Dominion affiliate proposes Tazewell pumped storage project

A Virginia-based utility company has applied to federal regulators for a preliminary permit to study the feasibility of a pumped hydroelectric storage facility in the coalfield region of Southwest Virginia. If built, Dominion Energy Services, Inc.'s Tazewell Hybrid Energy Center Project could use mine water sources for the initial fill and makeup water. 

On September 6, 2017, Dominion Energy Services, Inc. filed an application to the Federal Energy Regulatory Commission for a preliminary permit, pursuant to section 4(f) of the Federal Power Act, proposing to study the feasibility of the Tazewell Hybrid Energy Center Project. As described in Dominion’s application, a September 7 press release, and a September 29 notice by the Commission, the Tazewell project would be a pumped hydroelectric storage facility. According to Dominion, the project would “be operated by Dominion Energy Virginia for hydropower generation during peak energy demand periods and pumping during off-peak energy demand periods.” Dominion points to grid benefits from pumped storage including integration of intermittent power generation sources, enhancement of grid stability and supply of other ancillary benefits. The applicant notes that the site “could support multiple configurations, including different-sized pumped-storage facilities,” a flexibility which Dominion said enables it to determine the best environmental, technical and economic solution.

The project would not use any existing dams or hydroelectric facilities, but would involve new dams and other facilities constructed for the proposed project. In its application, Dominion described two alternative configurations — a smaller Alternative 1 and a larger-capacity Alternative 2 – featuring an upper reservoir and a lower reservoir. Under either alternative, Dominion described potential water sources “for the initial fill and makeup water” as

(1) Mine ID P03_903 and (2) Mine ID P03_017. The initial fill water for the Project's reservoirs will be supplied by one or more of these water sources via a proposed pump and water conveyance system… Although the upper reservoir would be located on Oneida Branch and the lower reservoir would be located in West Fork Cove Creek, it is anticipated that the proposed Project will use mine water sources for the initial fill and makeup water.

Dominion says it will evaluate the feasibility of relying on mine water sources under the preliminary permit.

Dominion’s press release mentioned that it is also conducting in-depth studies of another potential site for a pumped hydroelectric storage facility, the former Bullitt Mine near Appalachia, Virginia. That mine has been closed since 1997 and is currently flooded.

In its application, Dominion cited 2017 Virginia legislation that it said “encourages one or more pumped storage stations and includes a requirement that all or a portion of it be powered by renewable energy produced in the coalfield region.”  That legislation amended existing law to allow a utility to petition the State Corporation Commission for approval of a rate adjustment clause to recover from customers the costs of “one or more pumped hydroelectricity generation and storage facilities that utilize on-site or off-site renewable energy resources as all or a portion of their power source and such facilities and associated resources are located in the coalfield region of the Commonwealth ... regardless of whether such facility is located within or without the utility's service territory.” The coalfield region is defined as including seven counties and one city: Lee, Wise, Scott, Buchanan, Russell, Tazewell and Dickenson Counties and the City of Norton.

Virginia offshore wind research lease

The U.S. federal agency responsible for leasing offshore wind sites on the outer continental shelf has executed its first wind energy research lease, giving Virginia's state energy agency the right to pursue the Virginia Offshore Wind Technology Advancement Project (VOWTAP), a 12-megawatt offshore wind test facility to be located in federal ocean waters.

Offshore wind energy offers the potential to generate large amounts of electricity from a renewable resource, but to date no commercial grid-tied U.S. offshore wind projects are operating.  The U.S. Bureau of Ocean Energy Management is responsible for leasing sites on the outer continental shelf for energy projects, including offshore wind and other renewable energy developments.  BOEM has auctioned off sites for offshore wind projects off several East Coast states, including Virginia, but had not previously issued a research lease.

On March 24, BOEM announced the execution of a wind energy research lease with the Commonwealth of Virginia’s Department of Mines, Minerals and Energy (DMME).  Under research lease OCS-A 0497 (35 pages), the Virginia agency proposes to design, develop and demonstrate a grid-connected, 12-megawatt offshore wind test facility on the Outer Continental Shelf off the coast of Virginia, in partnership with a local utility affiliated with Dominion Resources, Inc.

The 30-year lease covers approximately 2,135 acres of sea space east of Virginia Beach, adjacent to the Wind Energy Area leased to Virginia Electric and Power Company (dba Dominion Virginia Power) for commercial development since 2013.  The lease describes the project as "a research project to generate energy using wind turbine generators and conduct any associated resource assessment activities, as well as install associated offshore substation platforms, inter-array cables, and subsea export cables."  As a research lease, the Virginia agreement does not include any fees payable from DMME to BOEM "for the purpose of ensuring a fair return for the use of this lease area."

As is standard for BOEM's offshore wind site leases, the lease itself does not give the lessee the right to build or operate an offshore wind project.  Rather, the lease gives the Virginia DMME the exclusive right to submit to BOEM for approval a Site Assessment Plan and a Research Activities Plan, and then to allow a designated operator to conduct whatever activities are described in those plans once they are approved by BOEM. 

In this case, DMME has designated Dominion subsidiary Virginia Electric and Power Company as the lease operator.  Dominion's partnership with DMME on offshore wind dates back at least to 2012, when the U.S. Department of Energy announced funding awards for seven proposed Offshore Wind Advanced Technology Demonstration Projects.  Dominion won one of these 2012 awards, and partnered with DMME and others to establish VOWTAP.  VOWTAP won a second funding award from DOE in 2014 for deployment activities.

Dominion and DMME have already filed a Research Activities Plan for VOWTAP.  With the research lease in hand, the path forward includes approval of that plan and a Site Assessment Plan by BOEM.  If the VOWTAP project is built, the data obtained and lessons learned from this project will be made publicly available and inform the future production of renewable energy within the adjacent commercial Wind Energy Area leased to Dominion.

Exporting compressed natural gas from the US

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

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

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

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

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

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

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

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

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

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

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

FERC approves Maryland LNG project

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

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

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

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

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

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

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

Feds to auction Maryland offshore wind sites

On August 19, the U.S. Department of the Interior's Bureau of Ocean Energy Management will auction off rights to lease sites off the Maryland coast for offshore wind.  Through the auction, which will represent the third auction for offshore wind sites in federal waters since July 2013, the Bureau hopes it will award leases to two areas covering approximately 80,000 acres about 10 nautical miles east of the Ocean City coastline.

Last year, the Department of the Interior held its first offshore wind site auction for sites off Massachusetts and Rhode Island; Deepwater Wind won that auction with a bid of $3.8 million.  The second auction, held for Virginia on September 4, covered approximately 112,799 acres about 23.5 nautical miles from the Virginia Beach coastline; Dominion Virginia Power won that auction with a bid of $1.6 million.

The Maryland auction later this month will follow procedures similar to those used in the previous two auctions.  Based on previous expressions of interest and qualifications, BOEM has determined that sixteen companies are eligible to bid on the Maryland sites:

• Apex Offshore Maryland, LLC
• Bluewater Wind Maryland LLC
• Convalt Energy LLC
• Dominion Wind Development, LLC
• EDF Renewable Development, Inc.
• Energy Management, Inc.
• Fishermen’s Energy, LLC
• Green Sail Energy LLC
• IBERDROLA RENEWABLES, Inc.
• Maryland Offshore Wind LLC
• Orisol Energy US, Inc.
• RES America Developments Inc.
• SCS Maryland Energy LLC
• Sea Breeze Energy LLC
• Seawind Renewable Energy Corporation LLC
• US Wind Inc.

How many of these entities actually participate in the auction remains to be seen.  8 qualified bidders (or their affiliates) also qualified to participate in the Virginia auction, but only winner Dominion and an Apex affiliate ever placed bids.  For Massachusetts and Rhode Island sites, 9 companies qualified to bid but only winner Deepwater, Sea Breeze, and US Wind participated.

Offshore wind project developers must coordinate regulatory, financial, and engineering efforts.  Securing a site for a project is a major step forward, but is only one of many important steps necessary to build an operating offshore wind project -- something the U.S. still lacks.  How much interest will the Maryland auction draw?  Who will win the right to lease the two parcels in the Maryland wind energy area, and how much will they pay?  Will the auction winners actually build offshore wind projects?  Some of these questions will be answered when the auction closes on August 19.

End in sight for New England's largest coal plant

New England's largest coal-fired power plant will close by May 2017, according to its owner.  The Brayton Point Power Station in Somerset, Massachusetts, consists of three coal-fired units and a unit capable of burning natural gas and oil, with a net generating capacity of 1,537.6 megawatts.  Within 4 years, it will follow other large New England coal-fired power plants like Salem Harbor Power Station into history.

The Salem Harbor Power Station in Salem, Massachusetts, scheduled to close in May 2014.

The forces leading to Brayton Point's closure have been gathering for years.  The U.S. energy industry is in the midst of a revolution led by affordable and abundant natural gas supplies.  Meanwhile, tighter environmental regulations on air emissions from coal-fired power plants have made these traditionally cheap generators more and more expensive to run.  This past March, Brayton Point's previous owner Dominion Resources Inc. announced plans to sell the plant and two other fossil-fired plants to a subsidiary of Energy Capital Partners LLC.  That deal was consummated in August.

In an effort to keep the plant economic, Energy Capital Partners reportedly worked with regional electricity grid operator ISO New England Inc. on an agreement under which Brayton Point would have been paid for its ability to be called upon to provide electric generating capacity when needed.  But when Brayton Point demanded a higher price for this capacity than ISO New England was willing to offer, the generator submitted papers indicating that it would not provide capacity for the 2017-2018 forward capacity year.

Without those capacity market revenues, Brayton Point's owners have said it will close by May 2017, according to AP reports.  If it does, it will follow Salem Harbor and other coal-fired power plants around the country which have either closed or been converted to natural gas.  What will the future hold for Brayton Point's site in Somerset?  With transmission lines already in place, will it be redeveloped with other energy infrastructure?  What environmental issues will closure or repowering entail?

Dominion wins Virginia offshore wind lease

Dominion Virginia Power was the winning bidder in today's auction for the right to lease sea space off Virginia to develop an offshore wind project.  The auction, held the federal Bureau of Ocean Energy Management, was for a lease for a designated wind energy area covering about 112,799 acres of the outer continental shelf.  The site, about 23.5 nautical miles off the Virginia Beach coastline, is considered capable of supporting over 2,000 megawatts of wind generation.  

Prior to the auction, the Bureau of Ocean Energy Management approved eight bidders as eligible to participate.  But only Dominion and Apex Virginia Wind LLC participated in the auction.  By the sixth round, Apex dropped out and Dominion won.  While the official results have not yet been published, Dominion reportedly paid between $1.1 and $1.6 million for the right to this lease.

The Virginia auction follows July's auction in which Deepwater Wind paid $3.8 million for the right to lease 164,750 acres off Rhode Island and Massachusetts.  To compare projects against each other, one metric for evaluation is the effective premium the winning bidder paid in dollars per megawatt of resource potential in the area.  This premium represents the cost of outbidding the competition for the site, and is distinct from the ongoing lease payments that would ultimately be due when a lease is entered into.

With an estimated resource potential of 3,395 megawatts, the Massachusetts bid implies a lease premium of about $1.12 per megawatt of potential.  Dominion's winning bid for Virginia implies a lower lease premium of 55 to 80 cents per megawatt of potential.  The difference between these premiums could be due to a combination of several factors, including the degree of competitive interest in the site, and bidders' varying projections about the development, fixed and operating costs of a project.  The value of winning the lease also depends on the bidder's plans and capital availability.  Any development of the sites would likely occur in phases over the coming years, and seems unlikely to reach its full estimated potential in the near term.  Nevertheless, the lower Virginia lease premium illustrates the market results for this auction; its implications may depend on Dominion's plans.

The Bureau of Ocean Energy Management anticipates holding subequent auctions for offshore wind site leases elsewhere in the country in the coming months.  Will these leases lead to the development of offshore wind in U.S. waters?

FERC OKs sale of Dominion merchant power plants to Energy Capital Partners

Federal regulators approved yesterday the sale of three fossil fuel-fired power plants from energy company Dominion Resources Inc. to Energy Capital Partners LLC for $650 million.  The order by the Federal Energy Regulatory Commission moves the deal closer to fruition.  Is the transaction part of a trend in the U.S. energy industry?

Dominion is a major player in the U.S. energy business, serving customers in 15 states with its holdings in both the electricity and natural gas sectors.  Dominion owns a portfolio of about 27,000 megawatts of electric generation and 6,400 miles of electric transmission lines, as well as vertically-integrated electric utilities like Dominion Virginia Power.  Dominion also owns a large natural gas storage system as well as about 11,000 miles of natural gas transmission, gathering and storage pipelines.

Buyer Energy Capital Partners is a private equity firm focused on investing in North America's energy infrastructure.  The firm has recently acquired other electric generation plants, including the 830-megawatt combined-cycle natural gas-fired Red Oak power plant in Sayreville, New Jersey, and the 847-megawatt Broad River simple cycle, natural gas-fired power plant in South Carolina.

Over the past several decades, Dominion added merchant power plants designed not to serve the load of its affiliated utilities.  These plants produced electricity from coal, oil and other fossil fuels, and sold the power into regional wholesale markets such as those managed by ISO New England and mid-Atlantic grid operator PJM.  But with tighter environmental regulations, and more competitive electricity markets thanks to low-cost natural gas, many New England coal and oil-fired power plants have a hard time succeding in the current markets.  As an apparent result, in 2012 said it would sell or close its merchant coal-fired plants to realign its portfolio and improve return on invested capital and shareholder value, and sold the coal- and oil-fired Salem Harbor Power Station in Massachusetts.

In March 2013, Dominion announced a deal to sell its interests in three power plants to Energy Capital Partners.  1,528-megawatt Brayton Point Power Station, in Somerset, Massachusetts, is the largest remaining coal-fired power plant in New England.  It has three coal-fired units and one unit capable of being firing oil or natural gas, as well as the coal-fired 1,158-megawatt Kincaid Power Station in Illinois..  Dominion also offered its stake in 1,424 megawatts of capacity at the Elwood Power Station outside Chicago, which is powered by nine 158-MW natural gas-fired combustion turbines.

The deal price announced was $650 million.  At least one analyst has noted that after removing tax benefits, the deal implied an underlying price paid per kilowatt of capacity of just over $100, a price 30 times lower than the the cost of building a new coal-fired plant according to the U.S. Department of Energy.

The Federal Trade Commission approved the deal from an antitrust perspective under the Hart-Scott-Rodino Act in March 2013,  so the Federal Energy Regulatory Commission approval today was among the final approvals needed.

Fossil fuel and electricity markets are experiencing changes, from tighter air emissions to the prospect of federal carbon regulation.  Assuming the Dominion deal actually happens, does it signal a trend of utility divestiture of merchant fossil fuel-fired power plants?  Will other utilities exit the merchant electricity generation business?  Will we see increased transactional activity, as utilities sell their fossil fuel-fired plants?  For how much longer will the buyers run these plants?  In the case of the Salem station Dominion sold last year, buyer Footprint Power LLC is demolishing the old plant and redeveloping the site as a natural gas-fired power plant.  Will Energy Capital Partners choose to keep Brayton Point operating in a market where margins are often tight?  Or is this just the rationalization of Dominion's asset base, with no similar ripples throughout the sector?

Virginia offshore wind site leases to be auctioned

Next month the United States will auction off the rights to develop offshore wind energy projects off the Virginia coast.  The Virginia auction's results will shape the development of offshore wind in North America, as it will represent the nation's second competitive lease auction for commercial offshore wind projects.

As part of the Obama administration's efforts to promote the use of federal lands for the generation of renewable electricity, the federal Bureau of Ocean Energy Management is holding a series of auctions of the rights to lease sites in federal waters over the outer continental shelf.  On July 31, BOEM held an auction for sites off Massachusetts and Rhode Island.  In that auction, Deepwater Wind New England, LLC submitted the winning bid of about $3.8 million for the rights to lease two parcels covering 164,750 acres offshore New England.

BOEM will hold its second competitive lease auction on September 4 for sites off Virginia.  The Virginia auction will be for a single lease for a designated wind energy area covering about 112,799 acres.  The western edge of the lease area is located about 23.5 nautical miles off the Virginia Beach coastline.  If fully developed, BOEM expects the Virginia lease area to support more than 2,000 megawatts of wind generation.

The Virginia Wind Energy Area is outlined in blue in this map provided by BOEM.

BOEM's current offshore wind leasing program - known as "Smart from the Start" - features a process reliant on multiple rounds of proposals and calls for public feedback.  For Virginia waters, that process began in February 2012 when BOEM published a Call for Information and Nominations in the Federal Register.  The Call was designed to evaluate competitive interest for the area, as well as to seek public feedback on existing uses and other considerations relevant to leasing the sea space.  Simultaneously, BOEM published a Notice of Availability for the final Environmental Assessment and Finding of No Significant for commercial wind lease issuance and site assessment activities on the Atlantic outer continental shelf offshore New Jersey, Delaware, Maryland, and Virginia.

BOEM received eight nominations of interest in the lease area in response to the Call.  The eight companies responding with interest were:

• Apex Virginia Offshore Wind, LLC
• Arcadia Offshore Virginia, LLC
• Cirrus Wind Energy, Inc.
• Dominion Virginia Power
• enXco Development Corporation
• Fisherman’s Energy, LLC
• Iberdrola Renewables Inc.
• Orisol Energy US, Inc.

As with the recent auction for sites off Rhode Island and Massachusetts, some of these companies may not choose to participate in the auction.  While BOEM had found nine companies to be legally, technically, and financially qualified to participate in the New England auction, only three actually submitted bids.  For example, Fisherman's Energy and Iberdrola Renewables both qualified for the New England auction, but did not bid.

Assuming interest remains in the Virginia sites, the September auction is expected to yield a single winner.  That winning bidder will pay the amount specified in the final bid for the right to lease part or all of the Virginia wind energy area.  Development of an offshore wind project would then require a series of additional steps, ranging from financing to permitting to interconnection with the mainland grid.  Whether the auction actually leads to offshore wind development off Virginia will thus depend on a number of factors, but the September auction will represent an important step toward the development of the United States' offshore wind resources.

Will Virginia's feed-in tariff work?

Virginia’s largest electric utility is launching a feed-in tariff for solar energy – but will it work?

Feed-in tariffs are a policy tool used to facilitate the production of renewable electricity.  While six states and a handful of utilities have each designed their own programs, in general feed-in tariffs guarantee that customers who own solar panels or eligible renewable electricity generation projects a fixed price to sell the power to their local utility.  Building solar photovoltaic and other renewable generation technologies can have a relatively high capital cost, but the lack of a fuel cost can lead to low operational costs in the long run.  Customers, particularly businesses, say they need certainty about the internal economics of their project – whether revenue streams or savings off existing power bills – prior to committing the capital to actually build it.  Feed-in tariffs are one tool to address this uncertainty. Dominion Virginia Power serves ratepayers in the Commonwealth as Virginia Electric and Power Co.  It is a subsidiary of Dominion Resources Inc.  After securing an approval from the Virginia State Corporation Commission last March, the utility recently proposed a pilot feed-in tariff program for solar resources.  Under the Solar Purchase Program, Dominion will provide five-year contracts to purchase the energy produced by eligible rooftop solar projects and other distributed solar photovoltaic resources.

The program guarantees a price of 15 cents per kilowatt-hour over the contracts’ term. This price paid to solar energy producers is above Dominion’s recent retail average electricity price.  In 2012, Virginia's average retail electricity price was 10.5 cents per kWh for residential customers.  Commercial customers paid an average price of just 7.8 cents per kWh; the increased spread between the feed-in tariff rate for sales to the utility and commercial customers’ average price for purchases from it creates a strong incentive for commercial customers to develop solar projects.

Despite significant interest in Virginia and elsewhere in the development of the feed-in tariff, Dominion’s program is only a pilot project.  It applies only to residential systems up to 20 kilowatts and commercial systems up to 50 kW in size.  Moreover, the feed-in tariff is capped at 3 MW in total participating capacity.  Coupled with solar projects’ capacity factors, this limits the total volume of electricity to be purchased under the program.

Will Dominion’s feed-in tariff work?  The answer depends on what “working” means.  If the price spread between the feed-in tariff rates and retail rates, combined with other incentives such as federal tax credits, the feed-in tariff may be enough to encourage the development of some commercial and residential systems.  The utility and ratepayers may learn more about the costs and benefits of distributed generation.  To some degree, it may incentivize activity and competition in the solar installation business.

But where the program is capped at 3 MW, the current feed-in tariff program alone may neither spur much new investment nor cost ratepayers much.  Dominion’s recent peak loads were about 19,636 MW – so solar purchases would represent just hundredths of a percent by capacity, and an even smaller number by volume of electricity sold.  The entire program cap could be taken up by 60 commercial-scale projects, or even by 750 homes using Dominion’s estimated average of 4 kW per residential project.  It is unclear if this level of volume is enough to lead to a more robust installation services sector, or to lower costs for installed solar projects.

Implementation of Dominion’s solar feed-in tariff program will follow State Corporation Commission review and approval.

Georgia Power to close many coal-fired plants

Following the current trend of coal-fired power plant closures, electric utility Georgia Power has announced plans to retire 15 coal- and oil-fired generating units by April 2016.

Georgia Power is a vertically-integrated investor-owned public utility serving most of Georgia.  A Southern Company subsidiary, Georgia Power currently has 18,623 MW of generating capacity.  While its portfolio includes nuclear, natural gas and hydro generation, the bulk of Georgia Power's capacity is fueled by coal, with 11,387 MW of coal-fueled generation at 10 plants across Georgia.

This week, Georgia Power announced that it will request approval from the Georgia Public Service Commission to decertify and retire 15 coal- and oil-fired generating units, with a total capacity of 2,061 MW.  The company plans to request decertification of most of the units by April 16, 2015, the effective date of the U.S. Environmental Protection Agency's (EPA) Mercury and Air Toxics (MATS) rule requiring more stringent air emissions controls for fossil fuel-fired plants.  The utility cited factors including the cost to comply with existing and future environmental regulations, recent and forecasted economic conditions, and lower natural gas prices, as contributing to the decision to close these units.

Georgia Power's announcement follows other similar utility decisions to close coal-fired power plants, including Progress Energy Carolinas and Dominion.

Maine offshore wind projects win federal grants

The U.S. Department of Energy has announced an award of funding to seven offshore wind Advanced Technology Demonstration projects totaling $168 million over six years.  These projects are designed to achieve large cost reductions over existing offshore wind technologies and develop viable and reliable options for the United States.  Waters off Maine will be home to two of the projects:

• Statoil North America of Stamford, Connecticut plans to deploy four 3-megawatt wind turbines on floating spar buoy structures in the Gulf of Maine off Boothbay Harbor at a water depth of approximately 460 feet. These spar buoys will be assembled in harbor to reduce installation costs and then towed to the installation site to access the Gulf of Maine's extensive deep water offshore wind resources.
  
  
• The University of Maine, based in Orono, plans to install a pilot floating offshore wind farm off Monhegan Island.  This project will feature two 6-megawatt direct-drive turbines on concrete semi-submersible foundations. These concrete foundations could result in improvements in commercial-scale production and provide offshore wind projects with a cost-effective alternative to traditional steel foundations.
  

Each project will receive up to $4 million to complete the engineering, site evaluation, and planning phase of their project.  Five other projects were also selected for this first phase:

• Baryonyx Corporation, based in Austin, Texas, plans to install three 6-megawatt direct-drive wind turbines in state waters near Port Isabel, Texas. The project will demonstrate an advanced jacket foundation design and integrate lessons learned from the oil and gas sector on hurricane-resistant facility design, installation procedures, and personnel safety.
  
  
• Fishermen's Atlantic City Windfarm plans to install up to six direct-drive turbines in state waters three miles off the coast of Atlantic City, New Jersey. The project will result in an advanced bottom-mounted foundation design and innovative installation procedures to mitigate potential environmental impacts. The company expects this project to achieve commercial operation by 2015.
  
  
• Lake Erie Development Corporation, a regional public-private partnership based in Cleveland, Ohio, plans to install nine 3-megawatt direct-drive wind turbines on "ice breaker" monopile foundations designed to reduce ice loading. The project will be installed on Lake Erie, seven miles off the coast of Cleveland.
  
  
• Seattle, Washington-based Principle Power plans to install five semi-submersible floating foundations outfitted with 6-megawatt direct-drive offshore wind turbines. The project will be sited in deep water 10 to 15 miles from Coos Bay, Oregon. Principle Power's semi-submersible foundations will be assembled near the project site in Oregon, helping to reduce installation costs. 


• Dominion Virginia Power of Richmond plans to design, develop, and install two 6-megawatt direct-drive turbines off the coast of Virginia Beach on innovative "twisted jacket" foundations that offer the strength of traditional jacket or space-frame structures but use substantially less steel.
  

After the first phase, the DOE Wind Program will select up to three of these projects to advance the follow-on design, fabrication, and deployment phases to achieve commercial operation by 2017. These projects will be eligible for up to $47 million over four years, subject to congressional appropriations.

Wisconsin nuclear plant closing as gas boom cuts electricity prices

A Wisconsin nuclear power plant is slated for closure early next year, as electricity prices have fallen due to the proliferation of low-cost natural gas.

Dominion Resources Inc. announced yesterday that it will close its Kewaunee Power Station, a 556-megawatt nuclear power plant in Carlton, Wisconsin.  Located on Lake Michigan about 35 miles southeast of Green Bay, the Kewaunee plant features one Westinghouse pressurized water reactor.  The station began commercial operation in 1974, and was acquired by Dominion in July 2005.

Despite being relicensed by the Nuclear Regulatory Commission in 2011 for a new term through 2033, according to Dominion's most recent Form 10-K, Dominion faced a $66 million loss ($39 million after-tax) from operations of the Kewaunee plant.  Part of Dominion's problems likely arose from the relatively low price it could get for power produced from the plant.  While Dominion has cost-of-service-based contracts to sell the plant's output to two Wisconsin utilities - Wisconsin Public Service Corp. and Wisconsin Power and Light Co. - those contracts expire in 2013.

Meanwhile, the development of natural gas supplies from shale resources though hydraulic fracturing or fracking has led to significant decreases in the price of natural gas.  Since natural gas plays a significant role in the energy mix used to generate electricity, shale gas has led to decreases in the price of power.  This in turn has put pressure on electric generators powered by fuels other than gas.  Some of these generators have announced closures, while others are being converted to gas-fired generation.


Dominion had been trying to sell the plant since last year.  Between the lack of economies of scale resulting from the company's inability to grow its Midwest nuclear fleet, projected low wholesale power prices in the region, and no buyer for Kewaunee, Dominion now plans to decommission the plant in 2013.  If that happens, it will be the first permanent closure of a nuclear power plant since 1998.

Utility coal plants closing, natural gas to replace

A North Carolina utility closed one of its coal-fired power plants this past weekend, to be replaced with a natural gas-fueled combined cycle combustion turbine facility.  Duke Energy subsidiary Carolina Power & Light, which does business as Progress Energy Carolinas, announced on Friday that it would close its coal-fired H.F. Lee facility on September 15.  The Lee Plant closure is part of a broader shift away from utility and non-utility "merchant" use of coal to generate electricity, in favor of natural gas and other fuels.

Progress Energy Carolinas provides electricity to about 1.5 million customers in both North Carolina and South Carolina.  The utility owns more than 12,200 megawatts in generation capacity, and serves a 34,000 square mile territory, including the cities of Raleigh, Wilmington and Asheville in North Carolina and Florence and Sumter in South Carolina.

The Lee Plant's story resembles that of a number of other coal plants across the country.  Built in 1951 on the Neuse River near the town of Goldsboro, the plant was gradually expanded over time.  By the 1960s, the Lee Plant hosted three coal-fired units with a total generating capacity of 382 megawatts.  Four oil-fueled combustion turbine units were also added to the plant, adding another 75 MW of generating capacity, will be retired Oct. 1, 2012.

U.S. energy markets and environmental regulations continued to develop over the ensuing decades.  Most recently, tighter federal air emissions regulations and an abundant supply of low-cost natural gas have made older and smaller coal-fueled power plants uneconomic to operate.  As a result, owners are retiring these plants, and converting others to alternative fuels.  For example, last week utility Dominion Virginia Power announced plans to convert its Bremo Power Station in Virginia from coal to natural gas. 

Progress Energy Carolinas is following this trend.  The utility closed its coal-fired W.H. Weatherspoon power plant near Lumberton, N.C. last year.  It also plans to retire the remainder of its coal-fired plants without advanced environmental controls by the end of 2013: the Cape Fear Plant near Moncure, N.C., the Robinson coal-fired unit near Hartsville, S.C., and the L.V. Sutton Plant near Wilmington, N.C.  These coal-fired unit retirements will represent about a third of the utility's coal-powered fleet, or about 1,600 MW of generating capacity.

To replace the power produced from these closing plants, Progress Energy Carolinas is building new natural gas-fueled combined-cycle units.  Adjacent to the Lee Plant site, the utility is extending an existing natural gas pipeline and building a new, 920-MW natural gas-fueled combined-cycle facility.  This plant, along with the five dual-fueled combustion turbines at the existing Wayne County Energy Complex, will be called the H.F. Lee Energy Complex when complete.

Projections suggest that natural gas will remain available at a relatively low cost for the next twenty years.  At the same time, environmental regulations tend to grow tighter over time.  These two factors suggest that the current trend of utilities switching from coal to natural gas to fuel electric generation may continue for the foreseeable future.

Utilities switching from coal to gas

Utilities around the country are closing or converting older coal-fired power plants, and increasing the use of natural gas.  Pressure to make this shift comes from several factors, including tighter regulation of air emissions and the low price of natural gas compared to recent history.

The stacks of the Salem Harbor Power Station rise above Cat Cove in Salem, Massachusetts.  Dominion announced last year that it would close this plant, which it then sold to Footprint Power.

One electric generation plant that may illustrate this trend is Dominion Virginia Power's Bremo Power Station on the James River in central Virginia.  Originally built by the Virginia Electric & Power Company in 1931, the plant can now produce 227 megawatts of electricity by burning coal to boil water; the resulting steam spins turbines attached to electric generators.  According to Dominion, the Bremo plant consumes an average of 2,500 tons of coal per day.

This week Dominion announced plans to convert the Bremo plant from coal to natural gas.  In a filing with the Virginia State Corporation Commission, the regulatory body responsible for electric utilities, Dominion asked for approval to convert the plant over the next year at an estimated cost of $53.4 million.  If the SCC approves the conversion, the utility anticipates stopping coal consumption at the plant by the fall of 2013.

Dominion had previously agreed to convert the Bremo Power Station by spring 2014 as part of the air permit it received for the 585-megawatt Virginia City Hybrid Energy Center.  That plant entered commercial operations in July of this year, burning a mix of coal and biomass.

Dominion describes the Bremo conversion as being the ninth company-owned, coal-fired power station with units recently announced to be closed or converted to alternative fuels.  The utility points to the uneconomic nature of operating smaller, older coal-fired stations given the spread of cheaper natural gas and new environmental regulations requiring operators to retrofit plants with upgraded emission control equipment.  According to Dominion, the Bremo conversion would allow consumers to save about $155 million when compared to continued operation on coal.

Other utilities are making similar conversions or are considering closing some existing coal-fired plants. Natural gas consumption is on the rise, particularly in the electric generation sector.  At the same time, many utilities continue to rely on coal as part of their generation portfolio, as evidenced by Dominion's construction of the the primarily coal-fired Virginia City plant.  The trend appears to be one of closing or converting older or smaller coal-fired plants, consolidating coal consumption in larger, newer plants and increasing the use of natural gas to produce power.

Net metering and utility charges

As more electricity customers are installing solar panels and other distributed generation, many are participating in net metering programs under which they can run their utility meter backwards -- but utilities are complaining that net metering customers don't pay their share of the grid's operating costs.

In states and utility territories where net metering is allowed, customers can use eligible distributed generation (typically renewable generation like solar photovoltaic or small-scale wind, or micro combined heat and power) to offset their consumption of electricity from the grid.  Even if the customer draws power from the grid at some times and injects power back onto the grid at other times, net metering or net energy billing allows the customer to offset distributed generation against purchases. 

While many states embrace net metering as a policy, some utilities complain that net metering customers can be free riders.  If a customer's solar panels produce as much power in a month as the customer consumed, net metering could credit that customer with a zero utility bill - even though at various times times, the customer relied on the grid for imports and exports.  As a result, some utilities are seeking to impose new charges on customers for net metering.  For example, last fall Virginia regulators approved part of utility Dominion's request to impose "standby" charges on certain net metering customers.  Solar advocates and other distributed generation interests typically oppose such charges as roadblocks to achieving the societal benefits of net metering.

The issue continues to simmer around the country.  California utility San Diego Gas & Electric Co. recently proposed adding a "network use charge" onto customers' bills.  SDG&E's concept was that the charge -- about $22 per month for the average net metering customer with a solar PV system -- would properly allocate the cost of maintaining the grid to these customers.  The utility argued that without the charge, net energy metering customers were being subsidized by all other customers.  Earlier this year, California regulators rejected the idea (see the 16-page order at the California Public Utilities Commission website), noting concerns that the proposed charge "may be inconsistent with current law, regardless of whether it is justified by cost causation principles or an analysis of the crosssubsidies inherent in current policies."  As a result, SDG&E refiled its rate application without the charge.

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.

Virginia considers net metering and utility standby charges

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.