Energy Business Law : Energy Lawyers & Attorneys: McDermott Will & Emery Law Firm

by William M. Friedman

Massachusetts’ net metering program went into full effect in February, but the Massachusetts Department of Public Utilities (DPU) may have inadvertently stymied the program’s growth by issuing an order that prohibits or impedes optimal interconnection of larger projects. The Massachusetts DPU is now considering reversing course.

Under the Massachusetts’ net metering program, local utilities provide billing credit to customers with interconnected renewable energy projects that feed power into the grid. The customer that hosts the project can either use the credit against its own account or assign the credit to another account with the same utility. The amount of interconnected and net metered generation permitted under the program is subject to two separate caps, one for private entities and one for municipalities and other governmental entities. Each cap is at 3 percent of the utility’s highest historical peak load, but the rules that apply to each cap differ slightly.

A net metering facility under the private cap may have a generating capacity up to 2 MW, while a facility under the public cap may have a generating capacity up to 10 MW (each municipality may not exceed 10 MW for all of its departments or subdivisions combined), but is limited to 2 MW per unit. Last year, the Massachusetts DPU issued guidance defining a “unit” as a single turbine for wind facilities, a single piece of generating equipment (e.g., an engine or turbine) for agricultural net metering facilities, or a single inverter for solar net metering facilities. 

The Massachusetts DPU defined “facility” for both the public and private caps as “energy generating equipment associated with a single parcel of land, interconnected with the electric distribution system at a single point, behind a single meter.” This three-part test, however, poses problems for larger capacity projects, particularly those under the public cap, which can potentially have a capacity of up to 10 MW. For larger projects, the distribution company that performs the System Impact Study and designs the interconnect might conclude that a design using multiple points of interconnection is best for safety, electrical reliability and electrical efficiency. While a design with two points of interconnection and two meters might be more appropriate, a facility with more than one point of interconnection will not qualify for net metering credit. The Massachusetts DPU’s definition thereby encourages suboptimal interconnection configurations.

The Massachusetts DPU has recognized the problem its definition caused and is currently considering a fix. In October 2012, the Massachusetts DPU sought comments on whether to allow an exception on the basis of optimizing facility interconnection and how such an exception might work. In response, the local distribution companies tepidly supported an exception to the DPU’s three-part test, emphasizing a clear and workable definition of “facility,” while other commenters were more enthusiastic about an exception. There is no set timeline for the Massachusetts DPU to make a final decision on whether to grant an exception. Since the definitional order was issued, a number of petitions have been filed seeking exemptions from various aspects of the DPU’s rule, and some petitions have met with success.

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by Gale Chan, Martha Groves Pugh and Philip Tingle

Last week, we reported that the Internal Revenue Service (IRS) issued Notice 2013-29 (Notice) to to provide guidance on eligibility for the production tax credit (PTC) and investment tax credit (ITC). On April 25, 2013, the Internal Revenue Service (IRS) updated the Notice. Under the IRS’s additional guidance, a binding contract that has a liquidated damages provision that limits damages to at least 5 percent of the total contract price will not be treated as limiting damages to a specified amount. 

When the Notice was first issued on April 15, 2013, it provided that a contract is binding only if the contract did not limit damages to a specified amount, including the use of a liquidated damages provision. This language differed from the treatment of a binding contract under the guidance issued by the Department of Treasury with respect to the grant program under section 1603 of the American Recovery and Reinvestment Act of 2009 because the Section 1603 Grant program, like the bonus depreciation regulations, provided that a liquidated damages provision that limited damages to an amount that was equal to at least 5 percent of the total contract price would not be treated as limiting damages in a contract to a specified amount. As updated, the Notice is now in line with the definition of binding contract under the guidance issued with respect to the Section 1603 Grant as well as the IRS’s own regulations regarding a binding contract in the bonus depreciation regulations.

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by Ari Peskoe

On April 24, four Republican legislators and four Democratic legislators reintroduced the Master Limited Partnership Parity Act in the House and Senate. Master Limited Partnerships (MLP) provide tax advantages to energy project developers but are currently limited under the Tax Code to resources subject to depletion, such as oil and gas, and transportation and storage of certain fuels. The Act would expand the definition of qualified projects to include a range of clean energy resources and infrastructure projects. 

An MLP is a business structure that is taxed as a partnership, but whose ownership interests can be traded like corporate stock on a market. Congress enacted legislation in 1987 that allowed entities that earn at least 90 percent of their income from “qualified” sources to be treated as MLPs. Qualifying income includes “income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil, or products thereof), or the marketing of any mineral or natural resource.” In 2008, Congress expanded the definition of qualifying income to include income from the transportation and storage of certain renewable and alternative fuels, such as ethanol, biodiesel and industrial-source carbon dioxide.

As we reported last June, legislators first introduced the MLP Parity Act last year. The Act would have expanded the definition of qualifying income purposes to include income from wind, biomass, geothermal, solar, municipal solid waste, hydropower, marine and hydrokinetic, fuel cells and combined heat and power projects, as well as certain renewable transportation fuels.  Those bills were referred to the Senate Finance Committee and House Ways and Means Committee but never advanced. The updated MLP Act introduced on April 24, also includes carbon capture and storage, waste heat to power, renewable chemical and energy efficient building projects.    

In public statements, Senators Coon (D-DE) and Murkowski (R-AK), two of the Act’s sponsors, have emphasized that the MLP Parity Act attempts to “level the playing field” by providing renewable energy projects with the same tax benefits that fossil fuel projects have enjoyed. Although the rhetoric should be appealing to both sides of the aisle and the Act is backed by a range of industry groups that would benefit from the legislation, it’s fate in Congress is unclear. 

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by Jon B. Dubrow and Cerissa Cafasso

On Monday, April 22, 2013, after rejecting the initial settlement agreement, Judge Richard Matsch (D. Colo.) approved a revised settlement of a suit brought by the U.S. Department of Justice (DOJ) against two energy companies for conspiring not to compete for mineral rights leases.  Gunnison Energy Corp. (GEC) and SG Interests I Ltd. and SG Interests VII Ltd. (collectively "SGI”) will each pay a fine of $275,000 to the DOJ to settle allegations of agreeing not to bid against each other in violation of antitrust law for natural gas leases on government land in western Colorado.  These fines are in addition to those related to alleged False Claims Act violations, for which SGI and GEC paid government fines of $206,250 and $245,000 respectively.  The new settlement is twice the amount of the fines in the original settlement.

McDermott Will & Emery wrote an article in February 2012 analyzing the DOJ's initial complaint against the parties, and the competitive implications of joint bidding.  At the time, the parties had agreed to pay a total of $550,000 in fines.  The court rejected the settlement in December 2012 finding that it was not in the public interest.  "There is no basis for saying that the approval of these settlements would act as a deterrence to these defendants and others in the industry, particularly as GEC considers 'joint bidding' to be common in the industry."  Further, the settlement amount was "nothing more than the nuisance value of [the] litigation."  Additionally, as reflected in the newly approved deal, the court wanted the alleged Sherman Act violations and False Claims Act violations settled separately, with a payment for the Sherman Act claims separate from, and in addition to, any amount due under the False Claims Act.  At heart, it appears Judge Matsch wanted any settlement he approved to be meaningful enough to have a deterrent effect on future agreements.

This was the DOJ's first challenge to an anti-competitive bidding agreement for mineral rights leases, but it is just one of the recent cases in which joint bidding activities have become the focus of antitrust scrutiny.  In Summer 2012, the DOJ opened an investigation into Chesapeake Energy's acquisition of oil and gas properties in Michigan and the possibility that Chesapeake conspired with Encana Corp. to allocate bids on those properties.  In 2006, the DOJ began investigating the joint bidding practices of private equity firms in connection with leveraged buyouts.  That investigation led to class action suits against private equity firms.  One of those suits survived a motion for summary judgment last month.

It is important to note that the DOJ is paying attention to joint bidding practices and taking action.  As noted in the SGI/GEC matter, while joint bidding may in fact be common practice in the energy field, it is not necessarily lawful.  Each arrangement should be evaluated for potential anticompetitive effects.

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by Gale Chan, Martha Groves Pugh and Philip Tingle

The Internal Revenue Service (IRS) issued Notice 2013-29 to provide guidance on eligibility for the production tax credit (PTC) and the investment tax credit (ITC). Under the most recent extension of the PTC and ITC, enacted by Congress on January 1, 2013, a renewable energy facility must begin construction before January 1, 2014 to be eligible for the PTC or ITC.  The IRS’ Notice largely follows the guidance that Treasury provided with respect to Section 1603 grants and provides that a taxpayer may establish that construction has begun either by demonstrating that physical work of a significant nature has begun or by satisfying a five percent safe harbor.  Key differences between the Section 1603 Guidance and the IRS’ Notice on the PTC and ITC are highlighted below.

Under the IRS’ Notice, physical work of a significant nature must be with respect to tangible property that is integral to the facility.  Thus, property integral to the production of electricity is included but not property used for the transmission of electricity.  Power conditioning equipment, such as a transformer, is an integral part of the facility.

Either on-site or off-site work can be sufficient to demonstrate the beginning of construction.  If work is performed off-site, the work can be performed either by the taxpayer or by another person for the taxpayer pursuant to a binding written contract.  A contract is binding only if it is enforceable under local law against the taxpayer (or a predecessor), and the contract does not limit damages to a specified amount.  This definition is a departure from the 1603 Guidance, which determined that a contract is binding so long as the liquidated damages provision in the contract does not limit damages to less than five percent of the total contract price.

A taxpayer must maintain a continuous program of construction of a significant nature.  The IRS’ Notice lists detailed examples, not provided in the 1603 Guidance, of allowable disruptions that are beyond the control of the taxpayer, including: severe weather, licensing and permitting delays, delays requested in writing by a government agency, financing delays of less than six months, and supply shortages.p>

Alternatively, like the 1603 Guidance, the IRS’ Notice includes a safe harbor that provides eligibility for the PTC or ITC if the taxpayer pays or incurs five percent or more of the total costs of the facility.  All costs properly included in the depreciable basis of the facility are taken into account.  However, the cost of land or any property not integral to the facility is not included. 

Unlike the 1603 Guidance, the IRS’ Notice imposes a continuous efforts requirement for the safe harbor and includes a taxpayer favorable provision related to cost overruns.  Facts and circumstances indicating continuous efforts include paying or incurring additional amounts included in the total cost of the facility, obtaining permits, and entering into binding written contracts for components or future work.  With respect to a single project comprised of multiple facilities, the IRS’ Notice provides that if the actual cost of the project exceeds the anticipated cost such that the safe harbor amount is less than five percent of the actual total costs, the safe harbor is not fully satisfied.  However, the PTC or ITC may be claimed with respect to some, but not all, of the individual facilities whose total costs are not more than 20 times greater than the amount the taxpayer paid or incurred before January 1, 2014.

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by Thomas L. Hefty

The Illinois General Assembly could be on the verge of enacting legislation, the Hydraulic Fracturing Regulatory Act (H.B 2615), that some environmental groups are touting as an environmental best practices for regulating the shale oil and gas recovery method known as horizontal hydraulic fracturing (fracing). H.B. 2615, the result of months of negotiations between environmental groups and the oil and gas exploration and production (E&P) industry, was set to be voted on in the Illinois General Assembly in late March, but a last second amendment (favoring in-state licensed drilling companies) has stalled the bill’s progress. 

While HB 2615 is laudable for setting robust regulations on horizontal fracing operations, what should make it the betting favorite is that it is also a revenue bill – the second half of H.B. 2615 contains the Illinois Hydraulic Fracturing Tax Act. Under H.B. 2615, Illinois would finally join the majority of drilling states that tax severed oil and gas. Each Illinois well using horizontal hydraulic fracturing could produce several million dollars in severance taxes during the span of the well’s productive life.

Illinois is one of the few drilling states not to impose any severance or gross production taxes on its substantial oil and gas production. Illinois currently has about 32,000 wells producing between 10 and 11 million bbls of oil (15th nationally) and 2,120 million cubic feet of natural gas, ranking it 26th. That production would increase significantly if large-scale horizontal hydraulic fracturing were introduced in Illinois to the New Albany Shale formation. Technically recoverable shale gas in the New Albany Shale is estimated at up to 11 trillion cubic feet (for comparison, the Marcellus Shale in the East has 84 TCF). A majority of the drilling states, including Indiana and Kentucky, tax oil and gas production. Several others, most prominently Pennsylvania, are currently considering adopting oil and gas severance taxes.

Competing with H.B. 2615 are three other bills: two bills favored by those environmental groups not supporting H.B. 2615 that would put a two-year moratorium on any hydraulic fracturing and an E&P industry-sponsored bill that environmental and community groups strenuously oppose. One would think that with the support of the E&P industry and some environmental groups (including the Natural Resources Defense Council), plus the revenue enhancement features of the severance tax, H.B. 2615 should be a done deal. But given the current state of Illinois politics, taxes might not be the certainty that Ben Franklin once thought they were. 

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by Thomas Hefty

Last month, the Department of Energy (DOE) issued its Large-Scale (>10 MW) Renewable Energy Guide, which is subtitled “A Practical Guide to Getting Large-Scale Renewable Energy Projects Financed with Private Capital” (Guide).   According to The Guide, its main purpose is to “provide a project development framework to allow the federal government, private developers and investors to work in a coordinated fashion on large-scale renewable energy projects.” The Guide aims to achieve this purpose by (a) developing a common language between federal agencies and developers; (b) describing a “best practice” large-scale renewable energy project development process; (c) giving government employees an understanding of what his or her responsibilities and roles are within the development process; and (d) outlining for developers a recognizable, reliable and predictable process in which it can engage with a reasonable likelihood of commercial success.

Renewable energy developed on federal land is a prototypical government/private industry hybrid -- the federal government is making more of its land available for renewable energy development (regardless of whether the federal government will be the energy off-taker), but relies nearly exclusively on private developers to develop and operate projects. However, the record of federal agency participation in renewable energy development has been less than stellar. According to the Guide, “many of the faults found in past federal contracts related to renewable energy can be attributed to a failure by the government to adequately understand the commercial power plant development side of the transaction during negotiation.”

To bridge the divide between federal agencies and their private development counterparts, DOE designed the Guide to provide a project development framework that allows the parties to work in a coordinated fashion -- to enable “both sides of a transaction to better understand the deal because better informed people execute better deals.” The Guide maps a process that is grounded in the foundations of commercial project development while integrating traditional federal processes. That process is shown below:

The federal agency takes the lead role in the project acquisition and pre-development phase and, by using the techniques in the Guide, the federal agency can methodically identify, analyze and choose projects that are more likely to be successful when offered to private developers in the late pre-development or early development phases.

The Guide maybe useful to private developers as well because if it can reduce developers’ perceptions of out-sized development risk when dealing with the federal government. To the extent that the Guide represents “best practices” for successfully developing renewable energy projects, private developers can use the Guide to analyze and improve their practices and strategies.

The Guide was developed in cooperation with the U.S. Army Energy Initiatives Task Force, the National Renewable Energy Laboratory and private industry consultants. DOE intends to update the Guide periodically.

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by Ari Peskoe

The Iowa state legislature is moving forward with a bill that would create the first U.S. feed-in tariff specifically for wind generation. If the bill is enacted, Iowa would join Vermont, and the cities of Los Angeles, and Gainesville, Florida as the U.S. jurisdictions currently offering a feed-in tariff. While it may seem like investors need little inducement to invest in wind capacity in Iowa, which already ranks third in wind capacity among U.S. states, the new incentive is aimed at mid-sized facilities, a neglected market in that state.

Under a feed-in tariff, a utility sets a long-term price for renewably generated electricity. A feed-in-tariff benefits generators by providing a standard offer contract and favorable rates, often based on a generous estimate of production costs. Feed-in tariffs are generally credited as one of the main reasons for large increases in renewable generation in several European countries. In the U.S., feed-in tariffs have been less popular. Under the Public Utilities Regulatory Policy Act (PURPA) of 1978, California offered a feed-in tariff in the 1980s that led to a proliferation of wind generation. While other states also offered similar programs under PURPA, none were as successful as California’s.

In Iowa, a state senate committee passed a bill earlier this month that would provide a feed-in tariff to wind facilities smaller than twenty megawatts in capacity and located on agricultural land. Under the standard offer contracts, the rate will be based on each utility’s cost, including a rate of return, for the new development of wind generation, and the term will be 10 years or until construction and financing costs have been recovered, whichever is earlier. 

The new tariff is designed to address a gap in the state’s wind portfolio. As of the end of 2011, about 85 percent of the state’s wind capacity was from facilities larger than 100 megawatts (19 total installations). The state had only five facilities sized between 2 and 20 megawatts, which accounted for less than two percent of capacity. Smaller-scale projects may be easier to site and could attract a different class of investors unable or unwilling to develop a utility-scale project. 

Other windy states have actively developed this mid-range market. Minnesota’s community wind program, launched in 2005, focuses on local ownership and provides front-loaded tariffs for facilities up to 50 megawatts. As of 2011, nearly 400 megawatts of capacity have been deployed under the program. Nebraska followed suit in 2007, but the program has failed to take off. That state, which has the fourth best wind for energy production, ranks just 23rd in total installed capacity.

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by David J. Levine and Pamela D. Walther

The flurry of international trade disputes in the renewable energy field, particularly the solar sector, is complicating the business landscape for the renewable energy industry.  In their BloombergBNA analysis piece, McDermott international trade lawyers David Levine and Pamela Walther provide a detailed account of renewable energy trade actions in the domestic and international arenas.  As the long-term implications of these disputes raise serious strategic issues for providers, consumers and governments, those involved are well-advised to monitor developments and take an active role in proceedings to protect their interests.

To read the full article, click here.

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by Melissa Dorn

The United States Department of the Treasury released a notification on March 4, 2013 clarifying how sequestration will affect payments awarded under Section 1603 of the American Recovery and Reinvestment Tax Act of 2009 for specified energy property in lieu of tax credits. Treasury stated that it will reduce the amount of each final award issued from March 1, 2013 through September 30, 2013 by 8.7 percent, regardless of when the application was received by Treasury.  The 8.7 percent sequestration rate is subject to change following September 30, 2013.

For more information please contact your regular McDermott lawyer of Phil Tingle at +1 305 347 6536 or ptingle@mwe.com.

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by William Friedman

President Obama proposed in his State of the Union creating an Energy Security Trust to invest in research and technology that will “shift our cars and trucks off oil for good.”  Oil and gas lease revenues, estimated at $150 billion over the next decade, would fund the Trust.  The idea of the Trust is more than 30 years old and was recently endorsed by the ranking Republican on the Senate Energy and Natural Resources Committee.  While predicting what Congress will do is a fool’s errand, there is some reason to think that an Energy Security Trust could become a reality.

President Carter in 1979 asked Congress to pass a windfall profits tax on oil company revenues in order to establish a trust that would be used to “protect low income families from energy price increases, to build a more efficient mass transportation system, and to put American genius to work solving our long-range energy problems.” More recently, Energy Security Trust Fund bills were proposed in 2007 and 2009.  The 2009 bill, entitled “America’s Energy Security Trust Fund Act of 2009,” proposed an excise tax on “carbon substances” including coal, petroleum products and natural gas.  The tax would have collected $15 per ton of carbon dioxide content in taxable substances sold by manufacturers, producers or importers and would have escalated at a base rate of $10 each year.  The proposed trust fund would have been used to finance research in clean energy technology, assist industries negatively affected by the bill, and provide payroll tax relief to individual taxpayers.  Neither the 2007 bill nor the 2009 bill, (both proposed by Rep. John Larson (D-CT.)) passed in Congress.

Unlike these previous proposals, President Obama’s proposal does not rely on tax revenues and instead resembles a recent energy policy blueprint put forward by Sen. Lisa Murkowski (R-AK), the ranking Republican on the Energy and Natural Resources Committee.  Senator Murkowski’s plan, “Energy 20/20: A Vision for America’s Energy Future,” calls for an Advanced Energy Trust Fund that would be funded by rents, royalties, bonus bids and corporate income taxes.  Murkowski also advocates opening up federal lands like Arctic National Wildlife Refuge (ANWR) and other offshore resources and using those revenues to fund a trust.  The Advanced Energy Trust Fund would be administered by the Department of Energy and used to pay for advances in renewable energy, energy efficiency, alternative fuels and advanced vehicles.

The White House has not released details yet on how the proposed Trust would be funded or administered. Unlike Senator Murkowski, the President is unlikely to support opening ANWR for drilling, which environmental groups have long opposed.  Yet, some version of an Energy Trust has support on both sides of the aisle.

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by Christopher S. Bloom

The Southwest Power Pool’s (SPP) deadline for revising its tariff to add day-ahead and real-time energy to its Integrated Marketplace is this Friday, February 15.  Federal Energy Regulatory Commission (FERC) granted conditional acceptance of SPP’s revised tariff in October, contingent upon SPP submitting various complying revisions.

The Integrated Marketplace is a change of course from the Energy Imbalance Service (EIS) market that SPP launched in 2007. The EIS market has served as a real-time platform for generators to sell excess energy and for load servers to purchase that energy. EIS reduced dependence on bilateral contracts, and enabled competition between generators to provide the lowest-priced energy, using locational imbalance pricing. The new Integrated Marketplace revamps the EIS by creating a day-ahead market along with a real-time energy and operating reserve market. To reduce energy and transaction costs, the new marketplace will consolidate 16 balancing authorities into a single SPP-operated balancing authority. The Integrated Marketplace will also utilize locational-marginal pricing and will include virtual transactions, auction revenue rights, and a market for transmission congestion rights.

The new day-ahead market will allow generators to submit offers to sell energy and operating reserves, and load-servers to submit bids to purchase energy. After the day-ahead submissions, SPP will clear the offers and bids via security-constrained unit commitment and security-constrained economic dispatch algorithms. The end product will be a financially binding schedule that matches sale offers with demand bids and satisfies operating reserve requirements. For day-of energy sales, settlement will be based on the differences between quantities cleared in the Real-Time Balancing Market and the day-ahead market clearing.

The Integrated Marketplace will also bring virtual bidding to the SPP. For a fee and subject to meeting credit requirements, market participants can enter into transactions that essentially short the price of the day-ahead market. Should those virtual transactions clear, the market participant will be obligated to purchase or sell the energy at the real-time locational marginal price, at a profit or loss. The benefit of virtual transactions is that they allow for convergence of day-ahead and real-time prices, allowing a more accurate reflection of the true value and price of the energy. Market participants will be limited to a single offer or bid per hour at each settlement location for each asset owner it represents.

An additional feature of the Integrated Marketplace is its incorporation of auction revenue rights (ARR) and the related transmission congestion rights (TCR) auction. ARRs are awarded to market participants based on firm transmission rights on the SPP grid. ARR holders can choose to retain their rights and receive a share of the revenue generated in the TCR auction, or ARR holders can convert their ARRs to TCRs. TCRs are tradable and TCR holders are entitled to revenue streams or charges based on the cost of congestion in the hourly day-ahead market associated with the TCRs.

In its October 18 order in Docket No ER12-1179, FERC addressed a number of issues raised in protests to SPP’s proposed Tariff Revisions, conditionally approving the Integrated Marketplace, subject to SPP submitting a compliance filing incorporating specific changes to the Tariff. The required revisions include:

(a)    clarification of forecasting procedures for Variable Energy Resources, including wind energy;

(b)   establishment of procedures to prevent manipulation — such as purposeful withholding or manipulation of load-forecasting — of the marketplace’s limited must-offer requirement in the day-ahead market;

(c)    revision of the definitions for ancillary services in the marketplace;

(d)   modification of the ARR process to plan for ties among winning bids and other scenarios; and

(e)    modification of the ARR allocation procedures.

SPP provides services to areas located within Arkansas, Kansas, Louisiana, Mississippi, Missouri, Nebraska, New Mexico, Oklahoma and Texas. SPP expects for its Integrated Marketplace to be ready for operation on March 1, 2014. SPP’s compliance filing will be open for comments for at least 30 days.

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by Simone Goligorsky

On February 7, 2013, it was announced that the Economic and Monetary Affairs (ECON) Committee of the European Parliament (EP) was withdrawing its objection to the technical standards (TS) for the regulation on over-the-counter derivatives, central counterparties and trade repositories, commonly known as the European Markets Infrastructure Regulation (EMIR). 

The TS supplement the level 1 text of EMIR, which came into force in August 2012.  It is the TS that define who exactly will be affected by EMIR, and how. 

Following the endorsement of the TS in December 2012 by the European Commission (EC), after they were published by the European Securities and Markets Authority in September 2012, the TS were undergoing the last review prior to their publication in the Official Journal of the European Union.  Many market participants expected the EP’s review to a procedural, rubber-stamping exercise. 

However, on January 24, 2013, it was confirmed that the ECON Committee was to publish a motion for a resolution to reject certain TS.  One of the reasons given for mooting the rejection was the view that the EC had gone beyond its remit for the TS, set out for it in the level 1 text of EMIR, when drafting the TS.

The TS in question related to matters including, inter alia:

1. The clearing threshold for non-financial counterparties, particularly the condition that if the clearing threshold for one asset class was exceeded by a counterparty, then the counterparty would be automatically held to have exceeded the threshold for all asset classes; and
2. The requirement for timely confirmations, in particular how this obligation would affect smaller, non-financial counterparties.

If the TS had been rejected, then the EC would have been required to put forward new TS.  This may have, in turn, have delayed the publication of the TS, and ultimately, the coming into force of EMIR. 

However, on February 7, 2013, the EP withdrew the resolution calling for the rejection of the draft TS.  The withdrawal of the objection was based on certain assurances given by the EC, including the assurance that the EC would publish frequent ‘questions and answer’ booklets to cover any matters over which there arose legal uncertainty.

EMIR has been tabled as the US equivalent of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd Frank).  As currently drafted, market participants undertaking activities in both the US and European markets may be subject to both Dodd Frank and EMIR, requiring, them, for example, to report trades to both European and US regulators. 

To avoid market participants having to report to two sets of regulators, European regulators are meeting with their US counterparts over the course of Q1 and Q2 2013, to advise the United States that EMIR should be accepted as being as strict as Dodd Frank.  If accepted, market participants complying with EMIR would be deemed to comply with Dodd Frank, and vice versa.

As the publication of the TS will not be delayed as much as initially thought, EMIR’s entry into force is not expected to be delayed.  The first obligations (the reporting of credit and interest rate derivatives) is expected to apply from July 2013.  The remaining obligations will come into force periodically, with EMIR expected to be fully in force by Summer 2014. 

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by Thomas Hefty

After years of studies and pilot programs, Los Angeles Department of Water and Power (LADWP), the United States’ largest municipal utility, unveiled the 100 megawatt  FiT Set Pricing Program (FiT 100), which will start on February 1, 2013.  Long favored in Europe to encourage renewable, distributed generation, a feed-in tariff or FiT offers generators standard long-term contracts, generally at favorable rates, eliminating the need for contract negotiations with utilities.  Feed-in tariffs are being introduced into U.S.’s renewable electrical generation market to fill the void between net-metering programs and utility-scale renewable energy projects.  While a range of renewable resources are eligible for the program, solar PV systems are likely to dominate the FiT 100 program.  

The FiT 100 allocation will be meted out in five 20 MW allocations, with one allocation made available every six months.  The first 20 MW allocation for the will be available from February 1, 2013 until June 28, 2013.  LADWP is using a fixed declining tier pricing system, with the Base Price of Energy (BPE) set at $0.17 per kWh for the first 20 MW allocation and declining one cent with each additional 20 MW allocation.  The price paid under the FiT Standard Offer Power Purchase Agreement (PPA) is the product of the BPE multiplied by a time-of-delivery (TOD) factor, which ranges from 2.25 for High Season (Jun-Sep), High Peak (M-F 1pm-5pm) to 0.50 for Base (M-F 8pm-10am, all day Sat/Sun).  The BPE and TOD factor are fixed throughout the term of the PPA, which is up to 20 years. 

To qualify for the FiT 100 program, the facility must be located within LADWP’s service area, have a nameplate capacity of between 30 kW and 3 MW, have a commercial operation date after the PPA effective date, and the facility cannot consume more than 10 percent of its energy generation.  All energy produced from the FiT Facility, as well as capacity rights and environmental attributes, must be sold to LADWP, and LADWP’s off-take obligation is capped at 115 percent of the facility’s monthly production profile as submitted by the FiT applicant.  Neither the PPA seller nor the owner of the FiT facility site can apply for or participate in any net metering program or receive any ratepayer-funded incentives.  In addition, to qualify for the program at least one member of the development team must have successfully developed and constructed at least one similar project using the same technology.  Additional terms and guidelines are available at LADWP’s website.

There are two general development models for FiT facilities: 1) property owners or long-term tenants with rights to the roof, parking field, or other underutilized real estate asset develop and own the FiT facilities (self developed model); or 2) independent power producers lease that underutilized asset from the real estate asset holder and develop the FiT facility (rent-a-roof model).  The rent-a-roof model has proven to be the more popular choice in Europe.  While rooftops are not the only location for solar photovoltaic FiT facilities, they often have advantages compared to freestanding ground mounted solar photovoltaic facilities including more insolation, less shading, flatter surfaces, fewer security risks and fewer zoning issues. 

Rent-a-roof leases can be structured several ways, with the real estate owner receiving a fixed percentage of PPA revenues, a set periodic rent based on the rooftop area, or an upfront lump sum payment, or they can use a lease-to-own structure.  Alternatively, the FiT developer can build a new roof for the owner and set off that cost from the rent. Generally, the better the site’s insolation characteristics, the more favorable the terms are to the site owner. 

Even though the minimum size for a FiT 100 eligible project is 30 kW, which would only require approximately 3,000 square feet of roof area (using the generally accepted “rule of thumb” that each kW of solar PV requires about 100 square feet of roof area), expect most independent power producers to require a minimum of 30,000 square feet of flat, unshaded roof with a remaining service life of no less than ten years.  While installed solar PV costs have fallen substantially, largely due to the dramatic decrease in the cost of PV panels, the upfront development and installation costs remain significant, and developers generally believe the ability to efficiently scale those costs diminishes for systems smaller than 300 kW. 

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