1 GW of renewable energy by 2022.
The company says that “now is the perfect time” to expand into the energy sector as demand for power – particularly clean power – increases in the Philippines.
The firm hopes to build and buy its way to that 1 GW figure, and will end 2017 with at least 160 MW of solar PV capacity on its books. This solar figure is comprised of a 100 MW and a 60 MW solar plant, located in Clark Green City, Pampanga, and Nagu City, Cebu.
MRC Allied will pursue the bulk of its clean energy objectives through its subsidiary Menlo Renewable Energy Corp, as well as other affiliates – which include Bases Conversion and Development Authority (BCDA) and Sunray Power.
Funding for MRC Allied’s renewable energy ambitions will be raised via strategic partnerships and other financial mechanism’s, the company’s president Gladys N. Nalda said. “We will aggressively explore all available options to raise capital and finance our RE projects.”

Ingeteam supplies inverters for 100 MW project in Australia

Ingeteam supplies inverters for 100 MW project in Australia


Ingeteam supplied its INGECON SUN PowerMax B Series central inverters, which come in sets of three in a 40-foot container. The 4.8 MW systems also include a power transformer, low-voltage switchgear, medium-voltage switchgear and an auxiliary services panel.
Downer EDI is handling EPC duties for the project, which is still under construction. All electricity will be fed into Origin Energy’s regional grid network, according to an online statement. The Sydney-based utility signed a 13-year PPA for the Clare project in May 2016.
Ingeteam has already supplied roughly 46 GW of inverters for renewables projects throughout the world. It currently claims a renewables O&M portfolio of about 10 GW. 
Madrid-based Fotowatio Renewable Ventures expects to complete the Clare project by the end of this year. The array will be the Spanish developer’s third large-scale PV project in Australia. In 2014, it completed a 24 MW array near Royalla, New South Wales. And in early 2016, it signed a 15-year PPA with Origin Energy for a 56 MW installation in Moree, New South Wales.
More recently, Fotowatio Renewable Ventures won an auction last October for a 300 MW project in Mexico, with a bid of $26.99/MWh. And in May of this year, it started building 133.4 MW of solar capacity at two site in Jordan.

Foresight Group acquires 35 MW storage system in UK

Foresight Group acquires 35 MW storage system in UK


Foresight Group, an independent infrastructure and private equity investment manager that owns the Foresight Solar Fund, has acquired the 35 MW Port of Tyne battery storage project from Renewable Energy Systems (RES).
The lithium-ion battery project is one of the largest of its kind in the U.K., and is particularly attractive for Foresight Group because it has in place a 12-year capacity market contract and a four-year enhanced frequency response (EFR) contract.
The installation is poised to be commissioned in early 2018, and will serve to offer frequency response and balancing services to the National Grid, enabling greater flexibility and more low-carbon power generation on the country’s energy network.
RES is developing and constructing the project, while Foresight’s investment augments its clean energy footprint, which includes more than 80 solar PV plants in the U.K. alone. Combined with the Group’s Energy from Waste projects, Foresight can boast more than 1 GW of clean power capacity in the country.
“The acquisition consolidates Foresight’s position as a leader in investing both in renewable energy generation and the flexible grid infrastructure required to accommodate increasing penetration of renewables, such as energy storage,” said Foresight partner Dan Wells.
RES MD Rachel Ruffle added that energy storage has a crucial role to play in helping the U.K. transition to a more flexible electricity network – a network that in turn will help support economic growth and usher in a more low-carbon future. “As a leader in the energy storage market RES prides itself in delivering projects that meet the needs of our clients and society. RES is proud to be working with Foresight, as it expands its infrastructure investments into energy storage. We look forward to building and operating a successful storage project at the Port of Tyne,” Ruffle concluded.

AGL Energy to raise FITs by 77% to 140% in Australia

AGL Energy to raise FITs by 77% to 140% in Australia


It said the revised retail feed-in tariff (FIT) rates will help to soften the impact of rising energy prices in some Australian states and save money for households that have installed solar modules. AGL, EnergyAustralia and Origin Energy all recently revealed that retail electricity and gas prices will rise sharply from the beginning of July.
“We estimate the increases in feed-in tariffs could be worth up to A$3,321 ($2,512) per year in extra savings for some customers, depending on which state they live in and the amount of solar energy they generate and export to the grid,” said Sandra de Castro, general manager of sales and marketing for AGL.
FiT rates for residential customers in Queensland, New South Wales (NSW), Victoria and South Australia will increase by between 77% and 140%. New tariffs will range from A$0.11 cents to $A0.16 per kWh, up from between A$0.05 and A$0.07. The revised rates are set to go into effect from July 1 July.
AGL is introducing the new rates in response to increases in wholesale market prices and higher residential electricity costs, particularly in New South Wales, Queensland and South Australia. The FIT in New South Wales will jump 82% to A$0.11/kWh and by 77% to nearly A$0.11/kWh in Queensland. However, rates will jump the most in South Australia — up 140% to A$0.16/kWh — and in Victoria, up 126% to A$0.11/kWh. The increase in Victoria is in line with requirements set by the Essential Services Commission, which is the state’s economic regulator.
In 2015, AGL completed a 53 MW solar array in Broken Hill, New South Wales. It also owns a 102 MW project in the state, near the town of Nyngan. And in March of this year, the company switched on a “virtual power plant” near Adelaide. With that project, it now centrally controls about 7 MWh of aggregated residential battery capacity backed by solar.

UGE secures $15 contract to install 9 MW in Ontario

UGE secures $15 contract to install 9 MW in Ontario


Canada-based renewable energy company UGE International Ltd. has bagged a contract to install 15 PV power systems with a combined capacity of 9 MW in Peterborough, Ontario, Canada.
The company will build the projects for Peterborough Solar Projects Corporation (PSPC), a joint venture between the local power provider Peterborough Utilities Inc. (PUI) and the City of Peterborough.
The contract, whose value is estimated at around 20 million CAD ($15.1 million), is pending signature this summer, although it was already approved by the City of Peterborough’s Committee of the Whole. All projects will be completed and installed in the nine to twelve months following contract signing, said the company in its press release.
Prior to this new contract, UGE had been selected by PSPC to build a 500 kW ground-mounted PV plant through a tender.
One week earlier, UGE announced it has taken full control of its unit Carmanah Technologies Inc., and that it has secured a contract to build a 17 MW ground-mounted solar plant near Calgary.
In early June, the company was also contracted by Ontario’s Potentia Renewables Inc. to design and install three new solar projects with a combined capacity of 700 kW.

Abu Dhabi releases safety standards for PV under net metering

Abu Dhabi releases safety standards for PV under net metering


The Abu Dhabi Quality and Conformity Council, QCC has released new safety standards for solar power systems. According to the UAE press agency WAM, the Small-Scale Solar PV Systems Conformity Assessment Scheme is expected to boost development of distributed generation under net metering and, at the same time, to ensure quality, safety and sustainability performance of PV installations.
The QCC said the new standards will help installers and manufacturers of PV products comply with the Regulatory & Supervision Bureau’s Electricity Wiring Regulations and with the Small-Scale Solar Photovoltaic Energy-Netting Regulation, which is the net metering scheme that the city government introduced in January 2017.
The executive director of conformity scheme services at QCC, Abdullah Hassan Al Muaini, said that the new scheme is responding to the industry’s need by identifying the key specifications of products, aligning international testing and control standards, and connecting the market’s stakeholders with the authorities’ requirements.
When Abu Dhabi’s government issued the net metering scheme it said that a knowledge scheme had to be developed and incorporated as an additional requirement for qualification and certification of PV integrators within the first year of the date of the regulations.
The net metering scheme is open to solar power generators not exceeding 5 MW in size that are connected to the low voltage distribution network.
The owner of a PV system must obtain the necessary municipal permits prior to grid-connection of the small-scale solar PV installation. Furthermore, all projects must be approved by the Abu Dhabi’s Regulation & Supervision Bureau.
Surplus electricity generated from the small-scale PV systems under the scheme is delivered to the local grid. Surplus power is carried forward indefinitely from one billing cycle to the next, without any limitation of time or quantity and shall only be offset against future electricity consumption under a service point. The owner of a solar installation under net metering is not entitled to any monetary compensation.

Silicon Ranch to build 200 MW-AC of solar in the United States

Silicon Ranch to build 200 MW-AC of solar in the United States


Georgia is a late comer to the solar game, but the U.S. state has arrived in a big way. After being forced to engage by pro-solar Republicans on the state’s utility commission, Georgia Power began commissioning hundreds of megawatts of solar, which brought the state into the top 10 of solar markets as early as 2013, and Georgia was the third-largest market last year with over 1 GW installed.
However, Georgia’s rural electric cooperatives are also getting in on the game. As early as 2001 a group of cooperatives got together to form Green Power EMC, a company to buy power from renewable energy facilities, which back them was largely biomass and hydro.
Today Green Power EMC announced that it has struck a deal with Silicon Ranch for the developer to build four PV plants totaling 200 MW-AC to supply cheap power to 38 of its member cooperatives. Silicon Ranch will develop, fund, build own and operate the projects, and Green Power EMC will buy all the power they generate.
The timeline for these projects is not exactly ambitious, as they are not expected online until 2020. However, the partnership between Green Power EMC has already put online 72 MW-AC of solar in two projects in Jeff Davis County.
This strategy of co-ops banding together to procure power is nothing new, however Silicon Ranch says that it brings significant benefits. “Green Power EMC has developed a procurement strategy that allows its member co-ops to capture tremendous value,” says Silicon Ranch President and CEO Matt Kisber. “By banding together, they are able to leverage economies of scale, resulting in an extremely low cost of energy for their members.”
As a result of the success of this strategy, the Smart Electric Power Association (SEPA) named Green Power EMC its 2016 Electric Cooperative Utility of the Year last September. Additionally Green Power EMC member Cobb EMC placed 8th in the nation among utilities for installed solar capacity on a per-capita basis, with 639 MW of solar per customer.