Community-based renewable energy in Maine

Friday, December 30, 2011

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

Thursday, December 29, 2011

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

Wednesday, December 28, 2011

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

Thursday, December 22, 2011

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

Wednesday, December 21, 2011

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?

Tuesday, December 20, 2011

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

Thursday, December 15, 2011

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

Wednesday, December 14, 2011

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?

Monday, December 12, 2011

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

Friday, December 9, 2011

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

Wednesday, December 7, 2011

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

Friday, December 2, 2011

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?

EPA regs and electric grid reliability

Wednesday, November 30, 2011

Debate is ongoing about the effect of new environmental regulations on the U.S. electric grid.  Some worry that tighter environmental controls will force certain electric generators to shut down, driving up the cost of electricity or putting electric reliability at risk.  Others believe that the grid's integrity can be maintained, and that the new regulations are necessary to protect human health and the environment.

Support for the concerned side of the equation comes from a recent report by the North American Electric Reliability Corporation.  NERC is the nation's electric reliability organization, charged with ensuring the reliability of the North American bulk power system.  In NERC's 2011 Long-Term Reliability Assessment (559 page PDF), NERC notes that recent and future environmental regulations may force the early retirement of a significant portion of the nation's coal-fired generating plants.  These regulations include the recently-finalized Cross-State Air Pollution Rule, plus rules under development governing utility plants' water intakes and air emissions.  According to NERC's report, EPA's new cooling water intake structures and mercury and air toxics standards rules "may significantly affect bulk power system reliability depending on the scope and timing of the rule implementation and the mechanisms in place to preserve reliability."

At the same time, others observe that NERC's report assumes multiple worst-case scenarios and ignored the health and environmental benefits of the rules.  After reviewing a near-final draft of the NERC report, EPA itself wrote NERC a letter (4 page PDF), stating "it appears likely your report may contain ... faulty characterizations of our rules."  EPA pointed to several flaws in NERC's analysis, including that NERC assumed generators would be forced to adopt the most expensive solutions immediately, rather than selecting the most cost-effective technologies for each facility.  EPA noted that the bulk of threatened plant retirements suggested in NERC's report would come from the cooling water intake regulations -- regulations which are still under development.  Finally, EPA pointed out that NERC's analysis appears to assume that no one tries to preserve grid reliability as the regulations begin to take effect, "an outcome that flies in the face of our 40 years of implementing the Clean Air Act and Clean Water Act."  Given the positive impacts of the regulations -- with the Cross-State Air Pollution Rule alone projected to prevent 34,000 premature deaths and 400,000 cases of aggravated asthma per year -- EPA defended their value and refuted NERC's analysis.

Reliability of the grid is important, enough so that the Federal Energy Regulatory Commission convened a technical conference yesterday and today to discuss grid reliability and policy.  While that proceeding may result in interim orders or changes to policy, it may take years for the environmental regulations to both take effect and to impact generating plants.  At the same time, generators are keeping a close watch on federal environmental regulation as it develops.

Google reduces renewable research

Monday, November 28, 2011

In recent years, Google has branched out from its core internet business to work on reducing the cost of renewable energy -- but now appears to have turned away from its renewable research efforts.

Here's a quick recap of some of Google's energy plays.
In addition to these activities, Google launched its "Renewable Energy Cheaper than Coal" initiative.  This program included engineering research and development to reduce the cost and water consumption of concentrating solar plants like Ivanpah.  Now, Google has announced that it has "retired this initiative", while reaffirming its investment in Ivanpah and its green energy procurement.

What will the future hold for Google?  Google it.

Tide Mill Institute event a success

Monday, November 21, 2011

I was very pleased to attend this past weekend's Tide Mill Institute conference. The Tide Mill Institute describes its mission as "to advance the appreciation of tide mill history and technology by encouraging research, by promoting appropriate re-uses of former tide mill sites and by fostering communication among tide mill enthusiasts." Here's a link to the conference website: My presentation compared tidal power projects past and present, looking at project economics, law and regulation. Interesting, many of the judicial opinions about tide mills from centuries past address concerns still expressed about tidal power projects. How will a given project affect water quality? Neighboring property? Fisheries and navigation on? Long before regulatory agencies or specific environmental statutes, tide mills effectively faced regulation in the form of court orders over lawsuits. Today, a host of agencies has regulatory authority over the development and operation of tide mills and tidal electric generation. It was great to meet so man people interested in the past, present and future of tidal energy.

Maryland dam faces sedimentation threat

Thursday, November 17, 2011

In September 2011, Tropical Storm Lee caused flooding in the mid-Atlantic region.  The Susquehanna River rose far above its banks, causing disruptive floods in Pennsylvania and Maryland.  Near the river’s mouth into Chesapeake Bay, massive flooding threatened to breach the 572-megawatt Conowingo Dam.

With its flood gates wide open, the dam survived the flooding.  At peak flows, about 7 million gallons flowed through the dam every minute.  That water transported millions of tons of sediment from the Susquehanna watershed out into the bay, along with large amounts of trash and debris.

The impacts of the flood are still being assessed.  Under typical operations, the dam builds up about 2 million tons of sediment every year, or about two-thirds of the Susquehanna River's total sediment burden.  (Compare the dams currently being removed from the Elwha River in Washington, which had trapped an estimated 24 million cubic yards of sediment.)  Overall, four dams on the Susquehanna might hold up to 280 million tons of sediment.

While Lee removed several years' worth of sediment from the Conowingo Dam, more sediment builds up every year.  The Army Corps is concerned that the Susquehanna River dams have nearly reached their full capacity to hold sediment, and is launching a project to study what could be done, such as sediment dredging or remediation.

Headwater benefits charges affect hydropower projects

Tuesday, November 15, 2011

Suppose you own a federally-licensed dam and hydroelectric generation facilities on a river.  The amount of electricity you can produce is determined by factors including how much water is flowing through your turbines every second and the dam’s “head”, or effective height through which that water falls.  Over an entire year, the amount of power you can produce is also affected by how much water can be stored in the watershed above your dam, and how well you can regulate the flow of water through your turbines.  For example, if you can impound more floodwaters upstream instead of spilling excess water over the dam, you can maintain maximum flows through your powerhouse for a longer period of time than you otherwise could.

Now suppose someone else builds a dam upstream from your site that enables better storage and regulation of water flows through the river.  Setting aside any environmental impacts from that change in flow, one upside of the improved flow regulation is that you can produce more power at your dam thanks to the upstream improvements.

Under the Federal Power Act, you may be required to reimburse that upstream dam owner for an equitable part of the benefits you receive from its improvements.  Federal hydropower licenses typically include a provision requiring the licensee to reimburse the owner of an upstream improvement for these headwater benefits.

Under the Commission’s regulations, headwater benefits charges can be calculated using an “energy gains” methodology.  This analysis includes an assessment of the difference between the number of kilowatt-hours of energy produced at a downstream project with the headwater project and that which would be produced without the headwater project.  Alternatively, dam owners may negotiate an agreement on headwater benefits charges and present it to the Commission for approval as a settlement offer.

Renewable demands drive billions in transmission investment

Thursday, November 10, 2011

As demand for renewable electricity increases, utilities are proposing new transmission lines to connect the new crop of electric generation projects to consumer markets.  Given the scale of these projects, and because renewable power projects are often sited far from the cities and industrial sites where the electricity will be consumed, the proposed transmission lines can come with a significant price tag.  For example, the Northern Pass project - a proposed high-voltage DC transmission line capable of carrying 1200 megawatts of power from Quebec to New Hampshire - is projected to cost $1.1 billion. These costs, and who must pay them, can generate as much controversy as siting the route for the transmission lines.

Another major high-voltage direct current transmission line has been proposed by Rock Island Clean Line LLC.  The Rock Island Clean Line would run about 500 miles from northwestern Iowa into Illinois, where it would connect with the mid-Atlantic regional grid operated by PJM Interconnection.  The proposed line would be positioned to collect electricity produced by wind power facilities in the eastern parts of South Dakota and Nebraska as well as the western parts of Iowa and Minnesota.  This power could be delivered into Illinois, either to satisfy that state's renewable portfolio standard or for further transmission throughout the mid-Atlantic region.  Proponents of the line also claim that it would reduce transmission constraints between the Midwest ISO and PJM grids, as well as reducing wholesale energy prices in Iowa and Illinois.

The price tag for the Rock Island Clean Line project is projected to be $1.7 billion.  While the current project is based on the assumption that the electricity flowing over the line would come from wind generation, there is no guarantee that the resource mix will be as expected.

FERC releases report on demand response

Wednesday, November 9, 2011

Demand response is an innovative smart-grid approach to meeting society's electricity needs. As customer demands on electric grids increase, the generating resources needed to meet higher and higher peak demands are typically more expensive to run and have more adverse environmental impacts.  In essence, demand response means covering electric load by having individuals or companies agree to temporarily cut back on electricity consumption in response to peak demand conditions.  When customers are willing to provide this service at a lower cost than generation, demand response can be a decentralized, crowd-sourced alternative to peaking power plants.

U.S. federal regulatory staff released a report this week assessing the nation's demand response and smart  meter resources.  The Federal Energy Regulatory Commission staff report is the sixth annual briefing since the enactment of the Energy Policy Act of 2005, which contained provisions promoting the development of demand response resources and markets.

The report notes that more and more customers have access to the kind of advanced meters that facilitate demand response participation.  These smart meters can not only measure instantaneous electricity demand, but typically report back to a utility automatically using radio frequency communications.  Since 2009, advanced meters have risen from 8.7% to a 13.4% share of all installed meters.  The report suggests that the actual penetration rate of advanced meters may be even higher if it includes meters that are installed but whose advanced features have not yet been activated.

The report also notes that in 2010, the grid operators it surveyed had a total of 31,702 MW of demand response resource potential, or enough to cover about 7% of the total 2010 peak demand.  Regional demand response capacities ranged from as low as 2.3% of peak load in the Electric Reliability Council of Texas to as high as 10.5% in the mid-Atlantic region's PJM Interconnection.  The report noted that demand response resourcs "made significant contributions to balancing supply and demand during system emergencies" in 2011.

Virginia considers net metering and utility standby charges

Tuesday, November 8, 2011

Virginia, like many states, allows grid-connected electricity customers to use customer-sited generation to offset its electric bill.  This practice is called net metering.

Virginia regulators are now considering a proposal by utility Dominion Virginia Power to impose two “standby” charges on net-metered solar photovoltaic systems larger than 10 kW.  The policy questions raised by this case appear in other contexts where incentives for clean, distributed generation run up against utility ratemaking considerations.  Utilities typically argue that they need to allocate costs fairly among their customers, while customer-sited generation advocates point to both the value of distributed generation and the array of incentives promoting customer-sited generation.

In June 2011, the Virginia legislature enacted House Bill 1983, directing Dominion to allow residential customers to net meter solar photovoltaicsystems between 10 kW and 20 kW.  Dominion responded by petitioning the Virginia State Corporation Commission (SCC) for approval of tariff changes that it argued are necessary to reflect its actual costs in supporting these customers’ peak loads.  The utility proposed to add monthly standby charges for transmission and distribution service based on each net-metered customer’s highest 30-minute demand.

Utilities often argue that their fixed costs in serving net-metering customers – maintaining wires, transformers, and other infrastructure – are the same as if the customers had no generation.  If a customer can be self-sufficient most of the time, the utility grid must still be of a sufficient size to deliver the customers’ peak demand when it is needed, such as when customer-sited generation fails.  Dominion requested approval of its standby charges to ensure fair cost allocation among customers.

Distributed generation advocates, on the other hand, argue that the standby charges would result in overcharging net-metered customers.  In Dominion's case, a witness for the Maryland, District of Columbia and Virginia Solar Energy Industries Association testified the standby charge would result in higher charges for a net-metered customer than a regular customer consuming the same amount of grid-purchased electricity.  The witness also testified that net-metering customers should receive credits for generating cost-effective energy, and for reducing the utility’s transmission line losses.  Diverse distributed generation may also reduce utilities’ distribution costs.  The solar association argued that Dominion's standby charges ignored these benefits, and would chill distributed solar development in spite of Virginia's net-metering policy.

The Virginia State Corporation Commission held a hearing on Dominion's request last week, and is expected to issue an order resolving the matter.

Biofuels power first commercial airline flight

Monday, November 7, 2011

Today marks the first U.S. commercial airline flight powered by biofuels.  United Airlines has selected a Boeing 737-800 for the route from Houston to Chicago.  The plane will be powered by Solajet, a fuel blend of 60 percent petroleum-based jet fuel and 40 percent biofuel produced by California-based algae producer Solazyme.

Biofuels appear poised to play an increasing role in the transportation sector.  Biofuels have traditionally included liquid fuels like ethanol (derived from corn or cellulosic sources) and biodiesel.  Biofuels typically rely on plants or algae to convert solar energy into chemicals that can be refined and modified to produce usable fuels.  The wood (biomass) burned in hearths and stoves around the world represents a very basic biofuel, but today's advanced biofuels can involve significantly more technology.  The U.S. Department of Energy is funding research and development efforts to produce "drop-in biofuels", which can be  used as additives or even replacements for liquid fuels like gasoline, diesel and jet fuels -- without requiring consumers or distributors to modify their engines and fuel distribution networks.

United Airlines is not the only carrier to take its biofuels experimentation live this week.  On Wednesday, Alaska Airlines will fly two commercial flights from its bases in Seattle and Portland, Oregon, to Washington, D.C.  Alaska Airlines' jets will be powered by a fuel blend composed of 20% biofuels from used cooking oil.  Alaska Airlines chose Dynamic Fuels as its supplier; Dynamic Fuels is a joint venture between food product giant Tyson Foods and synthetic fuel producer Syntroleum.

Presidential permits for cross-border energy facilities

Thursday, November 3, 2011

Presidential permits for the import and export of energy resources across the United States' borders are critical to the development of cross-border energy facilities.

Millions of dollars of energy resources flow across the United States' borders every day.  Trade in energy resources with Canada and Mexico accounts for the bulk of these transactions.  Canada is the single largest foreign supplier of energy to the United States, providing about 20% of U.S. oil imports and 18% of U.S. natural gas imports according to the U.S. State Department.  Canada and the United States share an integrated electricity grid and provide all of each other's electricity imports.  Today and tomorrow, members and guests of the New England - Canada Business Council are meeting in Boston to discuss this close relationship.

Facilities spanning the border -- whether pipelines for oil or natural gas or transmission lines for electricity -- can only be built and operated once a federal approval called a "presidential permit" has been obtained.  Since a 1968 Executive Order, presidential permits have been issued by the State Department.  Presidential permits cover not only the facilities themselves, but also the commodities (oil, gas, electricity) transmitted over those facilities.

For example, the proposed Keystone XL pipeline from Canada to Texas will require a presidential permit.  In today's news, President Obama is reported as saying that he will be the one to make the final decision on whether TransCanada will obtain its permit.

Yarmouth, Maine considers dam removal, other options

Monday, October 31, 2011

The town of Yarmouth, Maine is holding a meeting on November 1, 2011 about the future of two town-owned dams on the lower Royal River.

The Royal River flows nearly 40 miles across Maine, from Sabbathday Pond in New Gloucester to meet Casco Bay in the town of Yarmouth.  Along this course, the Royal River falls about 300 feet, much of which forms a series of old dams and falls in its lower reaches.  The village of Yarmouth formed around several of these dam sites, which provided mechanical power to mills and businesses in the village.  Today, dams remain on the Royal River.  A non-hydropower dam spans the river near East Elm Street, while the Sparhawk Mill dam hosts hydroelectric generating facilities near Bridge Street.

The Sparhawk Mill dam was originally built to provide mechanical power, but hydroelectric generating facilities were installed in 1984.  Now, the Sparhawk project can produce 270 kilowatts of power, and operates under a licensing exemption issued by the Federal Energy Regulatory Commission in 1985.

Today the town of Yarmouth owns the dams, and is considering their future.  The Sparhawk dam is reportedly not producing much -- if any -- revenue for the town, while both dams may need maintenance and repairs.  Some community members suggest dam removal for reasons ranging from municipal fiscal policy to enhancing fish passage along the Royal River.  Others point to value of the Royal River's continuing ability to produce renewable hydroelectricity, and urge that the dams be maintained.  The East Elm Street dam could even have electric generation facilities installed, either traditional hydroelectric or hydrokinetic devices.

The community forum starts at 7 p.m. on November 1 at Yarmouth Town Hall.

Keystone XL pipeline explained

Thursday, October 27, 2011

The proposed Keystone XL oil pipeline is drawing significant public attention.  What is the Keystone XL project, and why is it controversial?

What is Keystone XL?
The Keystone XL project is a proposed extension of an existing crude oil pipeline.  The $7 billion project would run from the Canadian province of Alberta to Texas, cutting across Saskatchewan, Montana, South Dakota, Nebraska, Kansas, and Oklahoma along the way.  TransCanada Corporation proposes Keystone XL to expand its existing Keystone pipeline network, a former natural gas pipeline repurposed to ship crude oil south to meet U.S. demand.

What is the controversy?
The U.S. is a major consumer of oil and petroleum-derived products.  

All major linear infrastructure projects tend to draw interest.  Significant projects, whether a pipeline for natural gas or oil, electric transmission line, or highway, often affect interests across a wide geographic range.  Relatively local siting concerns, like finding the best route for a given project and minimizing its direct environmental impacts, are common when planning any major infrastructure development.

In Keystone XL's case, project opponents point to additional concerns about the project's broader environmental impacts.  Some decry the proposal as increasing dependence on foreign oil, and believe the U.S. already has sufficient Canadian oil import capacity.  Others note that the oil to be shipped south over Keystone XL will be largely derived from Alberta's "tar sands" or "oil sands", and that extraction and production of crude oil from these sources involves greater greenhouse gas emissions or other environmental impacts.

What is happening now?
Concerns over the Keystone XL project are manifesting in multiple forms.  Protests have led to more than 1,000 arrests, including high-profile protestors like actress Darryl Hannah and NASA scientist James Hansen.  States affected by the pipeline proposal are moving cautiously; next week the Nebraska Legislature will meet at the request of Governor Dave Heineman to address concerns over Keystone XL.

To develop the project, TransCanada must secure a presidential permit to import oil across the national border.  While that permitting process initially appeared to be on track, 14 members of Congress have asked for a delay to allow an investigation into how the State Department performed its environmental review of the project.

The fate of the Keystone XL project depends on a number of factors, including whether it can secure a  presidential permit as well as how states react.  Part of the project's financing hinges on contracts to deliver crude oil as soon as 2014, and TransCanada is reportedly concerned that delay would jeopardize that financing structure.

How price predictions affect heating oil supply contracts

Wednesday, October 26, 2011

Nearly half the households in the northeastern region of the United States use heating oil to provide part or all of their space heating needs.  While natural gas fuels furnaces in many homes in other regions of the country, New England is a significant consumer of heating oil.  According to the U.S. Energy Information Administration, about 80% of U.S. households that use heating oil are located in the Northeast.

Those of us managing households in the Northeast know that heating oil companies typically offer customers different ways to buy oil.  The most basic approach is to buy oil on the spot market.  Under this approach, when a customer wants a delivery of oil, the customer can call around and select a supplier for a single delivery.  This approach lets customers benefit when prices go down, but leaves customers exposed to the market risk that prices may go up.

One alternative some customers prefer is locking in heating oil prices through a supply contract with a single supplier.  According to the EIA, customers' taste for this alternative changes based on predictions about future fuel prices.  In the middle of the last decade, about one-third of Northeast homeowners chose contracts; that number approached half of homeowners in 2008 in response to anticipated high fuel prices.  As it turned out, petroleum prices fell sharply in the second half of 2008; the fraction of homeowners with supply contracts fell to about 25% in both 2009 and 2010.  Now, the EIA reports that heating oil associations in the Northeast are predicting that even fewer customers will lock prices in this year.

Vermont wind project contested

Monday, October 24, 2011

A wind energy project in northern Vermont is the focus of significant controversy.  Utility Green Mountain Power is currently developing the Kingdom Community Wind project on Lowell Mountain near the town of Lowell in Vermont's Northeast Kingdom.  The 63 MW project is the first large-scale generation facility proposed by one of Vermont's investor-owned regulated utilities since the Searsburg wind project was approved in 1996. 

In May 2010, Green Mountain Power Corporation, Vermont Electric Cooperative, Inc and Vermont Electric Power Company, Inc. filed a petition with the Vermont Public Service Board seeking approval to build up to a 63MW wind generation facility, and to install or upgrade about 17 miles of transmission line and associated substations.

A year later, the Vermont Public Service Board issued its final order and certificate of public good approving the project (182 page PDF).  In the order, the Board found that "the proposed project will promote the general good of the state".  Among the factors supporting the Board's decision was the fact that the project would produce energy without greenhouse gas emissions, and would thus support the goals of the Regional Greenhouse Gas Initiative (RGGI).  The Board also noted that the project would help the state meet its goals of promoting new renewable generation as required in Vermont's SPEED, or Sustainably Priced Energy Enterprise Development Program.  SPEED requires that, by 2012, at least 10% of the state's electric load be served by new sources of renewable energy.  The Board also noted economic development benefits from the project, including job creation and tax revenues as well as the benefits of providing the developing utilities a long-term source of stably priced power.

The project drew opposition from a variety of sources, including those who oppose mountaintop wind development generically as well as those opposing development of this particular site.  Now, while Green Mountain Power is preparing the site for construction, a group of protesters has set up a camp near the ridgeline.  Abutting landowners have also asked a court to delay blasting and other work, claiming that they own part of the land where the blasting will occur.

What will happen to the Lowell Mountain project?  Green Mountain Power planned to complete the project by December 3, 2011.  As the Burlington Free Press has noted, the company has argued that delay is costly, and that too much delay would be fatal: Green Mountain Power must have project up and running by December 31, 2012 to qualify for $48 million in federal tax credit that are part of the project's overall financing plan.

Maine hydrokinetic energy project seeks pilot license

Friday, October 21, 2011

Hydrokinetic power plants can produce usable power from the energy contained in moving water into electricity.  Tidal currents, ocean waves, or water flowing through rivers can all be used to produce hydrokinetic energy.  (To learn more, check out my summary of what's happening with hydrokinetics across the country.)

Hydrokinetic energy development is generally regulated by the Federal Energy Regulatory Commission.  To be able to install and operate a hydrokinetic project at a given site, the developer typically goes through a multi-step regulatory process.  This usually includes securing a preliminary permit granting the exclusive right to study the site for several years, followed by the FERC license application process.

Maine is home to a number of issued preliminary permits for proposed hydrokinetic energy projects.  This month, one of those projects -- the Cobscook Bay Tidal Energy Project -- took a step forward, as its application for a pilot license was accepted by the Commission.

The Cobscook Bay project is proposed by ORPC Maine, LLC, a subsidiary of Ocean Renewable Power Company.  ORPC proposes to deploy its proprietary scalable tidal energy power system in Cobscook Bay near the city of Eastport and the town of Lubec, Maine.  Cobscook Bay's tidal energy resource has drawn interest for nearly 100 years, with proposals like the Passamaquoddy Power Project coming and going in that time.  Hydrokinetic technologies are enabling renewed interest in the bay's tidal energy resources.

ORPC's pilot license application envisions two phases of project development.  First, ORPC will test a single TidGen unit for one year.  Next, ORPC would add four more TidGen units to create a linked project.  Each TidGen unit has a maximum design capacity of 180 kilowatts, but is anticipated to produce only 60 kW during typical operations.  Electricity produced by the project would be brought ashore via a 3,600-foot underwater cable, where it would be conditioned and interconnected with the grid owned by Bangor Hydro Electric Company.

FERC gave notice that it accepted ORPC's application for processing on October 6, 2011.  Because ORPC is using the Commission's new pilot license process, the regulatory steps are more streamlined than for traditional hydropower licenses, and many of the deadlines are accelerated.  Comments, recommendations, motions to intervene or protests are due within 30 days from that notice of acceptance.

Bye-bye BOEMRE, hello BOEM and BSEE

Monday, October 17, 2011

The federal agency with prime responsibility for ocean energy development has been shuffled yet again.  After just over a year of operations BOEMRE - the former Bureau of Ocean Energy Management, Regulation and Enforcement - has been replaced by two offices: the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE).

This reshuffling is the latest organizational change to the federal oversight of ocean energy development, but it is not the first.  Until 2010, the Minerals Management Service (MMS) regulated both conventional oil and gas production and renewable energy activity.  In the wake of the Deepwater Horizon oil spill incident, and criticism of how MMS operated, U.S. Secretary of the Interior Ken Salazar restructured MMS into BOEMRE.

Now, BOEMRE has been split in two, with the division occurring along functional lines.  BOEM describesitself as “responsible for managing environmentally and economicallyresponsible development of the nation’s offshore resources”.  BOEM’s functions include offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, National Environmental Policy Act (NEPA) analysis and environmental studies.

Under the new paradigm, BSEE is responsible for safety andenvironmental oversight of offshore oil and gas operations, includingpermitting and inspections, of offshore oil and gas operations.  BSEE exercises functions including the development and enforcement of safety and environmental regulations, permitting offshore exploration, development and production, inspections, offshore regulatory programs, oil spill response and newly formed training and environmental compliance programs.

Feds decide not to delegate more transmission authority

Wednesday, October 12, 2011

Yesterday, I wrote about the Department of Energy's proposal to delegate increased electric transmission siting authority to the Federal Energy Regulatory Commission. Since the enactment of the Energy Policy Act of 2005, the Department has had the authority to study congestion on the transmission system, and designate national interest electric transmission corridors where it believes more transmission facilities are needed.  The act also gave the Commission “backstop” authority to approve transmission line routes when states fail to issue approvals within a year.

Until yesterday, Secretary Chu was considering whether to delegate the Department's congestion study and corridor designation functions to the Commission.   Supporters of the increased delegation said it would facilitate the development of new transmission facilities needed both for future load growth and to connect renewable energy resources to customers.  Opponents, including congressional leaders, noted that Congress had specifically divided the functions for good reasons, while states' rights advocates objected to increased consolidation in the Commission of power over transmission line siting -- traditionally a prerogative of each state.

Now, the Department and the Commission have issued a joint statement that transmission backstop siting authority will not be delegated.  Instead, the joint statement proclaims "enhanced cooperation" as an alternative to delegating additional authority to the Commission, along with process improvements within the Department to allow more expeditious transmission siting.

Federal authority over transmission siting may be reshuffled

Tuesday, October 11, 2011

U.S. Department of Energy Secretary Chu is considering a policy change that will affect how electricity transmission lines are sited and built.  Since the dawn of the electric power industry, states have had the authority over whether the siting of a given transmission facility should be permitted within their boundaries.  That traditional states’ right may be shifting away to the federal level.

Since the Energy Policy Act of 2005, the Department has had “backstop” authority to approve transmission line routes when states fail to issue approvals.  In 2007, the Department of Energy used this authority to designate corridors of highly congested transmission lines in the mid-Atlantic area (parts of Delaware, Ohio, Maryland, New Jersey, New York, Pennsylvania, Virginia, West Virginia, and the District of Columbia) and the southwest (parts of southern California and western Arizona).   

Proposed new transmission facilities located within these designated National Interest Electric Transmission Corridors can apply to the Federal Energy Regulatory Commission for siting approval if a host state does not approve the project within one year.  This could happen if a state regulatory proceeding drags on for longer than a year, or if state regulators condition project approvals in a manner that is not “economically feasible” – both results more likely to happen in connection with larger and more controversial transmission line projects.  While the Commission initially approved some transmission line siting applications that had been denied by state regulators, a federal appeals court held that the Commission lacked authority to approve a project in the face of a state’s affirmative denial (as opposed to mere regulatory delay).

At issue now is whether the Department of Energy should delegate its corridor designation function to the Federal Energy Regulatory Commission.  Proponents of the measure point to the need for increased transmission development, citing the growth of renewable resources located far from customer loads as well as transmission congestion; they believe the Commission will be better suited to the task of studying congestion and designating national corridors than the Department is.  Others oppose this proposed delegation, noting that Congress specifically divided the corridor designation and project approval functions between the Department and the Commission, and that states retain the ultimate rights to deny a siting application.  A number of comments have been submitted to the Department on this proposed delegation.