Questions about EPA regulation of power plant carbon emissions

Friday, October 31, 2014

This week the U.S. Environmental Protection Agency issued a public notice relating to its Clean Power Plan, the agency's proposed rule to reduce carbon emissions from the nation's existing power plants.  The notice reiterates questions raised by commenters about issues including the redispatch from coal- to natural gas-fired generation and near-term carbon reductions through 2029.

The Clean Power Plan imposes a federal carbon emissions rate (stated in pounds of carbon emitted per megawatt-hour of electric energy generated) for each state.  The rule is designed to offer states flexibility in developing plans to achieve that level of carbon intensity, and features four proposed "building block" elements that states may choose to include in their program design: increased coal plant efficiency, increased utilization of natural gas plants, increased renewable energy, and increased energy efficiency.  Collectively, EPA projects that by 2030 the Clean Power Plan's implementation will reduce power plant carbon emissions 30 percent below 2005 levels.

Since EPA published its proposal on June 18, 2014, the agency has held at least eight days of public hearings in four cities, attended by over 2,700 people, of whom nearly half spoke or otherwise weighed in.  The draft Clean Power Plan was originally scheduled for public comment through October 16, but EPA extended the comment period by 45 days (until December 1, 2014) in response to both the volume of comments and numerous requests for additional time. 

On October 28, EPA issued a notice of data availability related to the proposed Clean Power Plan.  EPA routinely issues such a notice, or NODA, to provide the public with a targeted opportunity to consider and comment on emerging technical issues and data related to an ongoing rulemaking.  EPA's Notice of Data Availability Related to the Proposed Clean Power Plan (PDF) provides additional information on several topics raised by stakeholders and solicits comment on the information presented.  The three topics covered in the notice are the emission reduction compliance trajectories created by the interim goal for 2020 to 2029, certain aspects of the building block methodology, and the way state-specific carbon dioxide goals are calculated.

EPA's interim goals govern emission reductions over the 2020-2029 period, as states transition to energy resources with lower carbon intensity.  Some stakeholders have expressed concern that, as proposed, the interim goals do not provide enough flexibility for some states which may be forced to rely heavily on re-dispatch from fossil steam generation (e.g., coal- , oil-, or gas-fired boilers) to natural gas combined cycle units to achieve the required reductions, and that this effect of the interim goals severely limits the opportunity to fully take advantage of the remaining asset value of existing coal-fired generation -- particularly challenging with the threat of a "polar vortex" or other disruptive weather event.  EPA requests comment on these interim goals and whether they afford suitable flexibility.

Stakeholders have also raised questions about the building blocks available to states as they design compliance programs.  In particular, building block 2 focuses on shifting utilization from coal- and other fossil-fired steam power plants to more carbon-efficient natural gas combined cycle plants.    Building block 3 focuses on renewable energy and nuclear power.  In response, EPA requests comment on ways that building block 2 could be expanded to include new natural gas combined cycle units and natural gas co-firing in existing coal-fired boilers and ways that state-level renewable energy targets could be set based on regional potential for renewable energy.

Stakeholders have also noted concerns with the way the state-specific carbon dioxide goals are calculated.  These include concerns that the numeric formula for calculating each state's goal is not consistent in its application of the best system of emission reduction (BSER) for each building block, and concerns with the use of data for the single year 2012.

EPA's Clean Power Plan is now open for public comment through December 1, 2014.

Value of distributed solar energy

Thursday, October 30, 2014

What is the value of distributed solar photovoltaic electric generation?  An investigation by the Maine Public Utilities Commission into this question is ongoing, and will culminate in a report to the state legislature this winter.  At stake are policies and incentives to foster the growth of solar energy in Maine.

Distributed solar generation -- such as solar panels on rooftops and ground-mounted solar arrays -- is a small but rapidly growing sector of the U.S. energy mix.  Solar panels can produce renewable electricity, with no direct fuel use, emissions, or reliance on foreign energy sources.  Customer-sited and other distributed generation resources can also enhance the reliability of the local electric grid, and reduce the need for more expensive transmission and distribution upgrades.  The growing shift to solar energy is also seen as a driver of jobs and economic development.

Rooftop solar photovoltaic panels on a business in Patten, Maine.
In recognition of these benefits, states and the federal government have enacted a variety of policies and incentives for solar power development and use.  These policies include renewable portfolio standards which mandate that utilities source certain amounts of their power from renewable resources, as well as net metering policies which allow a customer to offset its power bill with energy produced from on-site solar panels.

But what is the true value of distributed solar energy resources?  In an effort to find out, in 2014 the Maine Legislature enacted An Act To Support Solar Energy Development in Maine.  This law is also known as the Maine Solar Energy Act, P.L 2013 Chapter 562 (codified at 34-B M.R.S. §§ 3471-3473).  The law expresses the legislative finding that Maine's solar energy resources "constitute a valuable indigenous and renewable energy resource."  Moreover, the law is predicated on the findings that solar energy development is unique in its benefits to and impacts on the climate and the natural environment, and that it can help Maine because it can displace fossil fuel combustion and associated air pollution and greenhouse gas emissions.   The Act set a state policy "to encourage the attraction of appropriately sited development related to solar energy generation, including any additional transmission, distribution and other energy infrastructure needed to transport additional solar energy to market, consistent with all state environmental standards; the permitting and financing of solar energy projects; appropriate utility rate structures; and the siting, permitting, financing and construction of solar energy research and manufacturing facilities for the benefit of all ratepayers."

With these findings noted, the Act directed the Maine Public Utilities Commission to construct a report by February 15, 2015 on the value of distributed solar energy generation in Maine.  In so doing, the Act requires the Commission to develop a method for valuing distributed solar energy generation.   By statute, this method must, at a minimum, account for:
  • the value of the energy;
  • market price effects for energy production;
  • the value of its delivery, generation capacity, transmission capacity and transmission and distribution line losses; and
  • the societal value of the reduced environmental impacts of the energy.
The also Act requires the Commission's report to include a summary of options for increasing investment in or deployment of distributed solar energy generation, which may include recommendations for what Maine should do.

The Commission's investigation is ongoing.  On October 23, 2014, the Commission released a draft of its consultants' initial report, "Maine Distributed Solar Valuation Methodology."  That document is designed as a draft of the methodology to be used in the valuation phase, offered for public review and comment.

The Commission will accept written comments on the draft report until November 12, 2014.  In addition, the Commission and its consultant, Clean Power Research, will hold a work session on the Draft Methodology on October 30, 2014.

Following the first phase to establish the valuation methodology, the Commission and its consultants will conduct a second phase in which the methodology will be applied to Maine to calculate the value of distributed solar generation.  The Commission's work will be summarized in its report to the legislative energy committee, a draft of which the Commission plans to release in January 2015.

North America's largest battery energy storage online

Wednesday, October 29, 2014

A California public utility has brought the largest battery energy storage in North America online.  Funded partially by federal stimulus funds, Southern California Edison's Tehachapi Wind Energy Storage Project is designed to demonstrate the effectiveness of large-scale battery storage systems.

Southern California Edison Company is the largest electricity supply company in Southern California.  As part of the U.S. Department of Energy's implementation of the American Recovery and Reinvestment Act of 2009, the utility won funding to develop a major battery energy storage system (or BESS).  The Tehachapi Wind Energy Storage project consists of an array of lithium-ion batteries capable of storing 32 megawatt-hours, deliverable as an 8 megawatt stream of energy for 4 hours.  The LG Chem batteries rely on the same lithium-ion cells installed in battery packs for General Motors’ Chevrolet Volt electric vehicle, and feature 608,832 individual battery cells arrayed in 10,872 battery modules and 604 battery racks.  Along with two 4MW/4.5MVA smart inverters, the project will be housed in a 6,300 square foot facility sited at SCE's existing Monolith substation.

Of the project's $49,956,528 total budget, half will be paid for by SCE, while federal funds will cover $24,978,264.  In return, the project will examine whether and how the battery energy storage system improves grid performance and helps integrate wind and other large-scale variable energy resourced generation.  Project performance will be measured by 13 specific operational uses, most of which either shift other generation resources to meet peak load and other electricity system needs with stored electricity, or resolve grid stability and capacity concerns that result from the interconnection of variable energy resources.  These uses include: providing voltage support and grid stabilization; decreasing transmission losses; diminishing congestion; increasing system reliability; deferring transmission investment; optimizing renewable-related transmission; providing system capacity and resources adequacy; integrating renewable energy (smoothing); shifting wind generation output; frequency regulation; spin/non-spin replacement reserves; ramp management; and energy price arbitrage.  In addition, the project will demonstrate how lithium-ion battery storage can provide nearly instantaneous back-up capacity, minimizing the need for fossil fuel-powered back-up generation.

Between technological advances and a series of recent policy decisions, battery energy storage could be poised for rapid growth.  For example, in 2011 the Federal Energy Regulatory Commission issued Order No. 755, requiring the grid operators in organized markets to compensate battery energy storage systems and other fast-ramping frequency regulation resources based on the actual service they provide.  Last year's Order No. 784 required public utilities to take into account the speed and accuracy of regulation resources such as batteries.  Meanwhile, batteries are hoped to help balance into the grid large amounts of energy from intermittent renewable resources such as solar and wind projects.

After two years, the Tehachapi Wind Energy Storage Project will have completed its initial demonstration run.  Will the project lead to greater deployment of battery energy storage systems in the U.S.?

Constitution Pipeline environmental impact statement

Monday, October 27, 2014

A 124-mile natural gas transmission pipeline proposed from Pennsylvania to New York has received its final environmental impact statement from federal regulators, finding that while the project would cause some adverse environmental impacts but that mitigation would reduce them to less-than-significant levels.

The proposed Constitution Pipeline is designed connect natural gas supplies in northern Pennsylvania with major northeastern markets.  Proposed by Constitution Pipeline Company, LLC, a group whose investors include WilliamsCabot Oil & Gas, Piedmont Natural Gas, and WGL Holdings, the 30-inch underground pipeline would have a design capacity of 650,000 dekatherms of natural gas per day.  Constitution has pitched the project as a response to natural gas market demands in the New York and the New England areas, and interest from natural gas shippers that require transportation capacity from Susquehanna County, Pennsylvania to the existing Tennessee Gas Pipeline Company LLC (TGP) and Iroquois systems in Schoharie County, New York.

Developing an interstate natural gas pipeline requires a series of federal, state, and local approvals.  Under the federal Natural Gas Act, interstate pipelines must obtain a Certificate of Public Convenience and Necessity from the Federal Energy Regulatory Commission prior to construction.  Constitution started the pre-filing process in April 2012, and filed its certificate application under Section 7(c) of the Natural Gas Act with the FERC on June 13, 2013.

Under the National Environmental Policy Act, federal agencies must analyze and document the environmental effects of proposed federal actions such as issuing a certificate of public convenience and necessity for an interstate pipeline.  For the Constitution Pipeline and its associated Wright Interconnect compressor transfer station, FERC staff evaluated the projects' impacts on natural resources including geology, soils, groundwater, surface water, wetlands, vegetation, wildlife, fisheries, special status species, land use, visual resources, socioeconomics, cultural resources, air quality, noise, and safety.  Staff considered the projects' cumulative impacts along with other past, present, and reasonably foreseeable actions in the projects’ area.  Staff also evaluated over 400 alternatives to the projects, including the "no-action" alternative, system alternatives, major and minor route alternatives, and minor route variations.  In a collaborative effort, FERC staff also collected input from cooperating agencies including the U.S. Environmental Protection Agency, the U.S. Army Corps of Engineers, the Federal Highway Administration, and the New York State Department of Agriculture and Markets. 

FERC staff issued their Final Environmental Impact Statement, or EIS, for the Constitution Pipeline and Wright Interconnect projects on October 24, 2014.  In that document, staff concluded that construction and operation of the Constitution Pipeline and the associated Wright Interconnect would result in some adverse environmental impacts, but these impacts would be reduced to less-than-significant levels with the implementation of mitigation measures proposed by the company and additional measures proposed by FERC.  These mitigation measures include implementing plans for upland erosion control, revegetation, and maintenance plan, protecting wetlands and waterbodies, spill plans for oil and hazardous materials, an organic farm protection plan, and a karst mitigation plan. FERC staff also proposed an environmental inspection and mitigation monitoring program to ensure compliance with all mitigation measures that become conditions of the FERC authorizations and other approvals.

For the Constitution Pipeline project, the EIS represents a relatively favorable recommendation by FERC staff to the Commissioners.  The ultimate decision whether FERC will issue the project a certificate rests solely with the Commissioners themselves, but regulators typically rely heavily on their technical staff's evaluation of environmental impacts.  Likewise, while FERC's final EIS is not necessarily binding on cooperating agencies, they may adopt it if it satisfies their own statutory mandates for environmental reviews.

While the applicants had initially proposed to start construction in 2014, FERC staff acknowledged that "the proposed dates for the start of construction are no longer feasible."  Constitution now proposes to start construction in February of 2015 and continue through the end of 2015, pending receipt of all applicable federal authorizations.  The Federal Energy Regulatory Commission may rule on the projects' certificate applications as early as late November this year.

Canada's Energy East Pipeline Project

Friday, October 24, 2014

A subsidiary of Canadian energy company TransCanada has proposed a crude oil pipeline running 4,600 kilometers from Alberta and Saskatchewan to Saint John, New Brunswick.  The proposed Energy East Pipeline Project would enable Western Canadian crude oil to be shipped east across six Canadian provinces, expanding economic opportunities for refining and export -- but like other major pipeline projects, the Energy East project faces regulatory hurdles.

On March 4, 2014, Energy East Pipeline Ltd., a wholly owned subsidiary of TransCanada Oil Pipelines (Canada) Ltd., proposed the project which entails the conversion of about 3,000 kilometers of existing natural gas pipeline to an oil transportation pipeline, new pipelines in Alberta, Saskatchewan, Manitoba, Ontario, Qu├ębec and New Brunswick, and marine facilities that enable access to other markets by ship.  If built, the $12 billion project could carry up to 1.1 million barrels of crude oil per day.

The major motivation behind the line is the relative surplus of Western Canadian crude oil, including fuel produced from the Alberta oil sands.  While Alberta and Saskatchewan produce substantial oil, relatively little capacity to ship that crude to refineries means relatively low prices for producers.  Meanwhile, refineries in Quebec and Atlantic Canada currently receive 86% of their crude oil from foreign sources.  TransCanada pitches the Energy East project as giving these Eastern Canadian refiners access to "reliable, low-cost Western Canadian crude."  The developer also points to positive economic development impacts, including about 10,000 jobs and an estimated $35 billion added to Canada’s gross domestic product over 40 years, as well as the relative safety of shipping oil by pipeline as opposed to by rail or truck.  Notably, the project also allows TransCanada to make better use of its existing natural gas pipeline system, which has excess unused capacity.

Like the Keystone XL pipeline in the U.S., the Energy East project faces opposition from both local siting concerns and global worries about the environmental impacts of "tar sands" crude production.  Some have also expressed concerns that the project would disrupt natural gas flows to Canadian consumers, although TransCanada has said that it has plans to build more lines to meet any increased demand.

Under Canadian law, interprovincial pipelines are federally regulated by Canada's National Energy Board (NEB).  According to its website, TransCanada expects final regulatory approval in the fourth quarter of 2015, with the project commissioned and placed in service in 2018.  How the regulatory process plays out will affect when -- and whether -- the Energy East pipeline project moves forward.

FERC revokes hydro license over fish passage

Thursday, October 23, 2014

What happens when the owner of a federally licensed hydroelectric project fails to build the fish passage facilities required by its license?  In the recent case of the East Juliette Hydroelectric Project in Georgia, the Federal Energy Regulatory Commission revoked the project's license, ending the owner's right to operate its generating equipment.

The East Juliette Hydroelectric Project is (or was) based around the East Juliette Dam on the Ocmulgee River, a tributary to the Altamaha River.  Built in 1921, the dam is hundreds of miles inland from tidewater -- but nevertheless represents the first passage barrier that anadromous fish, including American shad, encounter on their migrations upstream from the Atlantic Ocean to the Ocmulgee River.  State and federal fisheries agencies have identified restoring access to historical spawning habitat for American shad as one of their highest priorities for the region.

Since 1995, the East Juliette Hydroelectric Project has been owned by Eastern Hydroelectric Corporation.  The project facilities include a 20-foot-high, 1,230-foot-long concrete gravity dam that creates a 78-acre reservoir with a storage capacity of 418 acre-feet, and two powerhouses with a total installed capacity of 687 kW.

In 2002, the Federal Energy Regulatory Commission amended the project's license to authorize the construction of a new powerhouse and 1,200 kW generating unit.  As part of that amendment, the FERC added language to the project's license requiring the licensee to install new fish passage facilities at the East Juliette Dam.  Similar conditions were imposed by the Georgia Department of Natural Resources as part of its water quality certification for the amendment.

According to the recent FERC order, while the licensee proposed a plan to construct fish lift at the dam, it ultimately did not follow through with its plan.  At several points over the past 5 years, FERC staff licensee directed the licensee to comply or else face civil penalties, an order to cease operation of the project, or revocation of the license pursuant to section 31 of the Federal Power Act.

Under section 31(b) of the Federal Power Act, after notice and an opportunity for an evidentiary hearing, the FERC may issue an order revoking a license, where the licensee is found have knowingly violated a final order after having been given reasonable time to comply fully with that order.  In Eastern Hydro's case, FERC found that despite 12 years of intensive efforts by its own staff and other agencies, "these efforts have met with steady resistance from the licensee."

Ultimately, the FERC found that Eastern Hydro knowingly violated its compliance order and that it was given a reasonable time to comply with the order before FERC commenced the license revocation proceeding. As a result, FERC revoked Eastern Hydro’s license for the East Juliette Project.

While environmental conservation groups asked FERC to require the licensee to remove all project facilities that it owns, FERC declined to do so.  Instead, the FERC order requires that Eastern Hydro disable all of the project’s generating equipment to prevent operation of the project in violation of section 23(b)(1) of the Federal Power Act.  Following revocation of the license, the FERC's jurisdiction will end, and authority over the site will pass to the State of Georgia’s dam regulatory authorities.

The East Juliette case illustrates some of the most severe consequences of failure to comply with FERC hydropower licenses.  Without a license, the project cannot generate electricity, thus depriving the project of much of its value.

FERC settles 3rd Southwest blackout case

Wednesday, October 22, 2014

A California public utility has settled claims by federal electricity regulators related to the September 8, 2011, blackout in the southwestern United States.  Following an investigation by the Federal Energy Regulatory Commission (FERC) and electric reliability organization North American Electric Reliability Corporation (NERC), Southern California Edison Company has agreed to pay a $650,000 civil penalty and undertake additional compliance actions.

According to previous investigative reports, the 2011 blackout started when a 500-kilovolt transmission line owned by Arizona Public Service Company tripped out of service, causing cascading power outages through automatic load shedding as other equipment quickly overloaded.  In the end, the outage affected over 5 million customers, shedding 7,835 megawatts of peak demand and over 30,000 megawatt-hours of energy.

Following the blackouts, both FERC and NERC launched investigations into what had happened.  As a federal agency, FERC has regulatory authority over the reliability of the electric bulk power systemNERC is a not-for-profit international regulatory authority whose mission is to ensure the reliability of the bulk power system in North America, and has been designated by FERC as the nation's electric reliability organization.

In July, FERC announced a $3.25 million settlement with Arizona Public Service.  In August, FERC announced a $12 million settlement with California's Imperial Irrigation District.

Today, FERC announced that it has approved a stipulation and consent agreement between FERC’s Office of Enforcement, NERC, and Southern California Edison Company.  Through a joint investigation, FERC Office of Enforcement staff and NERC determined that the utility violated the Protection and Control group of NERC's Reliability Standards.  In particular, the investigation found that Southern California Edison failed to adequately coordinate its intertie separation scheme at the San Onofre nuclear generating station switchyard with certain other protection systems.  Enforcement staff and NERC found this violation to be a serious deficiency that undermined reliable operation of the Bulk Power System.

Through the settlement, Southern California Edison will pay a civil penalty of $650,000.  Of this penalty, $125,000 will be paid to the U.S. Treasury, $125,000 will be paid to NERC, and $400,000 will be invested in additional reliability enhancement measures.

With Southern California Edison's case resolved, all three of the vertically integrated utilities known to be implicated by FERC's investigation have now settled their alleged violations by agreeing to pay penalties.  Will further penalties be forthcoming?  Will the penalties and ordered reliability measures keep the lights on the next time the grid is stressed?

Polar vortex caused energy price spikes, says FERC staff

Monday, October 20, 2014

Why did energy prices rise during last winter's extremely cold "polar vortex" weather?  A recent report by federal regulators suggests that inadequate infrastructure is largely to blame, while finding no evidence of widespread or sustained market manipulation.

A recent winter in New England: cold ocean, cold snow.  Must high energy prices follow?

The 2013 - 2014 winter season brought prolonged and unusually cold weather events in much of the United States.  While the nation's major electric grids were generally able to maintain reliable operation, prices for natural gas and electricity spiked to unprecedented levels.  Bottlenecks on interstate natural gas pipelines limited the amount of gas flowing into regions like the Northeast, while demand for gas for heating and electric power generation increased beyond the constrained pipelines' capacity.  This imbalance of supply and demand for gas led to extremely high prices for gas as well as for electricity, because the price of natural gas often sets the price for power.  Compounding the problem, some generators could not buy enough gas to operate, while others experienced outages due to equipment failure and frozen coal piles.  In some regions, generators amounting to 30 percent of electric load faced forced outages.

As an immediate response, the Federal Energy Regulatory Commission took actions including changes to rules in the PJM, New York ISO and California ISO electricity markets, the Commission's first use of its emergency powers under the Interstate Commerce Act to direct Enterprise TE Products Pipeline to temporarily provide priority treatment to certain propane shipments, and approving a Winter Reliability Program in the ISO New England region.

According to a recently released report by the staff of the Federal Energy Regulatory Commission, the FERC Office of Enforcement also launched investigations into whether market participant behavior influenced regulated energy prices.  In addition to the Commission's enforcement arm's regular surveillance of natural gas and electric markets for market manipulation and other improper conduct, the past winter's extreme price spikes prompted a closer look by the Office of Enforcement to determine if market manipulation was behind the historically high natural gas and electric prices.

On October 16, FERC’s enforcement staff reported that it found "no evidence of widespread or sustained market manipulation."  Enforcement staff said it reached its conclusions after an extensive review and data analysis related to gas trading behavior, allegations received through the FERC hotline, generator offer behavior and outage behavior.

However, enforcement staff reported that three non-public investigations remain pending.  At stake is whether any market participant was involved with the formation of a single monthly natural gas index to benefit its financial derivative positions, as well as whether certain generators improperly took advantage of constrained conditions in the electric markets by bidding in a way that increased their uplift payments.

Expect these enforcement investigations to continue, either to an informal resolution or a public enforcement process.  With former Office of Enforcement head Norman Bay as the newest FERC Commissioner, FERC's enforcement arm appears to be growing in influence.  Meanwhile, the coming winter may yet again test the nation's electricity and natural gas infrastructure.  What will the 2014 - 2015 winter hold, in terms of energy reliability, pricing, and enforcement actions?

Solar bonds: SolarCity launches first US public debt offering

Wednesday, October 15, 2014

Could publicly offered solar bonds play a significant role in financing solar photovoltaic projects?

Solar energy company SolarCity Corporation appears to think so, as this morning it filed a registration statement with the U.S. Securities and Exchange Commission to issue up to $200 million in solar bonds.  SolarCity describes the move as "the nation’s first registered public offering of solar bonds."  What does SolarCity's solar bond offering mean for solar energy?

Solar panels on a residential rooftop in Massachusetts.

By some metrics, SolarCity is the largest developer of residential solar photovoltaic projects in the U.S.  The company says it is currently providing more than one out of every three new solar power systems in the U.S., and notes that it "installed more residential solar in the second quarter of 2014 than its next 50 competitors combined."  While SolarCity develops projects under several financial models, its typically installs rooftop solar panels at its customers' sites with no upfront costs to the customer, who then pays the company every month for leasing the facilities or for the electricity it uses.  These long-term contracts create more stable ongoing revenues for SolarCity compared to those experienced by developers of turnkey projects who may end their relationship after the project is commissioned.

SolarCity's model has proved attractive to capital, as it has been involved with financing the installation of approximately $5 billion in renewable energy assets.  Much of the capital SolarCity needs to develop these projects has come from investments from major banks and corporations including US Bancorp and Google Inc., as well as individuals owning shares of the company's stock (traded as SCTY).

SolarCity has also turned to debt offerings, making three private placements of solar bonds in the last year.  Generally speaking, SolarCity will pay returns on the bonds using income generated from customers' monthly payments.  Because this income stream is both relatively stable and predictable, it should enable repayment of the bonds plus a steady yield.

But no company has previously publicly offered solar bonds of this type in the U.S.  SolarCity thus views its publicly offered solar bonding model as unique, in that it gives individual investors access to new investment opportunities -- and in turn, it may give SolarCity access to a whole lot more money -- up to $200 million in this round, with the prospect of more to come.

Under SolarCity's new offering, investors will be able to purchase solar bonds for as little as $1,000, with maturities ranging from one year to seven years and interest rates of up to 4 percent.  The relatively short maturity of these bonds, compared to those previously offered to institutional investors, helps reduce the risk that during the bonds' lives utility rates will change in a way that hurts their economics.

The company notes that solar bonds will be available to all U.S. investors who are at least 18 years old and meet SolarCity’s eligibility requirements, with no fees for purchase.  Indeed, the relatively low $1,000 minimum investment for this solar bond offering highlights SolarCity's strategy of targeting the millions of small or "retail" investors.  To facilitate these individual investors' access to the bonds, the company launched a new online investment site (solarbonds.solarcity.com).

How will the new solar bond offering affect SolarCity and the pace of solar development in the US?  With a market capitalization of $4.2 billion, SolarCity is relatively large compared to the $200 million that it may raise pursuant to the current public bond offering.  Nevertheless, individual investors' appetite for opportunities to participate in solar and other renewable energy projects may be significant enough that more bond offerings will follow on the heels of this one.  As the Brookings-Rockefeller Project on State and Metropolitan Innovation found in an April 2014 report, Clean Energy FinanceThrough the Bond Market:A New Option for Progress, "Bond finance holds tremendous potential for clean energy investment, at levels in the tens of billions of dollars in the next several years."  If SolarCity is indeed successful in attractive individual bond investors, other solar developers like First Solar, Inc. and Sunrun may soon follow suit with solar bond offerings of their own.

USDA awards $68 million for energy projects

Thursday, October 9, 2014

The U.S. Department of Agriculture has announced $68 million in grants and loan guarantees for renewable energy and energy efficiency projects.  The latest round of awards under the agency's Rural Development arm's Rural Energy for America Program will support 540 projects at farm and rural business sites across the country.

Since its creation in the 2008 Farm Bill, REAP has supported more than 8,800 renewable energy and energy efficiency projects nationwide with over $276 million in grants and $268 million in loan guarantees to agricultural producers and rural small business owners.  Eligible agricultural producers and rural small businesses may use REAP funds to make energy efficiency improvements or install renewable energy systems including solar, wind, biomass and anaerobic digesters, small hydroelectric, ocean energy, hydrogen, and geothermal projects.  (For looks at previous REAP winners, check out these posts from 2011 and 2013.)

In this year's REAP funding round, USDA awarded about $68 million in investment support.  Of this, $12,376,548 will come in the form of grants, while $56,449,244 will come as loan guarantees.  While most grants are under $100,000 per project (with some below $10,000), there were some larger grant awards: for example, a biomass anaerobic digester in California won $290,000, an off-grid solar project in Hawaii won $123,338, and a direct use geothermal heat pump in Oklahoma won $133,250. Of the loan guarantees, $55.3 million will go to support 22 solar photovoltaic projects in North Carolina, mostly ranging between 2 megawatts and 5 megawatts per project. 

In each case, funding is contingent upon the recipients meeting the terms of the loan or grant agreement. USDA's hope is that these grants and loan guarantees will enable American agricultural producers and rural small business owners to reduce their energy costs.

REAP was reauthorized by the 2014 Farm Bill, so expect USDA Rural Development to solicit more REAP projects later this year.  While not all sites may qualify, USDA's definition of eligibility is more broad than many assume.  The Preti Flaherty team helps our clients understand how to benefit from REAP funding and other incentive programs for renewable energy and energy efficiency.  Contact Todd Griset to learn more.

ISO New England's Winter Reliability Program 2014-2015

Wednesday, October 8, 2014

Keeping the lights on is what electric grid operators do around the clock – but challenges in New England are leading its grid operator to prepare for a winter when the availability of affordable electricity may be challenged.  In preparation, ISO New England, Inc. has received federal approval for a new Winter Reliability Program for the 2014-2015 winter season.

Winter is coming.
ISO New England is the federally-designated regional transmission organization for almost all of New England.  In this role, it is responsible for planning and operating electricity markets to balance supply and demand in real time.   

The grid operator first turned to a Winter Reliability Program in 2013.  ISO New England projected that a limited supply of natural gas and the retirements of several major generating plants would lead to a shortage of about 2 million megawatt-hours of energy during the winter months.  To insure against this gap, the grid operator held a competitive process to procure up to 2.4 million megawatt-hours of energy for the winter season, from a combination of oil-fired generators, dual-fuel generators, and demand response assets.  In exchange for their commitment to provide power when called upon, the selected generators and demand response assets received payments regardless of whether they were actually needed.

In ISO-NE's eyes, the 2013-2014 Winter Reliability Program proved essential in maintaining reliability during the “polar vortex” and other unusually cold conditions.  After adjusting for resource unavailability, the final cost of the 2013/2014 program was approximately $66 million, which came in below the original estimates of about $75 million.

While last year’s program was intended to be a one-time solution to bridge a reliability gap, this summer ISO-NE and regional stakeholder body NEPOOL identified additional challenges for the coming winter.  Specifically, more severe pipeline constraints, difficulty replenishing oil inventories, and large-scale generator retirements continue to threaten the coming winter's reliability and expose consumers to the risk of price spikes.

As a result, ISO-NE asked the Federal Energy Regulatory Commission to approve another program to mitigate reliability concerns for the 2014-2015 winter.  The new program, which the FERC accepted last month, combines features of last year’s program with further modifications.  For example, the new demand-response component is much the same as in last year’s program, while permanent rules related to auditing dual-fuel generators and the partial elimination of higher-cost fuel requirements are based on similar features in last winter’s program.

On the other hand, the new program has been modified as a result of several market changes that will be in effect prior to winter 2014/2015 as well as the FERC's clarification of what generators must do to procure adequate fuel for their expected run times.  The new program also adds a liquefied natural gas (LNG) component to improve fuel neutrality, and changes the basis for compensation from upfront inventory to actual unused inventory at the end of the winter.  While participants in last year's program were paid on an as-bid basis, the new program provides compensation for the fuel inventory and demand response programs based on a set rate of $18 per barrel.  This $18 price is designed to represent the carrying costs, price risk, availability cost and liquidity risk of the last resource needed to meet a cumulative inventory of 3.5 million barrels of oil.

The program also includes incentives for commissioning duel-fuel capacity: the ability to run on either oil or gas. Generators that have not operated on oil since at least December 1, 2011, and that demonstrate a plan for commissioning, or recommissioning a mothballed dual-fuel unit, by December 1, 2016, will be eligible for compensation to offset some of the associated costs.

The new program is moving forward.  On September 9, 2014, the FERC issued an order accepting the region’s proposed 2014/2015 Winter Reliability Program.  In the order, FERC requires ISO-NE to initiate a stakeholder process by January 1, 2015, to develop a proposal to address reliability concerns for the 2015/2016 winter and future winters, as necessary, to schedule meetings and submit progress reports, and to include certain analysis and recommendations in its Annual Markets Report.

For the proposed 2014/2015 program, the Analysis Group estimated costs for the separate components: the maximum cost of the demand response component would be about $2.4 million; the cost of the unused oil inventory and LNG contract volume components would be based on how much fuel remains unused, and assuming, at the high end, that 100% of the targeted amount of fuel is unused, the estimated cost would be $82.6 million; and the maximum cost for the dual-fuel commissioning program is estimated to be $12.9 million for units that commission by December 1, 2015.  The dual-fuel auditing provisions are estimated to cost a maximum, annually, of $7 million.

Consistent with the Commission’s order on the first winter program, the costs will be allocated to real-time load obligation, which is paid by load-serving entities, rather than to regional network load, which is paid by transmission owners.

Requests to Participate in the Oil Program, LNG Program, or Demand Response Program were due to ISO New England Customer Service by October 1, 2014. Dual Fuel Commissioning Requests are due by December 1, 2014

Exporting compressed natural gas from the US

Monday, October 6, 2014

In a divided opinion, the Federal Energy Regulatory Commission has found that it does not have jurisdiction over facilities proposed by Emera CNG, LLC to compress natural gas for export to the Bahamas by ship.

Natural gas is an important fuel used globally for electric power generation, heating, and industry.  Throughout most of the U.S., an abundant supply of natural gas means domestic pricing for gas is lower than overseas.  This creates a potentially profitable opportunity to export natural gas from the U.S., if regulatory conditions allow.

Natural gas can be exported by pipeline as a gas, or by truck or ship as either compressed natural gas (CNG) or liquefied natural gas (LNG). Liquefying natural gas enables massive quantities of gas to be transported anywhere in the world, but requires the construction of expensive facilities to liquefy and regasify the fuel.  The federal Natural Gas Act gives the Federal Energy Regulatory Commission jurisdiction over the siting and construction of most LNG facilities in the U.S., and authorizes FERC to issue certificates of public convenience and necessity for LNG facilities engaged in interstate natural gas transportation by pipeline.  For example, Dominion Cove Point LNG, LP recently secured the FERC's approval for its Cove Point LNG export facility.

By comparison, compressing natural gas to high pressures is a relatively lower-cost way to improve the energy density of the fuel and reduce its transportation costs, albeit not to the degree of LNG.  CNG exports are already happening, and may soon increase.

Emera recently proposed to construct a CNG compression and truck-loading facility at the existing Port of Palm Beach in Riviera Beach, Florida, in order to export CNG to the Commonwealth of the Bahamas.  At the site, Emera would draw natural gas from the Riviera Lateral, a pipeline owned and operated by Peninsula Pipeline Company.  Emera would then dehydrate and compress the gas to fill containers that would be loaded onto trucks.  The proposed CNG facility would initially be capable of loading 6 million cubic feet per day (MMcf/d) of CNG, with expansion capabilities up to 25 MMcf/d.  Once loaded onto trucks, Emera will haul the containers to a berth about a quarter mile away at the Port of Palm Beach.  At the port, the containers will be loaded onto a roll-on/roll-off ocean-going carrier and shipped to Freeport, Grand Bahama Island, where the containers would be unloaded, the CNG decompressed and injected into a pipeline for transport to electric generation plants owned and operated by Emera affiliate Grand Bahama Power Company and other customers on Grand Bahama Island.

To reduce regulatory uncertainty, Emera petitioned the Federal Energy Regulatory Commission for a declaratory order that its project will not be subject to the Commission’s jurisdiction under the Natural Gas Act.  Last month, a majority of the FERC Commissioners found that the construction and operation of the CNG facility described by Emera would not be subject to FERC's authority over natural gas exports under the Natural Gas Act.  In particular, the majority opinion held that Emera’s facilities to compress and load CNG onto trucks are not jurisdictional export facilities.

In reaching this conclusion, the majority found that the proposed CNG facilities were unlike the border-crossing pipelines and coastal LNG terminals that the Commission traditionally has regulated under section 3 as import/export facilities, and more like existing, unregulated facilities that deliver LNG into trucks which are subsequently driven across the border into Canada or Mexico.  Indeed, the opinion cites the example of Xpress Natural Gas, which has a CNG plant in Maine that receives gas from an interstate pipeline and loads CNG containers onto trucks for delivery to customers in Canada and in New England.  The Commission does not regulate the CNG facility under either section 3 or 7, nor does it exercise jurisdiction over the trucks’ passage across the border under section 3.

The majority opinion similarly found that because Emera said that all of the natural gas to be compressed at Emera’s planned facility will be exported in foreign commerce to the Commonwealth of the Bahamas, the Commission’s section 7 jurisdiction over transportation and sales of gas for resale in interstate commerce would not be implicated by Emera’s proposal.

Notably, new Commissioner Norman Bay dissented from the majority opinion.  Noting language in section 3 of the Natural Gas Act giving FERC jurisdiction over natural gas exports, Commissioner Bay's dissent describes the majority’s argument as that because the CNG will leave Emera’s facility by truck and travel a quarter of mile before being loaded onto ocean-going carriers for export – rather than by a pipeline running across a border or to a tanker – the facility is not an “export facility” under section 3 of the Natural Gas Act. In Commissioner Bay's words, "It cannot be that the Commission’s jurisdiction turns on this 440-yard truck journey."

With FERC regulation under the Natural Gas Act behind it, Emera will still need other approvals to export CNG; for example, Emera has filed an application with the U.S. Department of Energy's Office of Fossil Energy for authorization under Section 3 of the Natural Gas Act for export of natural gas.

What role will CNG exports play in the U.S.'s energy future?

Washington tidal energy project cancelled

Thursday, October 2, 2014

A tidal energy project proposed off the Washington coast will be scrapped due to cost overruns, according to the project developer.

Public Utility District No. 1 of Snohomish County's proposed Admiralty Inlet Pilot Tidal Project was envisioned as a temporary, experimental project to evaluate the commercial viability of tidal energy development in Puget Sound.  The 600-kilowatt hydrokinetic project would have generated electricity from the force of water moving through turbines mounted in tidal currents.  Earlier this year, the project won a pilot license from the Federal Energy Regulatory Commission, making it among the first tidal projects to qualify for the Commission's pilot licensure program.

But the estimated costs of the project were significant relative to its projected energy output.  Since it was first proposed in 2006, the Public Utility District estimated that the project would cost $20 million to build.  Based on these numbers, the Commission estimated that the levelized annual cost of operating the project would be about $1,848,294.  Dividing this by the project's expected production of energy, the power could cost $7,574.98 per megawatt-hour of energy generated -- an amount over 250 times higher than the estimated $30/MWh cost of alternative power.

Nevertheless, the PUD had designed the project's finances to avoid the need for ratepayer financing.  Rather, the project relied on funding from federal grants and in-kind contributions from project partners, as well as some money from the sale of excess renewable energy credits from the District's wind power projects.  To date, the District has invested about $3.5 million in the effort, over the past 8 years.

With the FERC license in hand, the District moved forward to solicit bids for project engineering and construction.  When those bids came in, the District realized the project would likely cost closer to $37 million, or $17 million more than previously expected.  According to a September 30 announcement by the Public Utility District, the District tried to seek more funding for the project from the U.S. Department of Energy and other project partners, but did not succeed.  As a result, the District has announced that it will not move forward with the project.

While the District is no longer actively pursuing the Admiralty Inlet Pilot Tidal Project, some other developer may try to pick up where the District left off.  Indeed, the District's announcement notes that the project "remains worthwhile to pursue on behalf of the nation to further the potential development of marine renewable energy."  Will another developer seek to advance the Admiralty Inlet Pilot Tidal Project?  Will other tidal current and marine hydrokinetic projects be developed given the challenges of ocean energy project economics?

Feds approve Quebec-to-NY power line

Wednesday, October 1, 2014

A proposed electric transmission line connecting Quebec to New York will receive a key federal approval, according to the U.S. Department of Energy.  The Energy Department's decision to issue a Presidential permit to Champlain Hudson Power Express, Inc. focuses attention on the nation's international trade in electricity, and may suggest increased reliance on power imports.

Pursuant to two Executive Orders -- EO 10485 (September 9, 1953), as amended by EO 12038 (February 7, 1978) -- no electricity transmission facilities may be constructed, operated, maintained, or connected at the U.S. border without first obtaining a Presidential permit from the Department of Energy.  In 2010, Champlain Hudson Power Express, Inc. applied to DOE for a Presidential permit to construct, operate, maintain, and connect a 1,000-megawatt (MW), high-voltage direct current (HVDC) merchant electric power transmission system across the U.S./Canada border.

As currently envisioned, the Champlain Hudson Power Express project would cross the U.S./Canada border near the town of Champlain in northeastern New York State.  From there, the line would extend southward about 336 miles to the Consolidated Edison Company of New York, Inc. Rainey substation in Queens, New York.  Notably, the aquatic portions of the transmission line would primarily be buried in sediments of Lake Champlain and the Hudson, Harlem, and East rivers, while the terrestrial portions of the line would be buried within existing roadway and railroad rights-of-way.

The Department may issue or amend a permit if it determines that the permit is in the public interest and after obtaining favorable recommendations from the U.S. Departments of State and Defense.  In making this determination, DOE considers factors including the proposed project's potential impacts on the environment and electricity reliability.

In the case of the Champlain Hudson Power Express, the Department of Energy's record of decision states that its decision to grant the Presidential permit was based on "consideration of the potential environmental impacts, impacts on the reliability of the U.S. electric power supply system under normal and contingency conditions, and the favorable recommendations of the U.S. Departments of State and Defense."  With the Presidential permit in hand, the project developer will be one step closer to success -- but additional steps remain, including both securing regulatory approvals and completing the commercial arrangements necessary for project development.

If the project is built, New York consumers may soon have increased access to electricity generated from Canadian hydropower and other resources across their northern border.  Will the U.S. soon import more power from Canada?  If so, how much, and at what cost?  How will market forces and regulatory agendas combine to affect Canadian exports of electricity to the U.S.?

FERC approves Maryland LNG project

Tuesday, September 30, 2014

A proposed Maryland natural gas liquefaction facility won a key federal approval yesterday, as the Federal Energy Regulatory Commission authorized Dominion Cove Point LNG, LP to build the Cove Point Liquefaction Project in Calvert County, Maryland, and related facilities at an existing compressor station and at metering and regulating sites in Virginia.

Natural gas is an important fuel used globally for electric power generation and heating.  While pipelines offer the most efficient way to transport large volumes of natural gas, liquefied natural gas or LNG can more easily be transported by ship to distant markets.  As US natural gas production has increased in recent years, so too has interest in building facilities to liquefy gas for export or other use.

Under Section 3 of the Natural Gas Act, the Federal Energy Regulatory Commission or FERC authorizes the siting and construction of onshore and near-shore LNG import or export facilities. Section 7 of the Natural Gas Act authorizes FERC to issue certificates of public convenience and necessity for LNG facilities engaged in interstate natural gas transportation by pipeline.

On April 1, 2013, Dominion applied to the FERC for approval under Section 3 of the Natural Gas Act to site, construct, and operate the Cove Point Liquefaction Project for the liquefaction and export of domestically-produced natural gas at Dominion’s existing LNG import terminal in Calvert County, Maryland.  Dominion also requested authority under section 7(c) of the Natural Gas Act to construct and operate facilities at its existing compressor station and metering and regulating sites in Virginia.  Collectively, the project will enable Dominion to transport up to 860,000 dekatherms per day of natural gas form existing pipeline interconnects near the west end of the Cove Point Pipeline to the Cove Point terminal for the export of up to 5.75 metric tons of liquefied natural gas per year.

Dominion's requests triggered a case that stretched for over two years of consideration.  During this time, the FERC heard from more than 140 speakers at three public meetings related to an assessment of the project's environmental impacts, and received more than 650 comments from the public and federal, state and local agencies on the application.  In the end, the FERC determined that Dominion’s proposal, as approved with 79 specific conditions required by the Commission’sauthorization, will minimize potential adverse impacts on landowners and the environment.

According to the FERC, Dominion proposes to complete construction of the liquefaction project so that facilities may start service in June 2017.  Notably, the U.S. Department of Energy has already approved Dominion Cove Point’s export of gas to both Free Trade Agreement and non-Free Trade Agreement countries.

The same economic forces motivating the Dominion project support other proposed LNG export projects.  Indeed, FERC has approved three other LNG export projects, all in the Gulf of Mexico -- the Sabine Pass Liquefaction Project, the Freeport LNG Project, and the Cameron LNG Project -- and 14 more LNG export proposals remain pending.

FERC Order 676-H adopts NAESB standards

Monday, September 22, 2014

Last week the Federal Energy Regulatory Commission issued Order No. 676-H, adopting and incorporating into its regulations most of the latest version of a set public utility business practice standards and communications protocols developed by the North American Energy Standards Board (NAESB).  While most of the NAESB standards will now become mandatory and enforceable, to enable smart grid innovation the Commission posted NAESB's five Smart Grid standards as non-binding guidance.

Industry standards enable cooperation and communication, and can lead to more efficient and competitive markets.  Formally known as Version 003 of the Standards for Business Practices and Communication Protocols for Public Utilities adopted by NAESB's Wholesale Electric Quadrant (WEQ), the newly adopted standards represent the latest evolution of NAESB's consensus-based standards for public utilities.  NAESB is an ANSI-accredited non-profit standards development organization formed to develop and promote business practice standards that promote a seamless marketplace for wholesale and retail natural gas and electricity. Since issuing Order No. 676 in 2006, the FERC has incorporated elements of NAESB's standards into its regulations.

While the FERC made most of the NAESB standards mandatory, it decided to include NAESB's smart grid standards only "informationally, as guidance."  While FERC noted that the smart grid standards have value and should be adopted by public utilities, it ultimately agreed with utility trade group Edison Electric Institute and the ISO/RTO Council that NAESB's five Smart Grid standards should neither be incorporated into formal federal regulation nor be enforceable and mandatory.  Notably, as prepared by NAESB the Smart Grid standards are meant to be optional and informative, not prescriptive or restrictive, and could prove difficult to enforce.

Thus to "encourage further developments in interoperability, technological innovation and standardization", the FERC chose to include NAESB's five smart grid standards in Order No. 676-H as guidance, but not to incorporate them into its formal, enforceable regulations.

Through Order No. 676-H, the FERC hopes to improve business practices and interoperability among public utilities.  The order also shows an intent to foster smart grid technologies, without stifling their development through overly prescriptive or unenforceable regulations.  Will Order 676-H usher in a new era of smart grid and utility cooperation?

FERC Order 800 eases hydropower regulations

Friday, September 19, 2014

The Federal Energy Regulatory Commission has issued an order streamlining its regulations for some small hydropower projects.  FERC Order No. 800 conforms the Commission's regulations to the Hydropower Regulatory Efficiency Act of 2013.  Between Order 800 and the Hydropower Efficiency Act, regulatory processes for developing some small hydropower projects have recently become easier.

Hydropower is one of the nation's most abundant sources of renewable energy -- and yet about 97 percent of the estimated 80,000 dams in the United States do not generate electricity.  While not all are great candidates for hydropower, some non-power dam sites offer significant opportunities to generate renewable electricity with minimal incremental environmental impact.

Congress had these dams in mind when it enacted the Hydropower Efficiency Act on August 9, 2013.  To encourage the use of these dams for electric generation, the Act aims to reduce the costs and regulatory burden on project developers during the project study and licensing stages.  In particular, the Act amended previous statutory provisions covering both preliminary permits and projects that are exempt from licensing.  These statutory changes prompted FERC to update its regulations to conform to the Hydropower Efficiency Act.

Order No. 800 formalizes the Commission's compliance procedures in its revised regulations on preliminary permits, small conduit hydroelectric facilities, and small hydroelectric power projects, and in a new subpart on qualifying conduit hydropower facilities.  Key changes include:
  • New regulations recognize the Commission's new statutory authority to extend a preliminary permit once for not more than two additional years, allowing permittees up to 5 total years to complete their feasibility studies without facing possible competition for the site from others.
  • Exempt small conduit hydroelectric facilities may now be located on federal lands, and all exempt small conduit hydroelectric facilities may now have an installed capacity of up to 40 megawatts.  Previously, non-municipal small conduit exemptions were limited to 15 megawatts.
  • Exempt small hydroelectric power project facilities may now have an installed capacity of up to 10 megawatts.
  • Qualifying conduit hydropower facilities, which do not require licensure under the Federal Power Act but do require the filing with FERC of a notice of intent to construct, are now covered under the regulations.
While several of these categories of facility appear similar, each is defined separately by statute.
  • A small conduit hydroelectric facility, as defined in section 30 of the Federal Power Act, is an existing or proposed hydroelectric facility that utilizes for electric power generation the hydroelectric potential of a conduit, or any tunnel, canal, pipeline, aqueduct, flume, ditch, or similar manmade water conveyance that is operated for the distribution of water for agricultural, municipal, or industrial consumption and not primarily for the generation of electricity.
  • A small hydroelectric power project, as defined in the Public Utilities Regulatory Policies Act of 1978 (PURPA), is a project that utilizes for electric generation the water potential of either an existing non-federal dam or a natural water feature (e.g., natural lake, water fall, gradient of a stream, etc.) without the need for a dam or man-made impoundment.
  • A qualifying conduit hydropower facility, as defined in the Hydropower Efficiency Act, is a facility that meets the following qualifying criteria: (1) the facility would be constructed, operated, or maintained for the generation of electric power using only the hydroelectric potential of a non-federally owned conduit, without the need for a dam or impoundment; (2) the facility would have a total installed capacity that does not exceed 5 MW; and (3) the facility is not licensed under, or exempted from, the license requirements in Part I of the FPA on or before the date of enactment of the Hydropower Efficiency Act (i.e., August 9, 2013).
In Order 800, the Commission is merely formalizing several practices it has already adopted since the enactment of the Hydropower Efficiency Act.  For example, the Commission has issued two-year extensions to preliminary permit holders, granted a small conduit exemption on federal lands, and issued conduit facility determinations on whether proposed projects are qualifying conduit hydropower facilities.  Nevertheless, the Act and Order No. 800 work together to offer an easier regulatory path for developers of small hydropower projects without new dams.

Federal grants support microgrids

Thursday, September 18, 2014

The U.S. Department of Energy has awarded over $8 million in funding for 7 microgrid projects.  Will microgrids play an increasing role in the U.S. electricity industry?

Solar photovoltaic panels can serve as distributed generation for microgrids.


Microgrids -- localized grids capable of operating as energy islands using distributed generation, energy storage, and distribution wires, as well as able to connect to the broader utility grid -- can offer participants and society at large significant value.  These benefits can include increased reliability against storm damage and infrastructure damage, reduced emissions of carbon and other pollutants, and reduced costs.

The Energy Department runs a portfolio of microgrid activities ranging from direct research and development to building community support.  Most recently, the Department announced over $8 million in grant funding to support 7 microgrid projects.  The Department selected these projects based on their ability to develop advanced microgrid controllers and system designs for microgrids less than 10 megawatts:

  • ALSTOM Grid, Inc.: about $1.2 million to research and design community microgrid systems for the Philadelphia Industrial Development Corporation and the Philadelphia Water Department, using portions of the former Philadelphia Navy Yard. 
  • Burr Energy, LLC: about $1.2 million to design and build a resilient microgrid to allow the Olney, Maryland Town Center to operate for weeks in the event of a regional outage, and a second microgrid for multi-use commercial development in Maryland. 
  • Commonwealth Edison Company (ComEd): about $1.2 million to develop and test a commercial-grade microgrid controller capable of controlling a system of two or more interconnected microgrids, serving civic infrastructure including police and fire department headquarters, transportation and healthcare facilities, and private residences. 
  • Electric Power Research Institute (EPRI): about $1.2 million to develop a commercially-viable standardized microgrid controller that can allow a community to provide continuous power for critical loads. 
  • General Electric Company (GE): about $1.2 million to develop an enhanced microgrid control system in Potsdam, New York, by adding new capabilities, such as frequency regulation. 
  • TDX Power, Inc.: about $1.2 million to engineer, design, simulate, and build a microgrid control system on remote Saint Paul Island, an island located in the Bering Sea off mainland Alaska. 
  • The University of California, Irvine (UCI): about $1.2 million for the Advanced Power and Energy Program at UCI to develop and test a generic microgrid controller intended to be readily adapted to manage a range of microgrid systems, and supporting the development of open source industry standards.

Each project also includes an awardee cost share ranging from 20 percent to about 50 percent.  Will the DOE funds lead to better and more widely adopted microgrids?

New generation in 2014 mostly gas, solar, wind

Wednesday, September 17, 2014

Most new power plants placed in service in the first half of 2014 are powered by natural gas, with new solar and wind capacity coming in second and third, respectively, according to the U.S. Energy Information Administration.  Meanwhile, no new coal-fired electric generating capacity was added during that period.

Source: U.S. Energy Information Administration, Electric Power Monthly, August 2014 edition with June 2014 data
Note: Data include facilities with a net summer capacity of 1 MW and above only.
From January through June 2014, EIA data shows the U.S. added 4,350 megawatts of new utility-scale generating capacity. Combined-cycle natural gas plants contributed 2,179 MW of new capacity.  Of this, over half is located at Florida Power & Light's Riviera Beach Next Generation Clean Energy Center in Florida.  New combustion turbine plants added another 131 MW.  In all, natural gas powers over 53% of new capacity coming online in the first half of 2014.  Most of the nation has access to low cost natural gas, which offers significant environmental benefits over other fossil fuels like coal and oil.

Solar projects came in second, with 1,146 MW of new capacity coming online.  Solar capacity is growing quickly, with an increase of almost 70% in new capacity added over the same period in 2013.  Nearly 75% of this solar capacity is located in California, with most of the rest in Arizona, Nevada, and Massachusetts.  Notably, the EIA's data only covers utility-scale projects; it omits most rooftop solar projects and any other solar capacity additions below 1 MW in size.

New wind capacity came in third, with 675 MW added.  Most of the new capacity is sited in California, Nebraska, Michigan, and Minnesota.

Coal was notably absent from the ranks of new generating capacity added in the first half of 2014.  New coal plants face steep headwinds in the form of environmental regulations and stiff competition against natural gas plants.  EIA reports that only two coal plants are planned to come online in 2014.

As regulations and market forces shape the nation's energy mix, where will the new equilibrium be found -- and for how long?

FERC authorizes mine drainage microhydro

Friday, September 5, 2014

The Federal Energy Regulatory Commission has issued a hydropower license to a project whose turbines generate electricity from acid mine drainage. The micro-hydropower license issued to the Antrim Treatment Trust illustrates this unusual approach to the twin challenges of mine remediation and renewable energy.

The power of falling water, in the White Mountain National Forest in New Hampshire.
In the 1980s, Antrim Mining, Inc. operated a surface bituminous coal mine in Pennsylvania.  When water draining through the mine and into streams and rivers was found to exceed pollution limits, the Commonwealth of Pennsylvania charged the company with violations of mining and reclamation law.  The charges led to a series of settlements through which Antrim agreed to improved water treatment facilities, including an off-the-grid hydroelectric facility.  This micro-hydro plant would be powered by treated effluent flowing downhill out of lagoons.  Antrim created the Antrim Treatment Trust to manage treatment of the mine water in 1991, then went out of business.

In an attempt to reduce the cost of treating the site's severe acid mine drainage, the Babb Creek Watershed Association identified micro-hydropower as an option for the site.  In 2008, the association received an Energy Harvest Grant from the Pennsylvania Department of Environmental Protection.  This $428,710 award was designed to support the installation of two hydroelectric turbines on the treatment plant's discharge, which was completed in 2012.

While the Federal Power Act requires most hydropower projects to secure a license from the Federal Energy Regulatory Commission, some off-grid hydropower projects that do not use the waters of the United States do not require licensure.  In 2010, the Antrim Treatment Trust filed a Declaration of
Intent for a 40-kilowatt grid-connected project, but quickly revised its project to be off-grid after the Commission issued an order finding that a license was required for the grid-connected project.  Once the project was off-grid, the Commission ruled that no license was required.

The Antrim treatment plant seems to have then operated one turbine, but left the second turbine non-operational. A 2012 article in the Williamsport Sun-Gazette suggested that with both turbines running and selling power into the electricity grid, the treatment plant could cut $12,000 in annual power costs and make $10,000 per year in new revenue.  But this could require a FERC license, because the project would become connected to the utility grid.

The Trust appears to have decided that these economics were worth pursuing, because in 2013 it filed an application for a project license for a 40-kilowatt project.  In the application, Antrim Trust proposed to bring a second identical turbine (currently in place but non-operational) online by installing additional indoor wiring with appurtenances within the existing powerhouse and treatment plant, and operate both turbines as a grid-connected project using the treated and/or untreated water.

As licensed, the Commission estimates the annual cost to develop and maintain the proposed 40-kW project is $9,356 or $37.42/megawatt-hour (MWh).  The project will generate an estimated average of 250 MWh of energy annually.  Based on Commission staff’s view of the alternative cost of power ($56.93/MWh), the total value of the project’s power is $14,233 in 2013 dollars.  To determine whether the proposed project is currently economically beneficial, staff subtracts the project’s cost from the value of the project’s power. Therefore, in the first year of operation, the project is expected to cost $4,877 or $19.51/MWh less than the likely alternative cost of power - demonstrating economic benefit.

Micro-hydropower projects can make economic sense in some mine drainage situations and other places where water treatment is required and a suitable vertical drop or pressure is available.  In Antrim's case, the project's success can partially be explained by the existence and purpose of the Trust, as well as the DEP grant to support project construction.  If treated and untreated mine drainage can be used to generate hydroelectricity, what other unusual sources of power will arise?

Oregon wave energy project surrenders license

Monday, August 25, 2014

Ocean waves contain tremendous amounts of energy that could be harnessed by humans -- but difficulties have led a pilot project proposed off the Oregon coast to surrender a key federal license.

Calm waters along the shore of Penobscot Bay, Maine.

Ocean Power Technologies subsidiary Reedsport OPT Wave Park, LLC had proposed a wave energy project in the Pacific Ocean off the central Oregon coast.  In 2012, the Federal Energy Regulatory Commission issued a license for the project.  That license authorized the developer to install a single "PowerBuoy" wave energy converter for testing, followed by additional grid-connected buoys.  The developer also envisioned a third phase that could bring the project's capacity to 50 megawatts, and secured a preliminary permit from the Commission to study the site.

Despite securing these key regulatory approvals, the Reedsport project quickly ran into technical difficulties.  Reedsport began construction of the project in September 2012, by installing a single floating gravity based anchor and auxiliary subsurface buoy.  However, this first phase of the project was unsuccessful and the auxiliary buoy sank.  Reedsport removed the buoy and associated tendon and outer mooring lines from the project area on October 17, 2013.  On February 28, 2014, Ocean Power Technologies notified the Federal Energy Regulatory Commission that it intended to surrender its preliminary permit for the 50 megawatt third phase, but left the first phase's license in place for the moment.

On May 30, 2014, Reedsport filed an application to surrender its license for project, stating that financial and regulatory challenges in developing the project have forced it to conclude that it cannot proceed with the development of the project.  The Commission accepted that license surrender by order dated August 14, to be effective following confirmation of the project's decommissioning.

With the Reedsport project shelved, no wave energy project currently holds a FERC license.  Several tidal projects have been licensed, one wave-based hydrokinetic project has secured a preliminary permit, and two other wave energy projects have pending applications for preliminary permits.  The ocean remains a demanding environment, and the economics of most wave energy projects are challenging.  Will others succeed where Reedsport OPT has not?

Maryland offshore wind sites auctioned

Wednesday, August 20, 2014


The U.S. Bureau of Ocean Energy Management has sold the rights to lease sites for offshore wind projects in federal waters off Maryland to US Wind Inc. for $8.7 million.

A lighthouse on an island in the Atlantic Ocean, off Maine.


Part of the Obama administration's "Smart from the Start" offshore wind leasing program, yesterday's auction covered the rights to lease nearly 80,000 acres of the outer continental shelf.  The Maryland Wind Energy Area ranges seaward from about 10 nautical miles offshore Ocean City.  According to Department of Energy’s National Renewable Energy Laboratory, the area could support between 850 and 1450 megawatts of commercial wind generation.

The Maryland auction drew three bidders: US Wind Inc., Green Sail Energy LLC and SCS Maryland Energy LLC.  After 19 rounds, BOEM declared US Wind Inc. the provisional winner.  US Wind Inc. is a subsidiary of Italian firm Toto SpA's Renexia group. 

While winning the auction is an important first step in leasing federal ocean sites for offshore wind projects, the process will likely continue to play out for several years.  Following the auction results, US Wind Inc. will have one year within which to submit a Site Assessment Plan to BOEM for approval.  In the Site Assessment Plan, the lessee must describe what it intends to do to assess of the wind resources and ocean conditions of its commercial lease area -- for example, installing meteorological towers and buoys.  If that plan is approved, the lessee will then have up to 4½ years in which to submit a Construction and Operations Plan providing more detailed information for the construction and operation of a wind energy project on the lease.  The filing of that plan triggers further public comment and environmental review; if approved, BOEM will then issue a lease with an operations term of 25 years.  Notably, these leases generally require the lessee to pay ongoing rents; placing the winning bid in the auction conveys the right to pay that rent, but paying that bid does not count towards the lease payment obligation.

Moreover, this entire leasing process is just one of several aspects of the project that must move forward in parallel.  At the same time, US Wind Inc. is likely considering engineering issues such as turbine selection and interconnection design as well as how to finance the project.

Will federal waters offshore Maryland soon become home to an offshore wind project?

Feds to auction North Carolina offshore wind sites

Friday, August 15, 2014

The U.S. Department of the Interior's Bureau of Ocean Energy Management has announced plans to auction the rights to lease sites off the North Carolina coast for offshore wind projects.

Under the Bureau of Ocean Energy Management's "Smart from the Start" competitive program for leasing sites on the outer continental shelf (OCS) for commercial wind energy development, BOEM conducts a series of stakeholder and environmental review processes.  Through these processes, BOEM identifies areas that are attractive for commercial offshore wind development, while also protecting important viewsheds, sensitive habitats and resources and minimizing space use conflicts with activities such as military operations, shipping and fishing.

For North Carolina, the process began in December 2012 when BOEM published in the Federal Register a Call for Information and Nominations and a Notice of Intent to Prepare an Environmental Assessment.  After considering the public comments and responses, BOEM defined three Wind Energy Areas off North Carolina:
  • The Kitty Hawk Wind Energy Area begins about 24 nautical miles (nm) from shore and extends approximately 25.7 nm in a general southeast direction at its widest point. Its seaward extent ranges from 13.5 nm in the north to .6 nm in the south. It contains approximately 21.5 OCS blocks (122,405 acres).
  • The Wilmington West Wind Energy Area begins about 10 nm from shore and extends approximately 12.3 nm in an east - west direction at its widest point. It contains just over 9 OCS blocks (approximately 51,595 acres).
  • The Wilmington East Wind Energy Area begins about 15 nm from Bald Head Island at its closest point and extends approximately 18 nm in the southeast direction at its widest point. It contains approximately 25 OCS blocks (133,590 acres). 

Map of North Carolina Wind Energy Areas, courtesy of BOEM.
The North Carolina auction will follow a series of similar auctions for East Coast offshore wind sites in federal waters over the past year, including sites off Massachusetts and Rhode Island and Virginia, and will come after the scheduled August 19 auction for sites off Maryland.  To date, BOEM has awarded five commercial wind energy leases off the Atlantic coast: two non-competitive leases (for the proposed Cape Wind project in Nantucket Sound and an area off Delaware) and three competitive leases (two offshore Massachusetts-Rhode Island and another offshore Virginia).  Altogether, the competitive lease sales have generated more than $5 million in high bids for more than 277,500 acres in federal waters.  BOEM expects to hold additional competitive auctions for wind energy areas offshore Massachusetts and New Jersey in the coming year.

When will North Carolina offshore wind sites be auctioned?  Who will bid?  Who will win -- and what will the high bid be?  Perhaps most fundamentally, will the BOEM leasing process lead to anyone developing a offshore wind project off North Carolina?