Community-based renewable energy in Maine

An innovative program in Maine seeks to facilitate the development of community-based renewable energy projects.  The program offers significant incentives for the development of qualified electric generation projects of up to 10 MW in size.

In 2009, the Maine legislature enacted a law establishing the Community-Based Renewable Energy Pilot Program to encourage the sustainable development of community-based renewable energy.  By community-based, Maine's program targets locally-owned community-scale projects (as opposed to large-scale renewable projects owned primarily by out-of-state entities).

Under the program, qualified renewable energy projects can receive significant incentives including a long-term contract to sell the facility’s output to a Maine transmission and distribution utility for up to 20 years at average prices up to $100 per MWh (equivalent to 10¢ per kWh). This incentive is attractive because not only can the contract prices be above average market prices, but also the long-term power purchase agreement makes projects easier to finance by enhancing revenue certainty.

Eligible projects can apply to the Maine Public Utilities Commission for certification as community-based renewable energy projects. This process involves making public filings, negotiating with Commission staff, and demonstrating that the project meets the program’s qualification requirements. These include restrictions on resource type, nameplate capacity, and ownership.

Under the pilot program, eligible resources include:

• fuel cells
• tidal power
• solar energy
• wind systems
• geothermal systems
• hydroelectric generators
• generators fueled by landfill gas
• biomass generators whose fuel includes anaerobic digestion of agricultural products, byproducts or wastes.

Each individual project must not exceed 10 MW in nameplate capacity. Projects must also be primarily locally owned, meaning that 51% or more of the facility must be owned by Maine residents, governmental entities, businesses, or other qualifying local owners.

Once certified, a qualified project can choose either of two incentives: a long-term contract for the output of the facility with a transmission and distribution utility, or a renewable energy credit (REC) multiplier giving a 50% bonus in the amount of RECs produced.

To date, most have viewed the long-term contract as the more attractive option. Under this incentive, projects meeting the program’s requirements can obtain a contract at a fixed or variable price, provided that two criteria are met. First, the average price per kilowatt-hour must not exceed 10 cents. Second, the cost of the contract must not exceed the cost of the project plus a reasonable rate of return on investment as determined by the Commission. These contracts may be approved for up to 20 year terms.  Projects smaller than 1 MW can contract directly with the utility, while larger projects go through a competitive process held periodically by the Commission.

What will 2012 bring for Maine's community-based renewable energy pilot program?

Municipal hydrokinetic energy

Interest is increasing in municipal hydrokinetic energy projects, as cities and towns consider whether they should generate renewable electricity from their water resources.  Hydrokinetics entails generating electricity from moving water such as tides, waves, and free-flowing rivers.  Towns, states, and national governments may not only have an interest in generating power for their citizens, but may also have advantages in project development such as lower financing costs.

For example, the town of Wiscasset, Maine is considering whether to pursue a project togenerate electricity from tidal power in the Sheepscot River. The town thinks that tidal currents and flowing water in the Sheepscot could be used to generate electricity using hydrokinetic technology.  In 2008, the town applied to the Federal Energy Regulatory Commission for a preliminary permit to study the feasibility of the project. Wiscasset proposed to deploy a series of hydrokinetic turbine generating units in the tidal Sheepscot, along with associated transmission facilities. Currently, Wiscasset appears to be considering using the RivGen units under design by ORPC.

In May 2009, the FERC granted Wiscasset its preliminary permit. Preliminary permits confer the right to investigate the feasibility of a hydropower project, typically for a three-year term. Preliminary permits do not authorize actual construction; to actually build and operate a hydrokinetic or hydroelectric project generally requires a FERC license or exemption. The holder of a preliminary permit does have first priority to file for a full license as long as the preliminary permit remains in effect, and FERC expects permittees to make progress toward ultimate licensure. (For example, in September 2011 a company affiliated with ORPC used its preliminary permit priority to file a pilot license application for the Cobscook Bay Tidal Energy Project.)

Next spring, the town faces a key deadline if it chooses to seek a hydrokinetic pilot project license for the project. Wiscasset’s preliminary permit is set to expire on April 30, 2012. Filings in the project’s FERC docket suggest that the town may seek to extend that deadline. For example, in a May 2011 filing, the town said, “we anticipate the Wiscasset Project will apply for a successive Preliminary Permit in May 2012”.

Generally, preliminary permits expire after three years, after which the original permittee has no special rights to the site. In certain circumstances, federal regulators can grant successive preliminary permits. For example, FERC has given several municipal hydroelectric projects successive preliminary permits when the towns need more time. Even this requires a showing of diligent efforts to investigate the project’s feasibility and partial progress toward readiness for a license application.

In Wiscasset’s case, other deadlines within the preliminary permit process have already been extended. For example, the 2009 preliminary permit required the town to submit a Notice of Intent and draft license application in May 2011. Instead of filing these pre-application documents, the town chose to ask FERC for an extension to allow more site studies and stakeholder consultation. FERC allowed the town more time, but only until the preliminary permit expires on April 30, 2012. FERC may give the town similar leniency if it applies for a successive preliminary permit this spring. On the other hand, FERC promotes competition and discourages “site-banking”; if someone else showed interest in developing the Wiscasset site, FERC might be less inclined to issue the town a successive preliminary permit.

Wiscasset has until the end of April 2012 to either file a license or seek its successive preliminary permit.  If Wiscasset moves forward, the Sheepscot hydrokinetic project could be an example of how towns can benefit from their renewable energy resources.

Court upholds Cape Wind PPA

The proposed Cape Wind offshore wind project won a legal victory today, as the Massachusetts Supreme Judicial Court has upheld the power purchase agreement between Cape Wind and utility National Grid.

Back in November 2010, the Massachusetts Department of Public Utilities approved a long-term contract between National Grid and Cape Wind. Under the approved power purchase agreement, the utility agreed to buy half of the output from Cape Wind’s project for 15 years. Pricing for the power would start at 18.7 cents per kilowatt-hour, escalating 3.5 percent annually. The state regulator concluded that the benefits of the contract exceed its costs, even though the Department found that the contract will most likely cost ratepayers between $420 million and $695 million above market prices over its 15-year term.

Many parties participated in the case before the Department of Public Utilities over whether the contract should be approved. When the Department approved the contract, several of these parties appealed to Massachusetts’ highest court. These appellants included trade groups for industrial energy consumers, traditional power generators, an international energy company and a group opposed to the project. Challengers filed a variety of legal claims, including that the Department lacked authority to approve the contract given its high costs, alleged lack of competitive bidding, and even potential violations of the Massachusetts Green Communities Act.

Today the Supreme Judicial Court issued its written opinion upholding the Department’s decision to approve the PPA. In the opinion, the court found that the record before the Department contained sufficient evidence for the Department to conclude that the Cape Wind contract’s special benefits exceeded those of other renewable energy resources. The court also agreed that it was proper for the Department to find that those environmental benefits would accrue to all of National Grid’s customers, and thus to spread the contract’s above-market costs across its rate base.

EPA finalizes utility air emission regulations

New federal environmental regulations on utility air emissions have been finalized, but their impact on electricity costs and grid reliability remains to be seen.  The US Environmental Protection Agency has released its final rule for power plant air emissions.  (Here's EPA's Final Rule, a 1,117-page PDF.)  These rules, formally known as the Mercury and Air Toxics Standards or MATS, are also known as "utility MACT" because they require many utility generation units to use "maximum achievable control technology".  The rule gives utility electric generation plants three years to comply with tighter air pollution control requirements.

Even before the rule was finalized, it provoked controversy over how it could impact electricity prices and the reliability of the US electric grid.  According to the US Energy Information Administration, in 2010 coal was used to generate about 45% of the electricity consumed in the United States.  The nation's electric reliability organization, NERC, released a report suggesting the new rules would force the early retirement of a significant portion of the nation's coal-fired generating stations.  In NERC's analysis, if EPA's air rules force needed generators to shut down, the reliability of the electric grid could be at risk.

EPA and the Department of Energy disputed NERC's assumptions.  Ultimately, EPA issued its final rule on December 21, 2011.

President Obama expressed his support for EPA's new rule.  In a Presidential Memorandum, President Obama described how the new rules would improve air quality and public health.  President Obama also explicitly addressed the linkage between these rules and grid reliability:

These new standards will promote the transition to a cleaner and more efficient U.S. electric power system. This system as a whole is critical infrastructure that plays a key role in the functioning of all facets of the U.S. economy, and maintaining its stability and reliability is of critical importance. It is therefore crucial that implementation of the MATS Rule proceed in a cost-effective manner that ensures electric reliability.

Analyses conducted by the EPA and the Department of Energy (DOE) indicate that the MATS Rule is not anticipated to compromise electric generating resource adequacy in any region of the country. The Clean Air Act offers a number of implementation flexibilities, and the EPA has a long and successful history of using those flexibilities to ensure a smooth transition to cleaner technologies.

The President also directed a coordinated process to plan and execute measures needed to implement the rule while maintaining the reliability of the electric power system.  This process should be designed to "promote predictability and reduce uncertainty," and should include engagement and coordination with a broad array of stakeholders including the DOE, the Federal Energy Regulatory Commission, state utility regulators, regional transmission organizations, the North American Electric Reliability Corporation and regional electric reliability organizations, other grid planning authorities, and electric utilities.

FERC Order 755 promotes energy storage

New technologies have the promise to help electric grid operators perform the challenging task of balancing supply and demand at all times.  This means making sure there the exact amount of electricity is being generated across the region as is demanded by consumers at that very moment.  Line losses and the constraints of each local transmission and distribution system add complication.  If the grid gets out of balance, problems arise with the electricity's frequency and power quality.  In the worst case, failure can lead to cascading blackout, and safety can be at issue.

Historically, the balancing act has involved sending coordinated dispatch instructions to generators and demand response resources.  Rules typically guide the grid operator in telling individual generating units to operate at specific levels. For example, flows through hydroelectric turbines can be varied, or fuel can be added to boilers or combustion turbines at a faster or slower rate.  Through careful management, these conventional generation resources have been used to balance supply and demand, providing services known as frequency response and frequency regulation.

Though it is partly automated and well-practiced, this conventional resource dispatch process does take some time to take effect.  Energy storage technologies such as flywheels, and batteries can not only provide frequency regulation, but can engage and ramp up much faster than conventional resources can.  These faster-ramping resources could provide the grid relief in real time, as opposed to ramping up more slowly like conventional generation.

In most US markets, providers of efficient fast-ramping frequency regulation have been compensated the same as when conventional units provide regulation service, even when using fast-ramping resources is more efficient.  At times this has meant that conventional resources have been dispatched when fast-ramping ones would have been lower-cost (and less polluting).  For these reasons, this October the Federal Energy Regulatory Commission found that the current frequency regulation compensation practices "result in rates that are unjust, unreasonable, and unduly discriminatory or preferential."

In Order No. 755, FERC issued a final rule requiring the grid operators in organized markets to compensate frequency regulation resources based on the actual service they provide.  Under Order 755 (123 page PDF), this must include separate payments for capacity (the marginal unit’s opportunity costs of being available) and for your actual performance.

Winners under Order 755 include providers of fast-ramping frequency response.  These could include developers and operators of flywheel energy storage companies like Beacon Power, battery storage facilities, and compressed air energy storage, and other resources still in the conceptual phase.  Winners also include energy consumers in the markets affected by Order 755, who should benefit from lower costs through improved operational and economic efficiency.

Could net metering save municipal hydro?

Two dams on the Royal River in Yarmouth, Maine are one step closer to removal, as a majority of the town council agreed earlier this month that the dams should be removed.  The town owns two dams near Bridge Street and East Elm Street, which provided mechanical power to mills as early as 1816.  The Sparhawk Mill site near Bridge Street was upgraded to produce hydroelectricity in 1984, and operates as a privately-owned hydroelectric project exempt from most Federal Energy Regulatory Commission regulation.  Yarmouth has considered dam removal for several years, with concerns over fish habitat restoration as the driving factor.

The push to remove the dams comes despite the value of the sites' ability to generate renewable electricity.  A consultant hired by the town in 2010 estimated that the Bridge Street site could theoretically produce over $150,000 in annual hydropower revenues (7 page PDF), with $55,000 being a more realistic estimate of practical production from the existing facilities if they could be repaired and maintained.  In reaching this figure, the report assumed the then-current energy price of 7 cents per kilowatt-hour (kWh).  The report also assumed that the project could qualify for net metering, which the report defined as "unused power is purchased by the utility".

Maine's style of net metering at present is slightly different from that suggested in the report.  Under what Maine calls net energy billing, the owner of eligible renewable or micro combined heat and power (CHP) equipment can use the generation facility to offset its consumption of electricity from the grid, effectively running its electric meter backwards.  If a customer generates more electricity than it uses in any given month, the utility banks the excess amount as credits to be used within the next year.

One advantage gained by a net metering customer is that when generation offsets consumption, the customer saves on more than just the energy component of its electric bill.  In Maine's electricity market, customers pay for both the energy they use and what it costs to deliver that energy over transmission and distribution wires.  Today, the standard offer energy price for residential and small commercial customers in Central Maine Power's territory (including Yarmouth) is 7.4 cents per kWh.  The Maine Public Utilities Commission reports that delivery fees add another 6.47 cents per kWh for residential customers, or 6.3 cents for small commercial customers.  Thus the total cost to these customers of buying electricity and having it delivered is closer to 13.7 cents per kWh - nearly double that assumed in the town's report.  This higher figure may more accurately reflect what the town could save by net metering the Sparhawk Mill project's output against its consumption.

Maine also allows more than one customer to cooperate in net metering.  One eligible generation project can be used to offset consumption on up to 10 customer accounts, provided the participating customers establish partial ownership or an entitlement to the part of the project's output.  This shared ownership net metering lets eligible projects reach their full potential, even when they can produce more electricity than the primary owner needs in a year.

If the town can take the full value of net metering into account and find a way to benefit from the existing renewable generation at the Sparhawk site, the economics would tip towards keeping the Sparhawk project running.  There are other ways that project revenues could be boosted by smart participation in other energy programs, such as selling capacity or renewable energy certificates (RECs) if the project can be certified as renewable.

Would reevaluating the Royal River dam's hydropower potential lead the town to a different conclusion on whether the dam should be removed?  The Yarmouth town council is holding a workshop session on January 5 and a public hearing on January 19 to discuss next steps.

Net metering charges in Virginia

Virginia regulators recently approved an electric utility's request to impose additional charges on net metering customers with rooftop solar panels or other customer-sited generation.

Net metering -- when utility customers can offset their electric bill by using their own generation -- is a tool to encourage the spread of small-scale generating resources.  Under net metering programs, customers are billed not based on how much electricity they buy from the grid over a given month, but rather based on their purchases netted against what they export from their own generation.  For example, a home or business with solar photovoltaic panels on its roof could use net metering to run its utility bill backwards to the point where the customer has no bill at all.  In some areas, customers can even run up a surplus of power through net metering.

Net metering facilitates distributed generation, in contrast to the centralized utility model that has historically prevailed.  Mixing in some distributed grid-tied generation has advantages for the whole system, such as a reduced need for expensive new transmission lines.  To promote the distributed model, Congress directed electric utilities to make net metering available as part of the Energy Policy Act of 2005.

Now, nearly all U.S. jurisdictions have net metering programs.  Each state's implementation of net metering is unique.  For example, under Virginia law, residential net meterers must pay their utility a "standby charge" -- a monthly amount to compensate the utility for the customer's ability to draw electricity from the grid, even beyond what would be charged under its net-metered bill. 

Earlier, I noted that utility Dominion Virginia Power had asked the Virginia State Corporation Commission to approve “standby” charges on residential net-metered solarphotovoltaic systems larger than 10 kW. Last month, the State Corporation Commission approved part of the utility's request.  The Commission approved a standby charge for transmission and distribution service - $2.79 per kW in monthly distribution standby charges and $1.40 per kW in monthly transmission standby charges.  The Commission denied Dominion's request for generation standby charges for now, but encouraged the utility to come back for another proceeding to determine whether a generation standby charge would be proper.

Alaska's Susitna hydro project revived

A large hydroelectric project proposed by Alaska's public power authority is moving closer to reality.  With over 600 megawatts of electric generating capacity, the Susitna-Watana Hydroelectric Project would be the largest dam built in the U.S. since 1966, when the Glen Canyon Dam was built on the Colorado River in Arizona.  If built, the Susitna project would represent a return to both mega-scale hydro and state-backed hydroelectric development in the United States.

The Susitna River project has been under consideration for nearly 50 years, although environmental concerns and the relatively low cost of oil dampened interest in the project for much of that time.  Increasing fossil fuel costs, renewable energy targets, and interest in exploiting the state's sovereign resources have now led to a revival of the project.  In 2011, Alaska state legislators unanimously approved funding for the Alaska Energy Authority to pursue the project.

The Alaska Energy Authority (AEA) was created by the Alaska Legislature as a public corporation of the state, albeit with a separate and independent legal existence.  AEA's missions include reducing the cost of electricity in Alaska, and constructing, acquiring, financing, and operating projects that utilize Alaska's natural resources to produce electricity and heat.

Renewed interest in the Susitna project comes partly in response to Alaska's renewable portfolio standard law.  In 2010, the Alaska Legislature enacted House Bill 306, creating a goal that the state receive 50% of its electric generation from renewable and alternative energy sources by 2025.  The project could also produce low-cost electricity, with generation costs projected to be lower than natural gas over the life of the project, possibly significantly lower once the project's financing is paid off.


AEA now plans to follow the traditional process for licensing hydroelectric projects through the Federal Energy Regulatory Commission.  AEA is expected to file its pre-application document with FERC on December 29, 2011, with the license review process expected to take up to six years.


If the Susitna project is built, it will be a departure from the recent trend of dam removal.  Some observers have argued that the era of building large-scale hydroelectric facilities in the United States ended decades ago, but the Susitna project could reverse that trend.  Moreover, the Susitna project would be built by a sovereign state government, echoing historic federal efforts like the Tennessee Valley Authority and Bonneville Power Authority.

Floating offshore wind in US waters?

US coastal waters may soon see the development of floating offshore wind electric generating projects. Being able to install offshore wind turbines on floating platforms, as opposed to towers fixed to the seabed, may enable projects to tap into the vast deepwater ocean energy resource. This would represent a major step in history and technology, and could provide real data on the actual feasibility and costs of offshore wind in the United States.

The Cuckolds Light off Boothbay Harbor, Maine, with Seguin Island Light in the distance.

2012 may bring the deployment of North America's first floating offshore wind project. The DeepCWind Consortium and the University of Maine plan to test a floating wind turbine several miles off the Maine island of Monhegan next summer. The Monhegan project is designed as a pilot project, not a commercial effort. Nevertheless, the lessons learned off Monhegan could be used to shape a larger commercial project in 2013.

Historically, this project could be the first operating US offshore wind development. As 2011 closes, US waters still host neither operating commercial offshore wind projects, nor installed pilot projects of significant size. This is not for lack of interest. Universities and businesses are investing in offshore wind research and development, while developers eagerly pursue commercial projects in nearly all US jurisdictions. Commercial proposals range from projects fully permitted projects but unbuilt, to concepts still in the formation phase.

Technologically, a floating offshore wind project would demonstrate potential solutions to the engineering challenges posed by deep water sites. At least two floating turbines have recently been deployed around the world. The first, Statoil’s 2.3 megawatt Hywind unit, was installed off Norway in 2010. In November 2011, Portuguese utility Energias de Portugal (EDP) teamed up with Principle Power, Inc. to deploy a 2 megawatt turbine on a WindFloat platform off Portugal. The semisubmersible WindFloat design allows the unit to be towed in a horizontal position to the site, then erected without the use of a lift vessel. These test projects demonstrate some of the technologies required for deepwater offshore wind projects. A US project would represent a similar demonstration of new technology.

Floating offshore wind projects appear to have some momentum in Europe, and are poised to make a splash in US waters in the next year. Whether these efforts take hold depends on broader questions of economics and policy as much as on technology. What will 2012 bring?

National park energy use and strategies

Small-scale alternative energy resources play an increasing role in how the U.S. National Park Service manages its lands, budget, and energy usage.

Solar panels line the roof of the comfort station at Devil's Garden Campground in Arches National Park, Utah.

The United States National Park Service manages about 84.4 million acres of land in the form of national parks, national monuments, and other historic and conservation properties.  While much of the Park Service's holdings are preserved as undeveloped backcountry properties, the NPS provides visitor amenities like lodging, food and other concession services.

The remote locations of many Park Service sites make traditional energy resources expensive and challenging.  Ranger stations and campground bathrooms may be located far from the traditional utility electric grid.  Diesel generators can be used if road access to the site is possible, but have drawbacks: fuel is expensive, and generators can be loud, produce emissions, and may be out of character for a particular national park site.

In some cases, the Park Service is turning away from traditional energy resources to alternative and distributed energy resources like solar power.  In fact, the Park Service has deployed distributed solar photovoltaic generation for over a decade.

Consider the example of Devil's Garden Campground in Arches National Park in Utah.  While the campground is relatively remote (located at the end of a 30-mile dead-end road inside the park), Park Service facilities in the campground need electricity.  These facilities include two campground hosts, three bathrooms, an amphitheater and a ranger station.

Historically, electricity for the campground facilities came from on-site diesel generators.  These units ran 24 hours a day, consuming over 6,400 gallons of fuel per year.  Producing electricity from diesel is seldom cost-competitive today; generating electricity from diesel at Devil's Garden Campground cost the National Park Service over $22,400 per year.  This meant that the Park Service was generating electricity for a price of 28 cents per kilowatt-hour (kWh), about four times higher than the current average Utah price.

(As expensive as this is, it's still about a third of the cost of diesel-generated electricity on the remote Maine island of Monhegan.  In 2010, electricity on Monhegan cost an average of 74.51 cents per kWh.)

As early as 1995, the Park Service joined with the state of Utah to develop four photovoltaic/diesel hybrid systems at Devil's Garden Campground.  Each system is composed of a 1.4 kilowatt (kW) tracking array, a 4 kW inverter and a 40 kWh battery bank.  Diesel units remain on-site and ready, but now run less than 4 hours per day.  This cut the Park Service's annual operation and maintenance costs for the diesel generators from $22,400 to $10,000.  The project dramatically reduced the noise level in the campground, and significantly cut the diesels' emissions of carbon dioxide, carbon monoxide, nitrogen oxides, and sulfur oxides.

As this example shows, sites that are already off the grid can be good candidates for small-scale distributed generation projects relying on alternative technologies like solar.  Depending on project economics and other objectives (like the Park Service's sustainability initiative, improving noise levels and air quality, or education), replacing diesel with renewable energy -- and making energy efficiency improvements -- can make sense.

Other units in the National Park Service system are following the Arches example by turning to distributed renewable energy and energy efficiency.  In 2011, Yosemite National Park installed a 672 kilowatt grid-tied solar array.  The $5.8 million Yosemite project is bigger in scale (the Park Service's largest solar energy project) and is tied to the utility electric grid, but represents a similar strategy to that used in Arches and throughout the Park Service.

Maine ocean energy advances

Maine's offshore wind industry may be moving forward, as the federal agency responsible for offshore wind site leasing is now considering a request by Norwegian energy company Statoil to lease a site for a Maine deepwater floating wind project.

Uninhabited Damariscove Island, off Boothbay Harbor, Maine.

The Maine site for which Statoil has applied lies over 12 miles offshore, south of Boothbay Harbor.  It lies in United States waters south of Damariscove Island.  This places the site near the pre-selected Damariscove Island wind site in Maine state-jurisdictional waters.  Statoil's proposed site is also southwest of the Monhegan offshore wind site.

Statoil's request to the federal Bureau of Ocean Energy Management was submitted on an unsolicited basis.  No BOEM Call for Information and Nominations (the agency's primary competitive solicitation tool) was in effect for these waters.  Under current regulations, unsolicited leases face a slightly different process for review, including a determination of whether there is any competitive interest in the site.

(You can read four public pages from Statoil's application here.)

Statoil is a large and diverse energy company headquartered in Stavanger, Norway, and owned primarily by the government of Norway.  Statoil's portfolio includes petroleum, gas, pipeline, and electric utility businesses.  Statoil is now exploring ocean energy opportunities, and developed the world's first full-scale floating wind turbine, the 2.3 megawatt Hywind unit.  Statoil has applied for a site lease off Maine, which could be its first US offshore wind site.

BOEM has deemed Statoil NA's lease application to be complete, and the applicant to be legally qualified.  Now BOEM is engaged in a review of Statoil's technical and financial qualifications.

Tomorrow morning, a joint state-federal task force will meet to review Statoil's request.  The Maine Task Force of the Bureau of Ocean Energy Management consists of a broad array of agency representatives.  Tomorrow's meeting will feature presentations by representatives from the governor's energy office, Maine Public Utilities Commission, United States Coast Guard, Department of Defense, NOAA, as well as BOEM and the Department of Interior itself.  This meeting will be held on December 8 at the Marriot Hotel in South Portland, Maine, at 9:30 a.m.

Separately, Statoil is negotiating with staff from the Maine Public Utilities Commission for a long-term contract to sell the project's output to utilities.  Statoil responded to the Maine commission's 2010 request for proposals for pilot floating offshore wind projects.  This offshore wind long-term contracting program was established by a Maine law designed to facilitate the development of a deep-water offshore wind energy pilot project.

If the Commission approves a long-term contract for the project's output, it could give the wind farm sufficient revenue certainty.  At the same time, the Commission is required to weigh the costs and benefits of any such contract, and must find that ordering a utility to buy the energy, capacity and renewable energy credits at the price and other terms proposed would not have an unreasonable impact on the utility's rate.

EPA regulations vs electric grid reliability

Debate continues over the impacts of new environmental regulations on the reliability of the U.S. electric power grid.  Players in the recent debates include the nation's chief electric reliability organization (North American Electric Reliability Corporation, or NERC) and the U.S. Environmental Protection Agency -- and now, the U.S. Department of Energy has weighed in.

Earlier this week, NERC released a report suggesting that new regulations under development by the U.S. Environmental Protection Agency may force the early retirement of many coal-fired generating plants.  NERC pointed to several rules under development and implementation, including EPA's Cross-State Air Pollution Rule (creating trading systems to control the emissions of NOx and SO2 from electric generators), Mercury and Air Toxics Standards (imposing emissions standards on coal and oil-fired electric generators for mercury, acid gases and particulate matter), and Cooling Water Intake Structures (regulating generators' intake of water).  On NERC's analysis, this could jeopardize the security and reliability of the electric grid.

EPA disputed these findings, noting that NERC's report contained "faulty characterizations" of its rules, that several rules were still in draft form, and that regulated generators would have more time and greater flexibility in adapting to the final rules.

Yesterday, the U.S. Department of Energy released its report, "Resource Adequacy Implications of Forthcoming EPA Air Quality Regulations" (41 page PDF).  The Department of Energy sided with EPA, noting that even under a "stringent" scenario in which a total of 29 gigawatts of coal capacity would be retired by 2015 -- a conservative assumption, according to the Department -- target reserve margins for generating capacity could be maintained across the country.  The Department also noted that mechanisms exist to help regulators keep the lights on if the rules prove too much.

The Department's report is not likely to end the debate.  Several of EPA's rules are still under development, such as the cooling water intake regulations.  The rules that are now final will take several years to ramp up.  Key agencies have vowed to maintain reliability no matter what happens -- but what impact will the environmental regulations have on the grid?