Is electricity goods or services?  That seemingly simple yet confounding question is illustrated by three recent bankruptcy cases (all of which consider whether an electricity provider is entitled to an administrative expense priority under Bankruptcy Code Section 503(b)(9) for “the value of goods received by the debtor” in the ordinary course within 20 days prior to the automatic stay):

  • In Hudson Energy Services, LLC v. Great Atlantic & Pacific Tea Co, Inc., 2013 WL 5212141 (S.D.N.Y. Sept. 16, 2013) (A&P), the court held that because electricity is consumed only after it is measured (at the customer’s meter), electricity is a “thing that is movable at the time of identification” (UCC 2-105) and accordingly should be characterized as goods under the UCC, which is the reference standard for Section 503(b)(9).
  • The bankruptcy court in In re NE OPCO, Inc., 501 B.R. 233 (Bankr. D. Del. 2013), agreed with A&P that the meaning of goods under Section 503(b)(9) “is primarily informed by the meaning of goods under the UCC,” but disagreed with A&P  that electricity is goods, holding that because “the period between identification and consumption must be meaningful,” the “infinitesimal delay” between those acts in the case of electricity makes it unidentifiable and thus not goods.
  • In contrast to A&P and OPCO, the lower bankruptcy court in Puerto Rico Electric Power Authority v. Rentas, B.A.P. 1st Cir. No. PR 13-050 (Sept. 23, 2014) (PREPA), rejected the UCC definition as controlling § 503(b)(9) and relied instead on the public utility’s monopoly status as the basis for denying the administrative expense priority.  The First Circuit Bankruptcy Appellate Panel rejected that reasoning and remanded with instructions to determine whether furnishing electricity is goods, but declined to instruct the lower court to use the UCC definition (with the exception of PREPA, nearly all bankruptcy courts have agreed that the UCC controls the §503(b)(9) definition of “goods”).

This lack of agreement on a seemingly elementary question is not confined to bankruptcy — it existed before Section 503(b)(9) was enacted (2005) and continues.  Courts peering into the sub-atomic qualities of electricity have reached opposite conclusions whether electricity is goods or services.  Other courts have gone the opposite direction, eschewing quantum physics and comparing the “common understanding of electricity” (which is to say the common misconception that an electricity customer is buying a “stream of electrons”) to severed oil, gas and other things that are UCC goods in hopes of finding the UCC equivalent of a “unified field theory” (as in physics, that search continues).  Still other courts have concluded that electricity in “its raw state” is a service, but when it passes the end user’s meter it becomes goods.

This leaves lawyers with the quandary of identifying (a) which state’s laws do or should apply to the power purchase transaction (keeping in mind that not always will the forum court enforce a contractual choice of law if that foreign state’s substantive law fails to bear a reasonable relationship to the transaction) and (b) whether that state’s laws will treat the power purchase agreement as a contract for sale of goods or as a services contract.  Then, the power purchase counterparties must presciently evaluate which permutation of outcomes (UCC goods or common law services) will most likely benefit their respective positions. Resolution of the goods-versus-services issue can lead to different construction of a contract for the sale of electricity in at least five respects:

  • Contract formation—common law requires mirror acceptance, while the UCC permits additional terms to be added by acceptance;
  • Contract administration—common law seldom recognizes modification of an existing contract without new consideration, while the UCC foregoes the need for new consideration;
  • Contract interpretation—common law only sometimes admits trade practices and the parties’ past conduct to interpret terms, while the UCC always admits such evidence;
  • Contract enforcement—common law can require impossibility to excuse performance, while the UCC recognizes the lesser standard of commercial impracticability; common law does not always recognize anticipatory repudiation or the right to demand adequate assurances, while the UCC recognizes both; and
  • Contract rights and remedies—common law statutes of limitations for breach of contract often differ from the UCC’s four-year statute of limitations; common law does not generally recognize cover, while the UCC requires cover.

Even if electricity is initially characterized as goods, when electricity is bundled with services (such as transmission/distribution services), yet another issue arises: should the predominant factor test be applied to assess whether the provision of electricity is predominantly goods or services, or should the apportionment test apply as it did in the OPCO case, which treated natural gas deliveries as goods entitled to the administrative expense priority and electricity deliveries as services not so entitled.  Further, even if the parties to a power transaction can agree on the substantive law to be applied — UCC or common law — their agreement must clearly identify that choice as the court held in Lockheed Electronics Company, Inc. v. Keronix, Inc., 114 Cal. App.3d 304 (1981).

The energy reforms in Mexico have generated significant interest from energy investors around the world. McDermott has created a new LinkedIn Group, McDermott Discussion Group: Mexico’s Energy Reforms, to discuss legislative developments and their impacts on the changing energy private investment climate. Members of our team are well studied in these reforms and we will be posting updates on legislative developments and market updates. We encourage group member discussion and comments as well. Group participants stand to gain insight from our lawyers who are studying the reforms, from their peers who are also considering opportunities in Mexico, and from Mexican government officials who are tasked with executing the reforms.  The impact of the reforms will be felt across the board, covering the oil, gas and power sectors.

Click here to join our group. If you have any questions or technical issues, please contact Taylor Shekarabi.

Primary regulators of energy transactions, the Federal Energy Regulatory and Commodity Futures Trading Commissions (FERC, CFTC or jointly Participating Agencies) began the new year by entering on January 2 two overdue Memoranda of Understanding (MOU), one on overlapping jurisdictions, the other on sharing of information generated in connection with market surveillance and investigations into suspected market manipulation, fraud or abuse.  Both MOUs became effective immediately.

FERC, with jurisdiction over physical natural gas and power transactions, and the CFTC, with jurisdiction over financially settled products such as energy futures and swaps, had battled in recent years over the reach of each other’s jurisdiction, culminating in a March 2013 decision of the U.S. Court of Appeals for the D.C. Circuit finding that FERC improperly invaded CFTC’s jurisdiction when, under authority of the Energy Policy Act of 2005, it sought to fine Amaranth Advisors trader Brian Hunter for allegedly manipulating  natural gas futures in order to increase the profitability of corresponding physical natural gas transactions.  When the Participating Agencies failed to meet the 2011 deadline of the Dodd-Frank Wall Street Reform Act for reaching the jurisdictional understanding, a troika of western-state senators with energy committee portfolios – Dianne Feinstein (D-CA), Ron Wyden (D-OR) and Lisa Murkowski (R-AK) – expressed concern and called on the two commissions to expedite action on an MOU.

The MOUs put in place procedures that replace a reactive status quo ante in which the two agencies collaborated and shared information, if at all, only upon the request of one or the other, with a proactive framework that obliges the staffs of both agencies to notify each other of requests from within their regulated community for authorizations or exemptions from authorization requirements that may implicate the other’s regulatory responsibilities.  Once so notified, the Notified Agency must promptly inform the Notifying Agency that it (1) has no interest, (2) has an interest, triggering a consultative process between the staffs of the Participating Agencies, or (3) wants to revisit the issue once a regulated company has filed request for an authorization or exemption or the Notifying Agency has instigated sua sponte an authorization or exemption.  If (2) is selected, then the triggered consultative process will seek to determine whether the CFTC has jurisdiction under the Commodity Exchange Act or FERC has jurisdiction under the Federal Power, Natural Gas or Natural Gas Policy Acts, with disputes elevated from staff to directors and ultimately to the respective commissioners.  While the jurisdictional MOU imposes these obligations on the Participating Agencies, it expressly creates no private right of action that could be enforced by a regulated company or other third party.

The MOU on information sharing obligates the Participating Agencies to share information needed in connection with each other’s market surveillance or investigations into suspected manipulation, fraud or market power abuse in markets that the requesting Participating Agency regulates.  FERC is authorized to seek from the CFTC information from (1) designated contract markets, (2) registered swap execution facilities, (3) registered derivatives clearing organizations, (4) boards of trade and (5) market participants.  The CFTC, on the other hand, is authorized to seek from FERC information from (1) regional transmission organizations or independent system operators, (2) the North American Electric Reliability Corporation, (3) interstate natural gas pipelines and storage facility operators, and (4) market participants.  Specific provisions of the MOU obligate both Participating Agencies to take all actions reasonably necessary to preserve, protect and maintain privileges and claims of confidentiality for non-public information.  Sharing information pursuant to the MOU expressly does not constitute a waiver of any privilege or protection attached to the shared information.

by Jacob Hollinger and Bethany Hatef

The U.S. Environmental Protection Agency (EPA) has issued a proposed rule concerning carbon dioxide (CO2) emissions from new coal-fired and natural gas-fired power plants. The September 20 proposal meets a deadline set by President Obama in a June 25 Presidential Memorandum and keeps EPA on track to meet the President’s June 2015 deadline for regulating emissions from existing power plants. Once the September 20 proposed rule is published in the Federal Register, interested parties will have 60 days to comment on it. 

Under EPA’s September 20 proposal, which replaces an earlier, April 2012 proposal, new coal plants would be limited to 1,100 pounds of CO2 emissions per megawatt-hour (lbs/MWh) of electricity produced, with compliance measured on a 12-operating month rolling average basis.  The proposed rule would also require new small natural gas plants to meet a 1,100 lbs/MWh emission limit, while requiring larger, more efficient natural gas units to meet a limit of 1,000 lbs/MWh. 

EPA is required to set emission limits for new plants at a level that reflects use of the “best system of emission reduction” (BSER) that it determines has been “adequately demonstrated.”  For coal, EPA has determined that the BSER is installation of carbon capture and sequestration (CCS) technology that captures some of the CO2 released by burning coal.  In essence, EPA is saying partial CCS is the BSER for new coal plants. But for gas, EPA is saying that the BSER is a modern, efficient, combined cycle plant.  Thus, CCS is not required for new gas plants.

An important feature of the proposed rule is the definition of a “new” plant. Under the pertinent section of the Clean Air Act (CAA), a “new” plant is one for which construction commences after publication of a proposed rule. EPA’s regulations, in turn, define “construction” as the “fabrication, erection, or installation of an affected facility,” and define “commenced” as undertaking “a continuous program of construction” or entering “into a contractual obligation to undertake and complete, within a reasonable time, a continuous program of construction.” 

EPA has concluded that its new proposal will have “negligible” benefits and costs – it won’t reduce CO2 emissions and it won’t raise the cost of electricity. This is based on EPA’s conclusion that even in the absence of the new proposed rule, all foreseeable new fossil fuel plants will be either modern, efficient combined cycle natural gas plants or coal plants that have CCS. In essence, EPA is proposing emission limits that it thinks would be met even in the absence of new regulations.

But if the rule won’t reduce CO2 emissions, why issue it?  First, EPA is of the view that it is required by the CAA to issue the rule; having already determined that CO2 emissions are endangering public health and welfare, EPA is required by § 111(b) of the CAA to publish regulations to address those emissions.  Second, EPA thinks the rule will provide regulatory certainty about what is expected of new plants.  Third, and perhaps most importantly, the rule setting performance standards for new plants is a necessary prerequisite to regulating CO2 emissions from existing plants.

by Caroline Lindsey

The Department of Energy and Climate Change (DECC) in the United Kingdom published its response to its “Consultation on proposals to enhance the sustainability criteria for the use of biomass feedstocks under the Renewables Obligation (RO)” on 22 August 2013 (the Response). The original consultation was published on 7 September 2012.

In the Response, the UK Government confirms that it will proceed with its proposals to revise the content and significance of the sustainability criteria applicable to the use of solid biomass and biogas feedstocks for electricity generation under the Renewables Obligation (RO). The RO is currently the principal regime for incentivising the development of large-scale renewable electricity generation in the United Kingdom. Eligible electricity generators receive renewables obligation certificates (ROCs) for each megawatt hour (MWh) of renewable source electricity that they generate. Biomass qualifies as renewable source electricity, subject to some conditions.

Changes to the criteria

The sustainability criteria associated with the RO is broadly divided into greenhouse gas (GHG) lifecycle criteria, land use criteria and profiling criteria. There will be changes to all of the criteria, but the significant changes relate to the first two criteria, and will take effect from 1 April 2014.

In general terms, the GHG lifecycle criteria are designed to ensure that each delivery of biomass results in a minimum GHG emissions saving, when compared to the use of fossil fuel. The savings are measured in kilograms (kg) of carbon dioxide equivalent (CO2eq) per MWh over the lifecycle of the consignment (sometimes referred to as “field or forest to flame”). The UK Government has confirmed that all generating plants using solid biomass and / or biogas (including dedicated, co-firing or converted plants and new and existing plants) will be on the same GHG emissions trajectory from 1 April 2020 (200 kg CO2eq per MWh). In the meantime, new dedicated biomass power will be placed on an accelerated GHG emissions trajectory (240kg CO2eq per MWh). All other biomass power will remain on the standard GHG emissions trajectory (285kg CO2eq per MWh) until 1 April 2020.

Changes to the land use criteria will also be introduced. In particular, generating plants using feedstocks which are virgin wood or made from virgin wood will need to meet new sustainable forest management criteria based on the UK Government’s timber procurement policy principles.

The land use criteria set out in the European Union (EU) Renewable Energy Directive 2009 (RED) will continue to apply to the use of all other solid biomass and biogas, with some specific variations for energy crops. As is the current position, the land use criteria will not apply to the use of biomass waste or feedstocks wholly derived from waste, animal manure or slurry.

The new sustainability criteria will be fixed until 1 April 2027, except if the EU mandates or recommends specific changes to the sustainability criteria for solid biomass, biogas or bioliquids, or if changes are otherwise required by EU or international regulation.

Making compliance mandatory

Currently, whilst generators using solid biomass and / or biogas have to report on their compliance with the sustainability criteria, their compliance with such criteria is not linked to their eligibility for ROCs. This will change, on a phased basis.

Specifically, from 1 April 2014, all generating plants with an output of 1MW and above using solid biomass and / or biogas (except landfill gas or sewage gas) will be required to submit an annual independent audit report, which assesses their compliance with the sustainability criteria, in addition to or as part of their sustainability report.

From April 2015, this category of plants will have to meet the sustainability criteria to be eligible for ROCs. This is already the case for generating plants using bioliquids, consistent with the RED. The introduction of the mandatory requirement in 2015 is subject to the UK Government complying with its obligation to notify the sustainability criteria under the EU Technical Standards Directive.

When introduced, the changes outlined in the Response will impose what is expected to be the most stringent controls on the use of solid and gaseous biomass for energy in the world.

To view the full text of The Response click here.

by Thomas Morgan and David McDonnell 

A warning from the UK’s energy regulator, Ofgem, on 27 June 2013, that the ‘buffer’ capacity of spare electricity on the UK’s national power grid could drop to as little as 2% of national supplies by 2015, has raised concerns in relation to the possibility of widespread disruptions in service. This spare capacity currently stands at about 4%.

The warning was linked to an extensive Electricity Capacity Assessment Report, also published by Ofgem that same day. Revised studies have indicated that power supplies will shrink considerably by 2015, as electricity demand in the United Kingdom is not decreasing in the manner previously foreseen by successive governments. This is due to a variety of factors, among them, the low uptake by residential households of environmentally friendly incentives and energy-efficient practices.

Ofgem recommends the implementation of far-reaching market changes proposed by the Department of Energy and Climate Change (DECC). Among other things, DECC stated in a report, also published on 27 June 2013, that the UK electricity sector will require approximately £110 billion of capital investment in the next decade to modernise its infrastructure. This would create opportunities for investment which a range of market players are likely to monitor with interest.

DECC has also emphasised the need for a ‘Capacity Market’ – essentially an insurance policy against the possibility of future blackouts – which would work by providing financial incentives to generators to keep a certain percentage of energy capacity in reserve to cope with spikes in demand.

The British government has been quick to retort to concerns of service disruption, downplaying the risk of blackouts to domestic consumers and, while it is unlikely that blackouts reminiscent of those experienced in the United Kingdom in the 1970s will be relived, the very publication of a formal warning from Ofgem highlights the potential significance of the concern.

by Dan Watkiss

In a July 16 order, the Federal Energy Regulatory Commission (FERC) assessed civil penalties of $453 million against a British banking conglomerate (BCL) and four of its power traders for manipulating western electricity markets from from November 2006 to December 2008 in violation of the Federal Power Act (FPA) and Commission regulation 1c.2.  The bank has 30 days to pay its $435 million penalty and disgorge $34.9 million in profits plus interest from its manipulative trades; likewise, the traders have 30 days to pay penalties ranging from $1 million to $15 million each.  The bank announced that it will not pay and instead will contest the finding of market manipulation in federal court.  The penalties are among the highest FERC has ever assessed under the authority Congress conferred on it in 2005 to police market manipulation.

FERC’s Office of Enforcement launched its investigation of BCL in July 2007, culminating in an October 2012 FERC order directing the bank and its traders to show cause why they should not be found guilty of market manipulation and assessed penalties.  Following the investigation, FERC concluded that the bank and traders traded fixed price products not to profit from the relationship between the market fundamentals of supply and demand, but rather to move the daily Index Price in favor of BCL’s long or short financial swap positions at the four most liquid western trading locations:  Mid-Columbia, Palo Verde, North Path 15 and South Path 15. According to FERC’s July 16 order, Enforcement Staff’s investigation unearthed a trove of communications among the BCL’s traders describing the allegedly manipulative scheme and affirming their intent to effectuate it, including so-called “speaking” documents in which traders describe their efforts “to drive price,” “move” the Index and “protect” their swap positions.

As amended to include an anti-manipulation rule modeled on the Securities and Exchange Commission’s Rule 10b-5, the Federal Power Act and FERC’s implementing regulations prohibit an entity from: (1) using a fraudulent device, scheme or artifice to defraud or to engage in a course of business that operates as a fraud or deceit; (2) with the requisite intent; (3) in connection with the purchase, sale or transmission of electric energy subject to the jurisdiction of the Commission.  The Act also empowers FERC to assess a civil penalty of up to $1 million per day, per violation against any person who violates Part II of the FPA (including section 222 of the FPA) or any rule or order thereunder.  As it has in other prosecutions for market manipulation, FERC rejected BCL’s defense that “open market” trading is per se not manipulative.

The July 16 order is noteworthy not only for the amount of penalties FERC assessed, but also for the procedural history of the BCL investigation.  The bank and traders chose to forego their right to an evidentiary hearing before a FERC judge and instead had the Office of Enforcement’s proposed findings of manipulation submitted directly to the Commission for its determination.  The bank’s and traders’ claims that the statute of limitations had run or that Enforcement Staff was equitably estopped from making its allegations were not successful in convincing the government to drop the charges against them.

FERC must now seek to enforce its decision and collect the penalties and disgorgement in federal court.

by Melissa Dorn

The California Public Utilities Commission (CPUC) recently released a proposal that would require the major investor-owned utilities (IOUs) in the state to procure approximately 1.3 gigawatts (GWs) of energy storage by 2020.  Consistent with state’s energy storage bill, Assembly Bill 2514, which passed in 2010, the CPUC’s proposal aims to reduce market barriers and incentivize development of viable, cost-effective energy storage methods.  The CPUC hopes that the rapid growth of energy storage in California will support the state’s renewable energy industry as the state seeks to meet the legislature’s mandate to have one third of California’s energy generated from renewable sources by 2020.  Many renewable energy sources are intermittent, making energy storage technologies important for the integration of a large quantity of renewable energy into the existing electric system.

Central to the CPUC’s proposal are biannual procurement targets for the three major IOUs, Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric. The CPUC’s proposed aggregate procurement targets for each IOU are divided into three different “use cases” based on the end uses of the energy storage:  transmission-connected storage systems, distribution-connected storage systems, and customer-sited storage systems. The initial proposed procurement targets are: 

* The Totals include the additional interim targets for 2016 and 2018 that were intentionally omitted from this table.

To procure third-party owned energy storage to meet the targets, the CPUC proposed a “reverse auction” market mechanism, similar in structure to the state’s existing Renewable Auction Mechanism for renewable power sources. Under a reverse auction, energy storage providers would bid non-negotiable price bids, and the IOUs select projects starting with the lowest cost. The first auction, proposed for June of 2014, will require the IOUs to procure an aggregate 200 MW of storage. Subsequent auctions will be conducted every two years. The procurement targets are subject to change if the IOUs can demonstrate, among other things, that the energy storage resources bid into the reverse auction are not reasonable in cost, are not cost effective, or were insufficiently competitive.

The CPUC anticipates releasing its final order in October of this year.

by William Friedman

The Federal Energy Regulatory Commission’s (FERC) approval of the New York Independent System Operator’s (NYISO) demand response compensation program left out a mechanism for compensating demand response from behind-the-meter generation, which prompted the latest outcry from demand response providers.   The demand response providers filed a complaint with FERC claiming discrimination between methods of demand response and seeking to compel the NYISO to compensate behind-the-meter generation demand response.  On the other side of the controversy are power producers who fear that compensating behind-the-meter generation would take money from power generation on the other side of the meter.

Demand response is a reduction in electricity consumption by customers from their expected consumption in response to an increase in the price of electricity or incentive payments designed to induce lower consumption.  In Order No. 745, FERC established a compensation approach for demand response resources by requiring that each regional transmission organization (RTO) and independent system operator (ISO) pay a demand response resource the market price for energy when the resource has the capability to balance supply and demand and when doing so would provide a net economic benefit to consumers.

The NYISO’s Order No. 745 compliance filing was approved by FERC without providing for compensation to behind-the-meter generation.  In other words, consumers with behind-the-meter generation, usually large industrial facilities, will not be compensated for relying on their own generators as an alternative to purchasing power from the market, while other demand response resources that do not generate power will be compensated solely for decreasing consumption.  In response, a number of facilities and aggregators that provide demand response recently complained to FERC seeking an order compelling the NYISO to compensate behind-the-meter generation as part of its demand response program.  The complainants point to neighboring RTOs/ISOs, including ISO-NE, PJM and MISO, which do compensate behind-the-meter generation and argue that excluding behind-the-meter generation violates FERC policy and constitutes undue discrimination.

The demand response providers are opposed by a consortium of independent power producers who argue that including behind-the-meter generation is economically inefficient and creates an improper incentive to move generation behind the meter where it is outside the reach of the RTO/ISO.  The NYISO also filed an answer to the complaint, arguing that forcing the ISO to compensate behind-the-meter generation as a demand response resource raises grid reliability and monitoring concerns.  The NYISO states in its pleading that it is already exploring revisions to its demand response program and the ISO’s internal stakeholder process should be allowed to run its course.  Answers to the complaint were filed last week.  A FERC ruling should be handed down in two to three months.

by Ari Peskoe

Last week President Obama announced a package of programs that aim to increase electricity generation and transmission in Ghana, Kenya, Liberia, Nigeria and Tanzania.  Headlined by $7 billion in U.S. government support and $9 billion in commitments from the private sector to invest in new generation projects, Obama’s initiative aims to “double access to power in Sub-Saharan Africa.” Although details are still forthcoming, the initiative is evidence of the enormous demand in Sub-Saharan Africa for new generation.  New supply supported by the President’s initiative is likely to primarily be large-scale natural gas-fired and hydro generation, and it is not clear how such projects will “double access.”    

Less than a third of people living in Sub-Saharan Africa have access to electricity.  Excluding South Africa, Sub-Saharan Africa has only 28 gigawatts (GW) of generation capacity for a population of approximately 850 million people.  (For context, the Netherlands has 26 GW of capacity for a population of less than 17 million).  With the exception of Nigeria, the five target countries have very low population densities and lower than average urban populations as a percent of the total population.  In other words, dispersed populations either have no electric grid at all or have access to a grid with only meager capacity.

New large-scale generation located near urban centers and industrial zones can be helpful in supplying stressed grids, and such projects are also likely to be the most feasible.  The more daunting task, however, is to provide electricity to dispersed rural populations, 85 percent of whom in Sub-Saharan Africa have no access to electricity.  Obama’s initiative includes $2 million in grants to African-owned and operated enterprises “to develop or expand the use of proven technologies for off-grid electricity benefitting rural and marginal populations.”  The initiative’s private sector commitments also include “installation of 200 decentralized biomass-based mini power plants in Tanzania.”  Such small-scale projects demonstrate that sub-Saharan Africa presents a range of opportunities, but that Obama’s initiative is focused on large-scale projects rather than reaching rural populations with decentralized alternatives.

Of the $9 billion in private sector commitments, just over $1 billion is for wind generation; fuel source for the balance has yet to be specified.  Natural gas and hydro projects, however, are well-positioned to receive the bulk of the support.   According to the most recent statistics (which are a bit out of date and incomplete), the five target countries currently get the majority of their power from natural gas and hydro, and oil is the third most common fuel, providing almost twenty percent of the countries’ electricity.  New investments may include some oil-fired generation, but that fuel is generally more valuable for transportation than power generation.

Coal-fired generation is also unlikely to see major support from Obama’s initiative.  Coal is used for electricity generation only in Tanzania, which is otherwise dominated by hydro and natural gas generation.  Furthermore, in his recent Climate Action Plan, Obama committed to “end to U.S. government support for public financing of new coal plants overseas.”  That commitment, however, includes an exception for “the world’s poorest countries in cases where no other economically feasible alternative exists.” 

The target countries all have economically feasible alternatives to coal.  Nigeria is a major oil and natural gas producer.  Ghana has significant domestic sources of natural gas and also imports natural gas from nearby Nigeria through the West Africa Gas Pipeline.  Kenya already produces significant geothermal power, and Obama’s initiative includes private sector commitments to build substantial wind capacity there.  The imitative also includes commitments to build wind capacity in Tanzania, and although that country has significant coal reserves, it also recently announced that it has offshore natural gas deposits as well.  Liberia has almost no electricity infrastructure and is currently focused on reconstructing a 64-megawatt hydropower facility that fell into disrepair in 1990 during the country’s civil war. 

Obama’s initiative also includes commitments that U.S. government agencies will work with the target countries to “implement the policy, regulatory, and other reforms necessary to attract private sector investment in the energy and power sectors.”