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FERC Staff to Measure Grid Investment Effectiveness

Posted in Electricity

The Department of Energy recently released a Quadrennial Energy Review that identified a pressing need for new electricity transmission facilities, among other infrastructure issues.  Encouraging new transmission investment has also been a decade-long priority policy goal of FERC reflected in the Energy Policy Act of 2005 and FERC’s seminal Order No. 1000.  In furtherance of this priority goal, FERC staff recently announced that it is developing quantitative metrics regarding transmission investment adequacy and the impact of FERC’s policies.

The metrics under development would help the Commission to assess the adequacy of transmission infrastructure and the effectiveness of FERC policies in achieving appropriate levels of transmission investment needed to meet reliability, economic and public policy concerns.  At the recent FERC meeting, staff described specific metrics for which adequate data are available.  The metrics fall into three broad categories.

Metrics to assess the adequacy of transmission infrastructure.  Staff will identify persistent costly line congestion as a measure of inadequate transmission investment.  One metric, to be used for facilities not under the control of a regional grid operator, will look at the number of incidents where the grid operator needed to take action to address congestion problems, weighted by the quantity of end-user, or retail, load.  For facilities under the control of a regional grid operator (Regional Transmission Operators or RTOs, and Independent System Operators, or ISOs), staff will identify persistent price differentials between locations on the grid.  This different metric is needed for RTOs and ISOs because they operate markets that place a price on congestion and thus do not rely on operator actions for congestion management such as curtailment.

Metrics to measure relative transmission investment.  Staff will develop three metrics:

  • Circuit miles of transmission added to the grid, divided by retail load.
  • Investment in new capital additions to the grid, divided by retail load.
  • Circuit miles of transmission added, divided by the associated investment dollars.  The resulting metric, circuit miles per dollar of investment, measures the effectiveness of investments.

Metrics to evaluate key goals of Order No. 1000.  Staff identified only one metric in this category: the percentage of transmission project proposals made by nonincumbent (i.e., non-utility) transmission developers.  One of the major goals of Order No. 1000 is supporting competition in transmission development.  This metric measures the participation of nonincumbent developers in regional planning processes. 

Staff indicated that it will consider whether additional metrics would be helpful.

New FERC Chairman Norman Bay told staff “This is important work that you’re doing.  The metrics presented by staff today will allow the commission and its staff to better see what works and what needs further improvement,” according to RTO Insider.

Risk and Reward in the UK Continental Shelf: Key Developments in Q1 2015

Posted in Oil & Natural Gas

Our 2014 series on risk and reward in the UK Continental Shelf (UKCS) outlined the challenges being faced by the UKCS oil and gas industry to remain competitive. A consistent theme emerging from industry stakeholders is that significant fiscal and regulatory reform is required to secure the industry’s long-term future. This post highlights key fiscal and regulatory developments during the first quarter of 2015.

2015 Budget: Welcome fiscal reforms

In the last Budget before the May 2015 general election, the UK Government announced oil and gas sector fiscal reforms, including:

  • A new “investment allowance” to simplify the existing system of offshore field allowances;
  • A reduction in Petroleum Revenue Tax from 50% to 35%; and
  • A reduction in the Supplementary Charge on company profits from 30% to 20%.

Almost simultaneously, the Office for Budget Responsibility published statistics showing that tax receipts from the UKCS were at their lowest in 40 years. The UK Government expects the measures in the Budget will encourage further investment in the UKCS, leading to over £4 billion of additional investment and a 15% increase in oil production by 2019. Oil & Gas UK — the trade association for the offshore oil and gas industry — welcomed the fiscal reforms contained in the Budget, commenting that the Government’s actions were “both sensible and far-sighted”.

Developments in the implementation of the Wood Review recommendations 

As reported in our November 2014 series, the Secretary of State for Energy & Climate Change commissioned Sir Ian Wood to conduct an independent review of offshore oil and gas recovery in the UKCS in June 2013 (the Wood Review). The Wood Review published its final report in February 2014. One of the Wood Review’s recommendations was to establish an arm’s length regulatory body with powers to implement a new strategy for maximising economic recovery from the UKCS (the MER UK Strategy).

In July 2014, as part of its response to the Wood Review, the UK Government announced that it would create the Oil and Gas Authority (the OGA). On 1 April 2015, the OGA was established as an Executive Agency and it will transition into a Government Company by summer 2016.

In March 2015, the Government published its response to the November 2014 Call for Evidence from interested parties concerning the implementation of the Wood Review recommendations. The Government’s response outlines the key regulatory powers of the OGA, which are to include:

  • The right to attend industry meetings as an observer, including meetings between operators within a joint venture and meetings between licensees.
  • Sufficient powers to gather relevant data and information from non-licensee parties captured by the MER UK Strategy.
  • A non-binding role in the resolution of disputes that relate to licence terms or that impacts, or has the potential to impact, on the MER UK Strategy. The OGA will have information-gathering powers and the ability to set timeframes for the provision of information to speed up the resolution process.
  • The power to impose sanctions where parties within the scope of the MER UK Strategy do not comply with the key powers exercised by the OGA, as well as other breaches of the MER UK Strategy and non-compliance with licence conditions. The Government has proposed a statutory limit of £1 million on individual financial penalties, with a reserve power to increase this limit to £5 million, subject to consultation and Parliamentary approval. Although the financial sanctions may be considered relatively modest, the reputational impact upon sanctioned parties is potentially significant.

The Government considers it appropriate for the oil and gas industry to pay the costs of the OGA, consistent with the user pays principle, through a combination of the existing fees and charges regime and a new levy. The Government intends for the costs falling under the levy to initially relate to Offshore Petroleum Licence holders only, and to begin collecting the levy from October 2015. A consultation on the design of the proposed levy is open from 23 March until 20 April 2015.

The Department for Energy & Climate Change is currently preparing a bill for the first session of the new Parliament in summer 2015, which will implement the measures establishing the OGA. However, this timeframe is expressly subject to the will of the new Government and necessary Parliamentary procedures. The outcome of the UK general election on 7 May 2015 could, therefore, have an impact upon the MER UK Strategy and the implementation of the OGA, as well as the UKCS’s broader outlook.

The Impact of Distributed Generation On Electric Utilities: How Big, How Likely and How Soon?

Posted in Electricity, Energy Storage, Renewables

Technological advances in distributed generation and battery storage and their consequent falling costs have the potential to significantly change the electric utility business model and regulatory policies.  While change seems likely, there are varying views on its scope, probability and timing.  Two are presented here.

One perspective is that fundamental changes in the way electricity is produced and delivered are unavoidable.  They are coming soon, and new regulatory policies and business models are needed.  These are the implications of a new report by the Rocky Mountain Institute (The Economics of Load Defection) that describes the findings of research evaluating the relative economics of taking service from the grid compared to customer-installed resources.

With increasing retail electricity prices and decreasing solar and battery costs, the report finds that the most economic scenario for electricity customers is to install combination solar-plus-battery systems and remain on the grid.  While the ultimate impact depends on how quickly customers act on the changing economics and install facilities, the solar-plus-battery systems will eventually provide the majority of customers’ electricity, according to the report.  By 2030, just fifteen years from now, grid sales erosion in the northeast U.S. could be as high as 50% for residential customers and 60% for commercial customers.

Utilities are concerned about this potential revenue erosion and are proposing policies to address it.  One concern is that part of their declining sales revenue pays for the grid.  So one suggested policy is to abolish net metering, under which customers receive a retail rate billing credit for electricity produced by their facilities above what is consumed and thus put on the grid.  Another policy is to impose a fixed charge on customers that have on-site generation to help pay for the grid.  According to the report, however, both policies will only delay the eventual loss of revenue.

The report observes that customers with solar-plus-battery systems should be able to bring value to the distribution grid by deferring upgrades and providing ancillary services and congestion relief, but realizing these benefits will require reforms on three fronts:

  • New pricing and rate structures that are locational (allowing congestion pricing or other incentives), temporal (time-of-use and real-time pricing) and attribute-based (breaking apart energy, capacity, ancillary and other service components).
  • New business models based on grid-connected customers with distributed resources (like solar and batteries) and a two-way flow of electricity on the grid (not one way from grid generators to customers).
  • New regulatory models that (1) provide fair and equal customer access to distributed resources, (2) recognize, quantify and monetize the benefits and costs of distributed resources, and (3) treat all customer equitably.

In an interview with greentechmedia, Leia Guccione, a co-author of the report, said “there is a real cost to doing nothing. . . . In the absence of more customer choices, customers will take matters into their own hands.  And that’s going to lead to sub-optimal outcomes that we see in grid defection — overinvestment and underutilized capital.”

Ken Costello of the National Regulatory Research Institute (NRRI) offers a somewhat different perspective in a recent article in Public Utilities Fortnightly (Rethinking Regulation).  Reacting to a “growing consensus” that “the U.S. electric industry will undergo major changes in the coming years,” Costello says “not so fast.”  He says that not everyone sees a radically different electric industry and some predict that change will be more gradual, and argues that regulators should be cautious and hedge their decisions to account for uncertainty.  With respect to uncertainty, in a recent NRRI paper (Utility Involvement in Distributed Generation: Regulatory Considerations) Costello describes the following challenges to the future growth of distributed generation:

  • Non-dispatchability.  An intermittent generating technology such as solar could have lower economic value than a dispatchable generating technology even with similar levelized cost.  Intermittency also requires a utility to have increasing amounts of flexible generating capacity that can be ramped up or down with solar’s intermittency.
  • Subsidies.  Federal, state, and utility incentives provide substantial impetus to solar PV systems.  In the not-too-distant future, distributed generation may have to operate without subsidies.
  • Lowering “soft” costs, i.e., customer acquisition costs, marketing, insurance, financing and contracting, permitting, interconnection and inspection, installation, labor, and O&M expenses.

That said, Costello says “[i]t seems inevitable that change will come but its effect on the electric industry is still in flux and unknown.  Both the vision of inevitable radical industry transformation and ‘not much will change’ seems extreme.”

Federal Agencies Join Forces to Procure Solar Electricity

Posted in Government Contracts

Earlier this month, the U.S. Environmental Protection Agency (“EPA”), U.S. Forest Service, Department of Energy, and General Services Administration (“GSA”) released a final solicitation for the Federal Aggregated Solar Procurement Project (“FASPP”).  Through the FASPP, these agencies seek to acquire cost-effective solar electricity at nine federal sites located throughout northern California and northern Nevada.  The solar electricity will be purchased under a firm fixed-price Power Purchase Agreement (“PPA”) with a single contractor who will design, construct, own, maintain, and operate photovoltaic systems on the agencies’ sites.

The FASPP comes in the wake of Executive Order 13693, issued by President Obama on March 19, 2015, charging agencies to reduce their “direct greenhouse gas emissions by at least 40 percent over the next decade while at the same time fostering innovation, reducing spending, and strengthening the communities in which our Federal facilities operate.”  As the EPA explained, by harnessing the economies of scale in solar installation, the agencies participating in the FASPP seek to advance this goal by purchasing 5 megawatts of solar electricity, while reducing their electricity bill by almost $1 billion.

In addition to the potential environmental and cost-saving impacts, the FASPP is noteworthy due to the collaborative nature of the procurement.  According to the GSA, combining the procurement for the nine agency sites will result in the agencies paying a lower rate for solar electricity than if it was acquired on a site-by-site basis.  This inter-agency collaboration appears to have some traction.  For instance, the GSA has stated that it hopes this model will be “replicated across the country”; and just over a year ago, the United States Coast Guard reported that it was assessing the viability of multi-agency collaboration for additional PPAs in northern California.

Although this collaborative approach to solar procurement may reduce costs to agencies and increase opportunities for contractors able to respond to the solicitation’s requirements, its long-term impact remains uncertain.  For instance, contractors who could have bid on a procurement to provide solar electricity for one or two agency sites may be unable to submit a competitive proposal that provides photovoltaic systems capable of producing 5 megawatts of electricity across nine federal sites in two states.  As a result, some interested bidders may wish to explore teaming arrangements with others in the industry to present a more competitive proposal for the FASPP contract.  The bundling of U.S. Government requirements into one procurement may also present an added layer of complexity in the financing of each project.

Bidders interested in the FASPP contract may attend a pre-proposal conference call on April 27 and participate in site visits between April 27 to May 1, 2015.  Proposals are due May 29, 2015, and contract award is expected this summer.

Transformative Power Technologies: Do We Need Regulation 2.0?

Posted in Electricity

As discussed in a previous post, new technologies — such as distributed generation, electricity storage, and digital control and communications — are making steady inroads toward transforming the traditional role of electric utilities and their relationship to customers.  The future transformed utility is sometimes referred to as “Utility 2.0.”  While integrating new technologies into the grid presents technical challenges, policy makers must focus on another challenge as well: “Regulation 2.0.”

As reported by greentechgrid (Forget Utility 2.0—the Power Sector Needs ‘Regulation of the Future’),  utility executives and regulators at a recent conference addressed some of the fundamental regulatory issues that must be addressed to foster the new utility paradigm.  “We agree today we will no longer write another report [referencing the] ‘utility of the future.  What we need now is ‘regulation of the future,'” said Lawrence Jones, vice president of utility innovations and infrastructure resilience at Alstom.

Rates are an important Regulation 2.0 issue.  For example, customers want customized services, such as different levels of reliability, and new technology allows customized services.  Of course, this means different levels of costs.  But universal service at non-discriminatory rates is a fundamental part of  regulatory policy now.  Michael Champley, a commissioner at the Hawaii Public Utilities Commission, noted that non-discriminatory rates “is a universal practice…But you can question whether it’s appropriate for regulation 2.0.”  Theodore Craver, chairman, president and CEO of Edison International said the utility industry’s non-discriminatory regulatory model is creating barriers for the integration of new technologies.

Another example is volumetric rates.  Utilities recover their costs through rates based on the amount of energy (i.e., kilowatt-hours) used.  But when customers install on-site generation, such as rooftop solar panels, energy taken from the grid goes down and so does the revenue used to cover the cost of maintaining the grid.  The impact is exacerbated where the customer sells some of its unneeded power back to the utility.  New rate designs are needed.

Adopting standards for connecting new distributed resources to the grid is another challenge for regulators.  According to the National Renewable Energy Laboratory, some distribution system components were not designed to coordinate with bidirectional power flows produced by distributed generation, such as photovoltaic solar, and could require modification of protection schemes and additional distribution equipment.  Hawaii Commissioner Champley noted that “(i)t’s great you can plug in, but it’s the rules and terms and conditions of how you play that makes the difference.”

Of course there are many other issues that policy makers need to consider as the regulatory framework is adapted.  Are there appropriate guideposts to help policymakers?

In 2013, the Advanced Energy Economy Institute (AEEI) and MIT’s Industrial Performance Center (IPC) hosted a forum to identify the barriers and opportunities for redesigning regulatory and utility revenue models to enable innovation and allow for flexibility and responsiveness to changing market conditions.  According to a summary of the conference (21st Century Electricity System CEO Forum Summary), the following five points were repeatedly emphasized throughout the discussion:

  • Regulatory and policy goals and objectives must be clearly defined and well understood before redesigning the regulatory framework.
  • Regulation must evolve to allow innovative business models to emerge and take advantage of opportunities presented by new technologies and changing customer needs.
  • Several different business models may be capable of enabling innovation in the electricity distribution sector.
  • Understanding the changing role of the utility is critical to identifying and capitalizing on the opportunities created by technological change.
  • Developing new business models for distribution utilities and technology providers requires a clear understanding of customer needs.

Regulators in New York appear to be thinking along these lines.  The New York Public Service Commission has embarked on a major restructuring of its retail electricity markets that is proceeding along two tracks.  Under the first phase, the commission adopted a comprehensive policy framework for a reformed retail electric industry that is aimed at increasing distributed energy resources and dramatically changing the role of utilities.  The reformed electric system will be driven by consumers and non-utility providers, and will be enabled by utilities acting as Distributed System Platform providers.  With the major policy and objectives now set, the second track will focus on the needed regulatory changes and ratemaking issues.

New York seems to have comprehensively addressed both Utility 2.0 and Regulation 2.0 issues in one initiative.  Other states may take a more measured approach.  Regardless of the approach, transformative technologies are here and regulatory policies need to adapt to them.

Spotlight on Manatee Conservation in Clean Power Plan Debate

Posted in EPA

As the partisan debate about the Environmental Protection Agency’s (EPA’s) Clean Power Plan continues, Chairman of the House Committee on Natural Resources Rob Bishop (R-Utah) recently suggested that the agency’s forthcoming carbon emission rules could significantly harm the West Indian Manatee, a mammal that has been listed as endangered under the Endangered Species Act since 1967.[1]

Manatees, known colloquially as sea cows, are herbivorous aquatic mammals that inhabit shallow coastal areas and rivers of the Gulf of Mexico, Caribbean Sea, and Amazon Basin.  Of the three species of manatee, the West Indian variant is perhaps most widely known domestically because it primarily makes its home in the coastal waters of the southern Atlantic Ocean from North Carolina to Florida.  Unable to tolerate prolonged exposure to water temperatures below 68 °F (20 °C), the animals make a winter migration to Florida, where according to Fish & Wildlife Service (FWS) estimates nearly two-thirds of the population congregates near the warm-water outflows of power plants rather than continue south.[2]

As we have discussed in previous posts, EPA’s plan to adopt rules regulating greenhouse gas emissions from existing coal-fired power plants this summer has garnered criticism from various quarters.[3]  Florida and North Carolina regulators recently claimed that rules for existing facilities would lead to economically devastating coal plant closures.[4]  Bishop added concerns about manatee conservation to the mix, pointing out that such closures would decrease the amount of warm water released by industry into Florida’s waterbodies, thus posing a threat to the migrating mammals.

Bishop raised the issue with FWS director Dan Ashe during a budget hearing on March 19, 2015.  He showed the Subcommittee on Federal Lands and Subcommittee on Water, Power and Oceans a photograph of wintering manatees in Tampa Electric’s Big Bend discharge canal—a state and federally designated manatee sanctuary—to illustrate that “if EPA regulations cause this primary warm-water site to close down or substantially alter its operations, then it would adversely affect the manatee.”[5]  After acknowledging that EPA and FWS have not consulted on the proposed rules, Ashe agreed that such consultation was warranted “because there is a very direct and obvious impact and relationship between that water discharge and those manatees.”[6]  FWS subsequently clarified that Ashe was referring to consultation about a power plant’s impact on the mammals, rather than consultation on EPA’s carbon emissions rules writ large.[7]

The Clean Power Plan gives states flexibility and does not preclude them from undertaking wildlife habitat mitigation efforts.  Environmentalists have noted that manatee conservation and the Clean Power Plan can therefore be pursued in concert, and that mitigation measures might involve replacing warm-water regions frequented by manatees—something that the Center for Biological Diversity points out has been contemplated for years—or encouraging the animals to continue their migration further south.[8]


[1] See, e.g., Ben Wolfgang, Republicans enlist manatee in bid to slow Obama carbon emissions regulations, Mar. 22, 2015, available at http://www.washingtontimes.com/news/2015/mar/22/republicans-enlist-manatee-in-bid-to-slow-obama-ca/.

[2] FWS, West Indian Manatee 5 Year Review, 2007, at 16, available at http://ecos.fws.gov/docs/five_year_review/doc3771.pdf.

[3] See, e.g.,Some Light Shed on FERC’s Role in EPA’s Clean Power Plan” (Mar. 2, 2015); “FERC Hears Concerns Regarding EPA Carbon Rules, But Next Steps Remain Less Than Clear” (Feb. 20, 2015); “FERC Conferences to Address Impact of EPA’s Clean Power Plan on Electricity Reliability and Markets” (Jan. 12, 2015).

[4] See Sean Cockerham, Regulators from coastal states of Florida, N.C., pan EPA climate plan, Mar. 17, 2015, available at http://www.mcclatchydc.com/2015/03/17/260061/regulators-from-coastal-states.html.

[5] Sean Cockerham, Lawmaker: Protect coal plants to help the manatees, Mar. 19, 2015, available at http://www.bradenton.com/2015/03/19/5700899_lawmaker-protect-coal-plants-to.html?rh=1.

[6] Id.

[7] Id.

[8] See Wolfgang, supra note 1.

States Announce Conservation Measures to Forestall ESA Protections for Sage-Grouse

Posted in DOI

While the federal debate over Sage-Grouse protections has stalled since the passage of the FY15 appropriations bill—which as we discussed in Sage-Grouse Rider Frustrates Conservation Efforts included a rider effectively prohibiting the United States Fish and Wildlife Service (FWS) from issuing new rules concerning the birds—the discussion continues at the state level.  In particular, Idaho and Utah recently announced new conservation measures in an attempt to demonstrate that the Greater Sage-Grouse can adequately be protected without federal safeguards pursuant to the Endangered Species Act (ESA).[1]

Mining, oil, and gas interests favored the appropriations rider because it prevents FWS from listing the Greater Sage-Grouse under ESA, a designation that would challenge industry development in Idaho, Utah, and nine other western states where the bird is indigenous.  In the absence of ESA listing, the Greater Sage-Grouse will be subject to federal protections only through the Forest Service and the Bureau of Land Management, which is still in the process of revising approximately 100 land-use plans that span millions of acres of the bird’s habitat.

On February 11, 2015, the Idaho Department of Lands (IDL) announced a plan to protect 700,000 acres of state endowment lands to “further demonstrate Idaho’s commitment to conserving sage-grouse to prevent a listing of the species under the Endangered Species Act.”[2]  The new measures would complement Idaho’s existing 2012 plan, which already covers millions of acres of Sage-Grouse habitat.  While IDL’s proposal would impose certain lease stipulations—including a half-mile buffer around the bird’s breeding areas, noise limits on drilling, and the adoption of best management practices—it would largely protect industry interests by allowing for mining, oil and gas development, and wind farm operation.[3]  IDL is currently reviewing public comments on the plan.  The state’s Land Board and Oil & Gas Conservation Commission will vote on the proposal on May 19, 2015 and May 21, 2015, respectively.

Like Idaho, Utah is ramping up conservation efforts to stave off ESA listing of the Greater Sage-Grouse which, according to Governor Gary Herbert, would “have a significantly devastating impact” on the state’s economy, particularly on farmers, ranchers, and the energy industry.[4]  On February 10, 2015, Herbert signed an Executive Order directing state agencies to coordinate implementation of the Utah Sage Grouse Conservation Plan of 2013, which mandates maintaining a minimum average population of the bird on monitored breeding grounds and protecting 10,000 acres of its habitat through incentive-based programs.  The Executive Order in in particular also directs the state’s Division of Oil, Gas and Mining to coordinate with the Division of Wildlife Resources on all regulatory actions proposed within so-called Sage-Grouse Management Areas; these areas provide habitat and breeding ground for 94% of the state’s Sage-Grouse population.

It is not yet clear if these efforts will produce the desired effect and persuade FWS to forgo listing the Greater Sage-Grouse under ESA.  Due to a settlement agreement with environmental groups, the agency has until September 2015 to make that decision.


[1] See Jodi Peterson, New state and fed efforts to protect sage grouse, Mar. 6, 2015, available at https://www.hcn.org/articles/states-struggle-to-keep-sage-grouse-off-the-endangered-list.

[2] IDL, Idaho Department of Lands outlines plan to protect sage grouse habitat, Feb. 17, 2015, available at http://www.idl.idaho.gov/news-media/2015-releases/2-17-2015-idaho-dept-lands-outlines-plan-to-protect-sage-grouse-habitat.pdf.

[3] See IDL, Proposed Greater Sage-Grouse Conservation Plan, Feb. 11, 2015, available at http://www.idl.idaho.gov/sage-grouse/draft-sage-grouse-mgmt-plan_v021115.pdf.

[4] Brett Prettyman, Utah guv directs state agencies to protect sage grouse, Feb. 10, 2015, available at http://www.sltrib.com/news/2164901-155/utah-guv-directs-state-agencies-to.

A Spotlight on Solar Power in Africa

Posted in Africa

The new year may only be a few months old, but 2015 has already ushered in a number of exciting developments in the solar power space in Sub-Saharan Africa.

Solar projects coming online across the continent and more in the pipeline. Riding the momentum of 2014 in which it brought online the largest photovoltaic (PV) plant in Africa and joined the ranks of the top ten largest markets for utility-scale solar, South Africa last week announced the opening of KaXu Solar One, the country’s first Concentrated Solar Power plant. In Rwanda, Gigawatt Global has completed the construction of the first utility-scale PV plant in the East Africa region. In West Africa, construction is underway at the Nzema solar plant in Ghana, which, with a projected capacity of 155 MW, will be one of the top ten largest PV plants in the world when completed. In addition, Nigeria has signed a Memorandum of Understanding with a South Korean firm to develop a 1 GW solar PV farm. This is the most recent of a series of new agreements to build gigawatts’ worth of utility-scale and distributed generation projects across the country. A number of other countries, including Côte d’Ivoire and Uganda, have also initiated tenders for solar projects.

Policies and programs that facilitate investment. The World Bank recently announced its Scaling Solar initiative, a “one-stop-shop” that consolidates under one window the existing services that the Bank provides its country clients. These services include technical and legal assistance, partial guarantees of private debt, political risk insurance, and competitive financing. The design of Scaling Solar draws in part upon the South African government’s success with its Renewable Energy Independent Power Producer Procurement program, which has successfully promoted competitive and rapid tenders for grid-connected renewable energy in South Africa. Both investors and communities stand to benefit from policies and programs that catalyze further competition and capital for utility-scale solar projects.

Increased attention to distributed energy solutions. With two-thirds of the region’s population not connected to the grid, off-grid solutions are as important as the utility-scale, grid-connected projects. Recognizing the critical need to develop solutions to serve these 600 million people, the IFC invested $4.5 million last month in Off Grid Electric, a “micro-solar leasing” firm that skirts the problem of high up-front installation costs of solar PV by allowing rural customers to pay incrementally for the installation over time. Innovation in financing mechanisms for off-grid solar, such as pay-as-you-go approaches and mobile payment platforms, is being pioneered by companies like M-KOPA Solar, Greenlight Planet, Azuri Technologies, Fenix International, BBOXX, and more. In addition, venture capital and private equity firms are paying increasing attention—and funding—to the off-grid space as well. In the first two months of 2015, they have invested approximately $35 million in off-grid solar tech companies—a solid start to the year, compared with the $64 million invested in all of 2014.

In light of the colossal gap in energy infrastructure in Sub-Saharan Africa, these new investments in utility-scale and distributed solar energy are an encouraging sign of the changes to come in Africa’s power sector.

The Road to Paris 2015: The EU Commits to a 40% Reduction of Greenhouse Gas Emissions as Part of its INDC to the UNFCCC COP 21

Posted in COP21 - The Road to Paris 2015

The Council of Environment Ministers of the European Union has approved the EU’s Intended Nationally Determined Contribution (“INDC”) in anticipation of the COP 21 of the UNFCCC in Paris in December 2015.  At COP 21, the UNFCCC contracting parties are expected to agree on a new international legal agreement on climate change to be implemented by 2020 that will apply to all countries and have the objective of limiting global warning below 2°C.

In line with the European Commission’s proposal, the approved INDC commits the EU and its Member States to a binding target of an at least 40% domestic reduction in greenhouse gas emissions by 2030 compared to 1990.  The commitment represents a binding, economy-wide reduction target that covers all sectors and sources of emissions in the EU.

The EU’s INDC explicitly excludes from its 40% reduction commitment any contribution from international credits, which is also in line with the Commission’s intention to exclude all international credits from the EU Emissions Trading System (“ETS”).  This in effect also means that any linkage between the EU ETS and the systems of third countries would require the EU to increase its emissions reduction above 40%.

However, due to Member States’ divergent views on how to include Land Use, Land Use Change and Forestry (“LULUCF”) in the 40% reduction binding target, the EU’s INDC merely states that a “[p]olicy on how to include [LULUCF] into the 2030 greenhouse mitigation framework will be established as soon as technical conditions allow and in any case before 2020.”  This ambiguity has been criticized by different environmental NGOs who claim that the inclusion of LULUCF offsets would lower the 40% commitment by up to 5%.

The EU’s INDC is also silent on adaptation measures and on finance for mitigation and adaptation in developing countries.

Evolving Role of Utilities: Indicators That New Power Technologies May Be Transformative

Posted in Electricity

Many forces are converging to focus the debate on the evolving role of utilities, and events and trends are being closely watched by utilities, regulators and policymakers.  Just in the last week or so, a few developments indicate that new technologies are likely to be transformative.

On the innovation front, the Pacific Northwest National Laboratory (PNNL) reported that with certain advances, fuel cells could provide power to large customer facilities like big box stores or hospitals such that they could go off the grid.  Fuel cells are a form of distributed generation in which electricity is produced by solid oxide ceramic cells that oxidize a fuel electrochemically.  PNNL concludes that natural gas fuel cells could play a significant role in meeting future energy demand if their lifespans are improved and enough systems are produced to reach economies of scale.  Larry Chick, a materials engineer at PNNL, says that “the Department of Energy’s Solid Oxide Fuel Cell program has been achieving targeted improvements over the last decade, so things are moving in the right direction.”  Improvements will lower the cost of fuel cells and hasten their adoption by customers, thereby further eroding the utility’s role as sole power provider.

On the deployment front, energy storage is reportedly poised for significant growth in the U.S.  Storage is an important complement to variable generators such as solar and wind because it provides energy when those resources cannot.  According to a report by the Energy Storage Association and GTM Research, the storage capacity forecasted to be deployed in 2015 (220 megawatts) is more than three times the 2014 total, and by 2019 annual additions are expected to be almost four times the 2015 level (860 megawatts).  Perhaps more important, 90% of storage capacity added in 2014 was on the utility side of the meter but by 2019, 45% of new storage is expected to be on the customer side of the meter.  Increased deployment of customer-side storage will mean customers can lower their demand at peak times and perhaps rely on their own renewable power resources.  Either means less need for utility income-producing investment in generation capacity.

And on the regulatory front, the New York Public Service Commission adopted a comprehensive policy framework for a reformed retail electric industry that is aimed at  increasing distributed energy resources and dramatically changing the role of utilities.  Distributed energy resources “will become integral tools in the planning, management and operation of the electric system,” placing them “on a competitive par with centralized options.”  The current retail utilities will serve as a platform to provide uniform market access to customers, distributed resources and aggregators.  In a press release, Commission Chair Audrey Zibelman said the new policy “will reorient both the electric industry and the ratemaking process toward a consumer-centered approach that harnesses new technologies and markets.”  Each New York utility must file an implementation plan by December 15, 2015.

These developments — advances in fuel cells and storage, and a new regulatory policy in a key state that significantly elevates the role of distributed resources to meet customer needs — are but the most recent indicators that new technologies are making steady inroads toward transforming the traditional role of electric utilities.