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.

US holds first offshore wind site lease auction

Yesterday the U.S. Department of the Interior held its first competitive lease sale for renewable energy on the Outer Continental Shelf.  With a total bid of about $3.8 million, Deepwater Wind New England, LLC won the rights to lease two parcels covering 164,750 acres offshore Rhode Island and Massachusetts.  What do the auction results mean?

Consistent with President Obama's climate action plan, the Interior Department is promoting the use of federal lands for the production of renewable electricity.  Yesterday's auction represents the first competitive auction for leases for offshore wind sites in federal waters.  Following significant stakeholder process, the Interior Department identified and refined the parcels off Rhode Island and Massachusetts, and solicited interest in leasing sites.  In June, the Interior Department announced that nine companies were legally, technically, and financially qualified to participate in the auction.

The auction took place in two phases in late July.  First, a panel met to consider non-monetary factors, including whether any bidders held agreements that could make their project a more realistic success.  For example, bidders demonstrating a power purchase agreement or joint development agreement could score bonus points enabling them to compete against higher monetary bids.  Deepwater Wind's joint development agreement with the State of Rhode Island thus gave it an advantage in the second round held on July 31.  This round took a more traditional auction format, with bidders placing a series of increasing bids until only one bidder remained for each parcel.

Three bidders participated in the auction: Deepwater Wind New England, LLC, Sea Breeze Energy, LLC, and US Wind Inc.  After 4 rounds, Deepwater Wind had won the south parcel for $94,153, and only one other company remained in the competition for the north parcel.  By round 11, Deepwater Wind had won the north parcel with a bid of $3,744,135.

With the auction completed, Deepwater Wind has 10 days to execute the lease agreements.  Its first rent under the leases will be due in 45 days.  Lease fees for the sites will be charged at $3 per acre, and if Deepwater Wind develops an operating project, it will also pay an annual fee roughly equal to 2% of its wholesale energy market revenues.

Building on this first auction, the Department of the Interior plans to hold a second auction for sites off Virginia in September.  Eight bidders have been deemed qualified to participate in the Virginia auction.  How many bidders will actually participate in the auction?  How much competitive interest will arise?  For what price will the parcels' lease rights sell?  Will the leases - whether off Rhode Island and Massachusetts, or off Virginia - lead to operating offshore wind projects?  Time will tell how the 2013 offshore wind lease auctions affect U.S. energy development.

Maine standard offer prices jump up 23%

The upward trend in wholesale natural gas and electricity prices in New England will begin to hit retail consumers later this summer, based on the bids accepted today by the Maine Public Utilities Commission for standard offer electricity service.

Following Maine’s deregulation of the electric power industry, transmission and distribution utilities no longer sell electricity but merely provide wires enabling the delivery of power. For their energy needs, customers may choose among licensed competitive electricity providers, or may receive so-called “standard offer service” by default. Most residential consumers receive standard offer service, while more than half of the load of medium and large commercial and industrial customers is served by customer-selected competitive providers.

The providers of standard offer service, and the prices customers pay for standard offer service, are selected by the Maine Public Utilities Commission through a competitive process. In deliberations this afternoon, the Commission established new prices for standard offer electricity supply service for medium commercial and industrial customers of Maine’s two largest utilities, Central Maine Power Co. and Bangor Hydro Electric Co. Over a six-month term starting on September 1, 2013, Central Maine Power’s medium commercial and industrial customers taking standard offer service will pay an average price of 7.5 cents/kWh. Bangor Hydro customers will pay 7.45 cents/kWh. These new prices are over 23% higher than current standard offer prices for these customers, and are between 17% and 19% higher compared to last year’s standard offer pricing.

Why have these prices gone up? One explanation is that suppliers are pricing the recent upward trend in regional wholesale natural gas and electricity prices into their retail bids. Wholesale electricity pricing in New England is generally set by the price of natural gas. Despite the availability of low-cost natural gas throughout most of the country, peak demands for natural gas in New England for heating and for electric power generation exceed the capability of the natural gas pipeline network to deliver gas into the region. As a result, the wholesale price of natural gas – and electricity – spikes as demand for gas increases.  Based on last winter's experience with this phenomenon, retail electricity suppliers are expecting similar high wholesale prices this winter, and are increasing their retail rate bids accordingly.

One solution that could keep downward pressure on the cost of natural gas and electricity is expanded pipeline infrastructure to enable a balance between supply and demand for natural gas deliveries into New England. New England states are working to promote this solution, which could save consumers over $1 billion per year. Until then, the likelihood is for continued upward pressure on wholesale electricity prices, and corresponding upward jumps in the retail price consumers pay for electricity as evidenced by the new standard offer prices.

FERC Order No. 784 boosts energy storage

Energy storage - the ability to store electricity and deliver it to the grid as needed - has the potential to create great value for society.  New technologies, ranging from batteries to mechanical flywheels, are expanding options for energy storage.  Now, a federal rule issued last week known as Order No. 784 significantly expands opportunities for energy storage providers to capitalize on these advances.

Traditionally, electricity has been difficult to store.  While society has been able to generate electricity for over a century, technologies to store that electricity once it has been generated have been elusive.  As a result, electric grid operators have needed to balance the supply and demand for electricity in real-time, leading to costly inefficiencies like the continual need to ramp generators up and down.  To keep the grid balanced, grid operators rely on so-called "ancillary services" like regulation and frequency response made possible by fine-tuning generators' output -- or now by energy storage technologies.

Despite recent federal rulings like the Federal Energy Regulatory Commission's Order No. 755 enabling enhanced compensation for energy storage, the market for energy storage has been restricted by regulation.  Until last week, the Federal Energy Regulatory Commission restricted third parties from selling ancillary services at market-based rates to public utility transmission providers under a 1999 ruling known as the Avista order.  Under Avista, transmission customers had two choices for how to procure their share of the grid's ancillary services.  First, customers could purchase ancillary services from their local public utility.  Second, customers could self-supply regulation and frequency response services - but could only do so from resources deemed comparable to those used by their public utility.  This restriction stripped away the benefit of self-supplying ancillary services because customers couldn't tailor their purchase of regulation and frequency response services to their own needs, but rather had to buy services based on their transmission provider's overall resource mix.  For example, customers were powerless to choose resources that could respond more quickly or more accurately than those used by their utility, meaning customers faced the risk of buying too much - or too little - ancillary services.

Order No. 784 significantly reforms the Commission's ancillary service regulations.  By November, public utilities must take into account the speed and accuracy of regulation resources, which opens the door for greater efficiency in transmission customers' purchase of regulation resources.  For example, Order No. 784 allows customers to save money by buying a smaller amount of faster or more accurate energy storage resources.

This flexibility creates a premium value for providers of these fast or accurate energy storage solutions.  Order No. 784 also eases the barriers for third-party entry into ancillary service markets, and revises accounting and reporting requirements to improve market transparency and better account for public utilities' use of energy storage devices.

Order No. 784 creates significant opportunities for utility customers, as it opens the door for lower-cost and more precise ancillary services.  The order also creates opportunities for innovative companies developing and implementing energy storage technologies like batteries, compressed air, and flywheels, as Order No. 784 both increases consumer demand for these technologies and reduces developers' barriers to entry into the markets.

For more information about Order No. 784 and the opportunities it creates, contact Todd Griset at Preti Flaherty at 207-623-5300.

Report: climate change poses risks to US energy sector

Climate change poses significant risks to U.S. energy infrastructure, and the reliability and cost of the services it enables, according to a report released yesterday by the U.S. Department of Energy.

The report - U.S. Energy Sector Vulnerabilities to Climate Change and Extreme Weather Report (4.2MB PDF) was developed as part of the Obama Administration’s efforts to support national climate change adaptation planning and to advance the U.S. Department of Energy’s goal of promoting energy security. These efforts are embodied by the Interagency Climate Change Adaptation Task Force and Strategic Sustainability Planning process established under Executive Order 13514.

The report is predicated on the findings that the U.S. climate is changing, and that these changes impact energy resources and infrastructure. As the report states, "Climatic conditions are already affecting energy production and delivery in the United States, causing supply disruptions of varying lengths and magnitude and affecting infrastructure and operations dependent upon energy supply." The report provides over 30 recent examples of energy infrastructure adversely impacted by climate change-related events such as power plant outages due to high temperatures or low water availability, storm damage to transmission lines, oil wells, pipelines and generators, and flooding-related disruption of fuel transportation systems.

Building on these findings, the report identifies a broad set of risks posed by climate trends, including increasing temperatures, decreasing water availability, and increasing storms, sea level rise, and flooding, as well as the current and potential future impacts of these climate trends on the U.S. energy sector. According to the report, each of these trends will independently, and in some cases in combination, affect the ability of the United States to produce and transmit electricity from fossil, nuclear, and existing and emerging renewable energy sources. These changes are also projected to affect the nation’s demand for energy and its ability to access, produce, and distribute oil and natural gas.

In particular, significant risks identified include:

• Thermoelectric power generation facilities are at risk from decreasing water availability and increasing ambient air and water temperatures, which reduce the efficiency of cooling, increase the likelihood of exceeding water thermal intake or effluent limits that protect local ecology, and increase the risk of partial or full shutdowns of generation facilities
• Energy infrastructure located along the coast is at risk from sea level rise, increasing intensity of storms, and higher storm surge and flooding, potentially disrupting oil and gas production, refining, and distribution, as well as electricity generation and distribution
• Oil and gas production, including unconventional oil and gas production (which constitutes an expanding share of the nation’s energy supply) is vulnerable to decreasing water availability given the volumes of water required for enhanced oil recovery, hydraulic fracturing, and refining
• Renewable energy resources, particularly hydropower, bioenergy, and concentrating solar power can be affected by changing precipitation patterns, increasing frequency and intensity of droughts, and increasing temperatures
• Electricity transmission and distribution systems carry less current and operate less efficiently when ambient air temperatures are higher, and they may face increasing risks of physical damage from more intense and frequent storm events or wildfires
• Fuel transport by rail and barge is susceptible to increased interruption and delay during more frequent periods of drought and flooding that affect water levels in rivers and ports
• Onshore oil and gas operations in Arctic Alaska are vulnerable to thawing permafrost, which may cause damage to existing infrastructure and restrict seasonal access, while offshore operations could benefit from a longer sea ice-free season
• Increasing temperatures will likely increase electricity demand for cooling and decrease fuel oil and natural gas demand for heating

Looking on the brighter side, the report notes that while climate change will, on balance, create challenges and costs for the energy sector, there are potential benefits to the energy sector as well. Examples include reduced average heating loads during the winter in parts of the United States, such as New England, and the opening of new regions to offshore oil and gas exploration due to shrinking sea ice cover in the Arctic. The report also covers adaptation actions underway, as well as other major opportunities to prepare for climate change through adaptation. Nevertheless, on balance, the report finds that the magnitude of the challenge posed by climate change on an aging and already stressed U.S. energy system could outpace current adaptation efforts, unless a more comprehensive and accelerated approach is adopted. Will the U.S. follow that path? What measures will it include? Will it make a difference?

Tackling New England natural gas pipeline constraints

Natural gas offers consumers a relatively low-cost energy source with fewer environmental impacts than coal or oil.  Throughout most of the United States, natural gas is displacing other fossil fuels in electric power generation, heating, and transportation.  But as a recent federal report found, inadequate pipeline infrastructure into New England is keeping prices for natural gas and electricity in the Northeast higher than in other regions.

In its 2012 State of the Markets report, the Federal Energy Regulatory Commission described how the availability of low-cost natural gas drove electricity prices downward last year.  However, as power plants, businesses, and homes convert to natural gas for their energy needs, growing competition between heating and electric load for a limited natural gas supply drives prices of both gas and electricity upward during the winter season.

New England's demand for natural gas peaks in the winter, due primarily to heating demand from the residential and commercial sectors.  As electric generators have increasingly turned to natural gas as the fuel of choice, total demand for gas has increased correspondingly.  In recent years, to meet peak demands for natural gas, New England has relied on imports of liquefied natural gas (LNG), as well as natural gas produced from Canada's offshore Sable Island field.  But last year, low domestic natural gas prices led to low imports of LNG and Canadian natural gas.  LNG imports hit their lowest level since 2002.  Sendout from the with Canaport LNG facility in St. John, New Brunswick, was drastically reduced, as LNG shippers chose to send their cargoes to higher-priced markets in Europe and Asia.  As FERC found: 

Lack of LNG and natural gas from Canada exacerbated pipeline constraints into New England from the southern supply corridor, including Marcellus Shale natural gas production, as New England relied more heavily on these pipelines for supply. This led to concerns that extreme cold weather could result in some service interruptions, particularly to power generators that generally rely on interruptible pipeline capacity to meet their fuel needs.

In particular, during cold snaps, demand from power plants coincides with peak residential and commercial natural gas demand.  Despite an unusually warm winter that suppressed residential and commercial load during the first quarter of 2012, demand reached pipeline capacity for part of the winter.  As a result, last winter New England consumers paid over a billion dollars more for natural gas and electricity than they would have if adequate pipeline capacity existed.

Unless LNG imports once again become economic, or domestic pipeline constraints are relieved, this situation is likely to repeat itself in New England next winter.  As consumers find wider uses for natural gas -- from converting vehicles and the transportation sector to compressed natural gas, to increased access to natural gas for home heating -- the number of days when demand reaches pipeline limits will likely grow.  This reality has led states like Maine to stimulate the development of new pipeline capacity by authorizing its Public Utilities Commission to enter into contracts for natural gas capacity.  While it may be several years until the constraints can be relieved, other states are likely to follow Maine in addressing the problem.