Monhegan island electricity grid updates

Thursday, December 20, 2012

Residents of the Maine island of Monhegan will soon benefit from upgraded electricity infrastructure, thanks to a grant from the U.S. Department of Agriculture.

Supplying electricity and other forms of energy on remote islands offers a unique set of challenges.  For islands too far from the mainland grid to be connected by undersea transmission cables, island utilities must both produce the power and distribute it to homes and businesses.  On small, remote islands, the lack of economies of scale can lead to very high electricity costs.  About 12 miles offshore, Monhegan one of those islands.  In recent years, customers served by the Monhegan Plantation Power District have paid electricity prices about 5 times higher than those on the mainland.

Propane tanks sit by the dock on Monhegan Island, Maine.
Yesterday the U.S. Department of Agriculture announced that the Monhegan Plantation Power District has won $420,154 from the USDA's High Energy Cost Grant Program.  That program provides competitively-awarded grants to improve and provide energy generation, transmission and distribution facilities serving communities with average home energy costs exceeding 275% of the national average. Grant funds may be used for on-grid and off-grid renewable energy projects, energy efficiency and energy conservation projects serving eligible communities.

On Monhegan, the grant will be used to replace the current switchgear, add a smaller, 40 kW generator to the power station's fleet, and add a 13 kW solar photovoltaic array to the power station's roof.  Currently, electricity is provided to about 100 accounts on Monhegan from a 300 kW diesel generator.  Demand for electricity on Monhegan varies seasonally, with many fewer consumers on the island during the winter months.  The new 40 kW generator and solar array are expected to be able to cover the winter load more efficiently than using the existing larger generator.

While Monhegan typifies the remote, inhabited small island, other islands face similar energy challenges.  Will Monhegan serve as an example for other island communities?

Maine ocean energy roadmaps

Monday, December 17, 2012

A coalition of Maine trade groups has released a pair of comprehensive permitting and regulatory road maps for developers of offshore wind, wave and tidal projects in Maine. The Maine Composites Alliance, Maine Wind Industry Initiative, and Environmental and Energy Technology Council of Maine (E2Tech) prepared these road maps to help steer potential developers and interested parties through federal, state and local laws and regulations applicable for ocean energy projects.

The documents can be obtained here:
Maine Composites Alliance is an alliance of composite businesses that work together to promote Maine's leadership in the international composites industry.  Maine Wind Industry Initiative is a collaborative created to organize Maine wind industry interests, link opportunities to Maine companies, relate industry needs to the state and federal government and act as a communication hub for Maine-based industrial partners in the wind energy industry. E2Tech seeks to build and expand the State's environmental, energy and clean technology sectors through networking and educational events, business development and sustainable job growth projects, and research, development and commercialization initiatives.

Waters off Maine are considered to be home to significant renewable energy resource potential.  Ocean Renewable Power Company has developed a marine hydrokinetic project off Eastport, and Statoil has proposed an offshore wind project off the Maine coast.  The roadmaps released today are designed to illustrate the path forward for offshore wind or MHK projects.  Developing renewable ocean energy projects requires developers to compile permits and approvals under over a dozen federal and state statutes.  Will the current regulatory structures lead to the development of more ocean energy projects off Maine and other U.S. coasts?

New England energy efficiency grows, saves

Thursday, December 13, 2012

Energy efficiency in New England has saved consumers significant money in recent years, and is changing the energy landscape in the northeastern U.S.  At a briefing yesterday, the region's electric grid operator announced that continued investment in electric energy efficiency has changed its load projections from modest growth to a flat forecast through 2021. 

ISO New England manages the energy markets and transmission grid in the six New England states.  ISO New England plans for future electricity needs, and develops forecasts for electricity consumption for the next decade.  In recent years, the adoption of energy efficiency measures has reduced society's demand for electricity.  From 2008 to 2011 New England spent $1.2 billion on energy efficiency through programs like Efficiency Maine and Mass Save.  ISO New England said that it expects spending on energy efficiency is expected to increase to $5.7 billion from 2015 to 2021.  As a result, electricity use previously projected to rise by 0.9 percent annually between 2012 and 2021 will instead be flat.

Customers win through energy efficiency in several ways.  Direct savings include the money they would have spent on electricity but for their efficiency increases.  The overall wholesale price of energy and capacity can also be reduced through greater adoption of energy efficiency.  Efficiency can also eliminate the need for some transmission upgrades; according to ISO New England, 10 transmission upgrades that earlier studies showed were needed to ensure reliability can be deferred until after 2020, saving consumers an estimated $260 million more.

Maine offshore wind projects win federal grants

Wednesday, December 12, 2012

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.

Maine utility launches time-of-use rates

A Maine electric utility has launched a program to offer residential consumers rates that vary depending on whether the consumption occurs during times of peak demand on the electric grid.  Central Maine Power Company's residential time-of-use rates are designed to encourage consumers to shift their use of electricity-intensive equipment to off-peak hours, generally between 8:00 p.m. and 7:00 a.m. and on weekends. How many customers will choose this option?  What effects will it have, both for the consumers opting in and for society as a whole?

Traditionally, electric ratepayers pay the same price for every kilowatt-hour of energy they consume, without regard to the time of consumption or to conditions on the grid.  But the cost of producing a given kilowatt-hour of electricity depends on factors including the portfolio of generators operating at the time, as well as on the instantaneous demand for electricity in the overall regional market.  Because they are not directly exposed to the real-time price of power, consumers individually and collectively may not make efficiency choices about how much power they consume, and when they consume it.  For example, energy prices are typically lower at night, when demand is reduced, but consumers have not traditionally had any incentive to shift their consumption to lower-priced nighttime hours.  Some utilities have offered industrial and commercial businesses time-of-use rates to encourage efficiency, but most residential ratepayers have not had this option in recent years.

Central Maine Power now offers residential consumers the option to choose time-of-use rates.  Prices during peak hours will be about 15 percent higher than under the default rate schedule, with off-peak prices about 20 percent below the default rates.  The structure offers the opportunity for consumers to choose to shift heavy-consuming applications like air conditioning and heating to off-peak hours.  This could save these consumers money - but it would require them to modify their behavior, invest in new "smart" technology, or both.  Will consumers find the opportunity for savings to be worth these changes?

The current enrollment window is open through January 31, 2013.

Civil engineers grade Maine dams D+

A group of civil engineers have released a report card for Maine infrastructure, giving Maine a C- overall and giving Maine's dams a D+.

ASCE's 2012 Report Card for Maine's Infrastructure (71-page PDF) comes four years after its first Report Card was issued in 2008.  The Report Card covers infrastructure including roads, bridges, railroads, ports and waterways, passenger transportation, airports, dams, municipal wastewater, municipal drinking water, contaminated site remediation, solid waste, schools, energy, and state parks.  It was prepared by a team of nineteen ASCE infrastructure leaders who analyzed issues including existing conditions, capacity, operations & maintenance or deferred maintenance, public safety & security, risk and consequences of failure, and current and projected levels of funding.

As the report notes, Maine has over a 1,000 dams, mostly privately owned.  153 of Maine's dams are classified as high- or significant-hazard-potential.  Dam safety is an important issue, both for dam owners and from a public policy perspective.  When dams fail, they can pose risks to people, communities, properties, and the environment.  According to the report, 131 federally regulated dams are in good repair, but most non-hydropower dams are subject only to state regulation.  Most of Maine’s dams are low-hazard potential, but are more than 50 years old.  Moreover, most of these dams do not generate revenues, making it harder to fund their upkeep even though they may provide values like maintaining lake environments for people and wildlife.

The ASCE report finds that Maine continues to fall well below the needed funding for dam safety inspectors and ranks near the bottom nationally for dam safety program funding.  The report critiques Maine’s Dam Safety Program, which spends much less than the other Northern New England states, is understaffed and has no enforcement division.

Will the ASCE report card lead to changes in how Maine regulates dams?  What funding sources are available to help private dam owners maintain their facilities in safe condition?  Will the state respond by revamping its dam safety program?

IRS reverses tax ruling on wind PPAs

Tuesday, December 11, 2012

The U.S. Internal Revenue Service has reversed its previous position on how it will treat power purchase agreements from wind energy facilities. 

Earlier this year, IRS issued a private letter ruling addressing a tax issue arising when a taxpayer purchases wind energy facilities operating under facility-specific power purchase agreements.  Under Section 167 of the Internal Revenue Code, which establishes how depreciation works under tax law, the computation of an adjusted basis for an asset is essential to calculating tax values and liabilities.  What happens when a taxpayer purchases a wind project that operates under one or more PPAs?  Should the purchase price affect the basis of the facilities, or should part of the purchase price be allocated to the PPAs?

In January 2012, in Private Letter Ruling 201214007, the IRS concluded that the purchase price should be included in the adjusted basis of the facilities, rather than allocating any portion of it to the PPAs.  Last week, the IRS issued Private Letter Ruling 201249013, which revokes its previous private letter ruling.  According to the new ruling, "the Service has determined that Private Letter Ruling 201214007 is not in accord with the current views of the Service."  Rather, the IRS now holds that the portion of the purchase price paid by the taxpayer that is attributable to the PPAs is to be allocated to the PPAs and not to the wind energy facilities.

While private letter rulings are directed to the specific taxpayers involved and may have limited precedential value, the ruling indicates a shift in the IRS's thinking about the tax treatment of transactions involving operating renewable energy generation projects.

Canada's largest wind farm built in Quebec

Thursday, November 29, 2012

A newly expanded wind farm on Quebec’s Gaspé Peninsula became Canada’s largest. commissioned wind project. The second phase of the Gros-Morne project came online, bringing the project’s total operating nameplate capacity to 211 megawatts.

Cartier Wind Energy Inc. developed and operates the Gros-Morne project. The company, known as Cartier Énergie Éolienne in French, was founded in 2004 as a partnership of TransCanada Corporation (62% owner) and Innergex Renewable Energy or its associated Innergex Power Income Fund (38).

Cartier submitted winning bids to provincial electric utility Hydro-Québec Distribution in response to its request for proposals seeking to buy 1000 megawatts of wind power from merchant projects on the Gaspé Peninsula. As a result, the company was selected to construct and operate six wind farms spread around the administrative region of Gaspesie, Iles-de-la-Madeleine and the Regional County Municipality of Matane.

Collectively, the Cartier projects’ total nameplate capacity will be 740 megawatts. Over 600 megawatts have now been commissioned, including the Baie-des-Sables, Carleton, L'Anse-à-Valleau, and Montagne Sèche projects in addition to Gros-Morne.

Cartier now ranks among Canada’s largest owners of wind generation capacity. Wind is a growing sector in Canada, with the Canadian Wind Energy Association projecting that the country will host 6,400 megawatts of wind capacity by the end of 2012, with Quebec alone accounting for over 1,247 megawatts.

FERC enforcement of energy laws

Wednesday, November 28, 2012

The Federal Energy Regulatory Commission is charged with enforcing statutes and rules covering much of the U.S. energy industry.  Its jurisdiction includes wholesale electricity market activity, electric and natural gas transmission and storage, and hydropower.  A report recently issued by the FERC's Office of Enforcement documents its enforcement activities in fiscal year 2012 (ending September 30, 2012).  The report illustrates the role of the Office of Enforcement and the importance of compliance by regulated entities.

According to the report, in FY2012, Enforcement focused on matters involving four kinds of conduct:
  • Fraud and market manipulation;
  • Serious violations of the Reliability Standards; 
  • Anticompetitive conduct; and
  • Conduct that threatens the transparency of regulated markets.
The report states that Enforcement does not intend to change its priorities in FY2013.

Organizationally, Enforcement currently houses four divisions: the Division of Investigations, the Division of Audits, the Division of Energy Market Oversight, and the Division of Analytics and Surveillance.  While these divisions are designed to coordinate on some enforcement operations, each has a specific mandate.

The Division of Investigations conducts public and non-public investigations of possible violations of the statutes, regulations, rules, orders, and tariffs administered by the Commission.  These investigations typically arise from self-reports, tips, calls to the Enforcement Hotline, referrals from organized markets or their monitoring units, other agencies, other offices within the Commission, or as a result of other investigations.  Where FERC Enforcement staff finds violations of sufficient seriousness, staff reports its findings to the Commission and attempts to settle the investigation for appropriate sanctions and future compliance before recommending that the Commission initiate a public show cause proceeding.

The Division of Audits administers the Commission’s audit and accounting programs. These programs help the Commission achieve effective and appropriate oversight of jurisdictional entities while maintaining accountability and transparency. To accomplish its mission, Audits conducts operational and financial performance and compliance audits of jurisdictional entities, and conducts other activities that aid the Commission. These audits and other activities assess how jurisdictional entities implement statutes, orders, rules, tariffs, and regulations the Commission administers.

The Division of Energy Market Oversight is responsible for monitoring and overseeing the nation’s wholesale natural gas and electric power markets. On a daily basis, Market Oversight examines and monitors the structure and operation of these markets to identify market anomalies, flawed or inadequate market rules, tariff and rule violations, and other unlawful behavior. Market Oversight administers, analyzes, and ensures compliance with the filing requirements for Electronic Quarterly Reports (EQRs) and various Commission financial forms.

The newest branch of FERC's Enforcement office is its Division of Analytics and Surveillance, created in February 2012 to develop surveillance tools, conduct surveillance, and analyze transactional and market data to detect potential manipulation, anticompetitive behavior, and other anomalous activities in the energy markets.  Analytics and Surveillance focuses on three areas: (1) natural gas surveillance; (2) electric surveillance; and (3) transactional analysis.  Within these areas, the Division of Analytics and Surveillance develops and refines surveillance tools to perform continuous surveillance and analysis of market participant behavior, economic incentives, operations, and price formation on both the natural gas and electric markets, to detect anomalous activities in the markets and identify potential investigative subjects.

Together, these divisions' FY2012 activities led to almost four hundred recommendations for corrective action and over $5.8 million in refunds, over $148 million in civil penalties and disgorgement of over $119 million in unjust profits in FY2012, and penalties for over 904 possible or confirmed violations.  In a future post, I will look at some of these specific enforcement cases in more detail.  It is clear that the FERC Office of Enforcement wields considerable power and is increasingly active.

Gila River Power, FERC enforcement settle for $3.4 million in market manipulation case

Wednesday, November 21, 2012

Federal regulators have amped up their investigations of businesses involved in U.S. energy markets in recent years.  This week the Federal Energy Regulatory Commission (FERC) approved a settlement between its Office of Enforcement and Gila River Power LLC over market manipulation claims, requiring Gila River to pay a punitive fine of $2.5 million, and disgorge unjust profits of $911,553 plus interest.  Notably, this settlement represents the first time that a market participant accused of manipulating power markets has admitted to unlawful energy trades.

Gila River is a subsidiary of Entegra Power Group LLC.  Entegra owns and operates four combined cycle power plants capable of producing about 3,300 MW of power.  Two of these plants are located at the 2,200 MW Gila River Power Station in Arizona, while the other four are located at the Union Power Station in Arkansas.  Entegra markets energy from these facilities to customers in the southeastern and southwestern U.S.

In the settlement agreement, Gila River admitted to using energy transactions known as "wheeling-through transactions" between July 2009 and October 2010 to manipulate prices in markets operated by the California Independent System Operator.  Because congestion on the transmission grid limited both the amount of power Gila River could import into California as well as the price it could get for that power, the company designed its transactions to avoid creating congestion so that it would receive a higher price on a higher quantity of energy imports.  This strategy involved claiming that it was simply passing power between two points outside California over transmission facilities located inside California, even though its transactions lacked a resource and a load outside the California markets as required by the CAISO tariff.

Under the FERC's enforcement procedures and penalty guidelines, the FERC assessed a base penalty amount based on its powers under the Federal Power Act, which allows it to levy fines of $1,000,000 per day for each violation.  The FERC then considered mitigating factors, including Gila River's cooperation in the enforcement investigation and its acceptance of responsibility for its violations.  Based on these factors, and negotiations between Gila River's legal counsel and the FERC's Office of Enforcement, the parties settled on a fine of $2.5 million, and disgorge unjust profits of $911,553 plus interest. 

While the Gila River settlement represents the first time an accused company has admitted market manipulation, FERC has used its enforcement powers more extensively in recent years.  In fiscal 2012, FERC approved nine settlement agreements entered into by Enforcement for total civil penalty payments of more than $148 million and disgorgement of more than $119 million plus interest.

Long Island utility exec resigns, hurricane response blamed

Thursday, November 15, 2012

The Long Island Power Authority announced this week that its Chief Operating Officer, Mike Hervey, has resigned from LIPA effective at the end of 2012.

LIPA is a political subdivision of the State of New York.  LIPA was formed in 1985 as a non-profit municipal electric utility to take over the assets of former investor-owned utility Long Island Lighting Company.  Today, LIPA owns the electric grid in most of Long Island.  LIPA does not own electric generation assets on the island but serves 1.1 million customers with electricity generated off-island.  Its electric distribution network was hard hit by Hurricane Sandy, with over 1.1 million customers losing power.  As of earlier this week, 10,000 customers just east of New York City were still without power, while 35,000 more farther onto Long Island suffered significant flood damage and will need repairs before electric service can be restored.  County executives and other leaders are calling for federal involvement, and have criticized LIPA for its management of the restoration process.

In a statement released November 13, LIPA Chairman Howard E. Steinberg stated that he had accepted Hervey's resignation, with regret, on behalf of the Board of Trustees.  The announcement noted that Hervey had worked for LIPA for 12 years, including serving as CEP for two years.

Also on Tuesday, New York Governor Andrew Cuomo formed a commission to investigate utility companies' storm preparedness and management.  Governor Cuomo used his powers under the Moreland Act to form the commission, whose mandate also includes an examination of the regulatory and legal structures for oversight of utility operations.  Citing storms including Hurricane Irene, Tropical Storm Lee, and Hurricane Sandy in the past two years, Governor Cuomo also addressed the adaptation process of adjusting "to the reality of more frequent major weather incidents".

One utility executive has already resigned, and the commission's investigation will soon be under way.  What other changes lie ahead for utility companies in New York and elsewhere as a result of utility responses to hostile weather?

From brownfields to renewable energy sites

Wednesday, November 14, 2012

Contaminated lands, landfills, and mine sites are increasingly being used as sites for renewable energy projects.  For example, many landfills may be suitable for siting solar photovoltaic panels.  Former industrial sites with subsoil contamination may not be suitable for redevelopment with buildings, but may be able to host solar or wind-based electric generation.  According to the U.S. Environmental Protection Agency, renewable energy systems have been installed at 60 such sites in 25 states.  What is the future of this trend?
EPA policy encourages renewable energy development on current and formerly contaminated land and mine sites when it is aligned with the community’s vision for the site.  Under EPA's RE-Powering America's Land initiative, EPA identifies the renewable energy potential of these sites and provides resources for communities, developers, industry, state and local governments.

An EPA report released earlier this month describes 60 renewable systems installed on potentially contaminated lands, landfills, and mine sites.  Of these, the majority (49) generate electricity through solar photovoltaic technology.  Seven generate electricity from the wind; biomass, geothermal, hydropower, and combined solar/wind round out the count.  Together, these resources provide 184.7 MW of electric generation capacity.  Most sell their power into the wholesale market, while some use the power on-site.

Host sites are split among private, federal, municipal, and state ownership.  Sites include those regulated under EPA's Comprehensive Environmental Response, Compensation, and Liability Act program (CERCLA, or Superfund), EPA's Resource Conservation and Recovery Act program (RCRA), brownfields, and landfills.

Many more potential sites exist.  Thousands of properties across the country face redevelopment challenges from contamination.  The country is home to over 3,000 active commercial landfills and 10,000 municipal landfills.  While not all may be suitable for renewable energy development, the concept offers the opportunity to create a revenue stream from property otherwise limited in use and saddled with environmental liabilities.  This revenue could be used for remediation of the sites' contamination, as well as for other purposes.  The trend of developing renewable energy facilities on contaminated lands, landfills, and mine sites is likely to continue for the foreseeable future.

Flow chart of 2011 US energy use

Tuesday, November 13, 2012

A flow chart released by the Lawrence Livermore National Laboratory illustrates the sources and uses of energy in the United States.  It depicts information about all the energy sources used to power society, as well as the breakdown of how that energy is used - or wasted - in electricity generation, transportation, residential, commercial, and industrial contexts.

On the energy source side, petroleum - oil, gasoline, and similar products - provides the largest share of the energy we consume, slightly more than a third of total energy.  Natural gas comes in second, providing about a quarter of total energy, with coal coming in at another 20%.  Altogether, these fossil fuels provided about 82% of the energy consumed in the U.S. in 2011.  Nuclear power provided about 8% of the energy used.  The remainder came from renewable resources including biomass, hydropower, wind, geothermal, and solar.

About 40% of the energy from these sources was used to generate electricity.  The remainder was used directly for other purposes such as transportation, heating, and industrial processes.

On the use side, transportation consumed the largest share of energy, about 28%.  The industrial sector consumed another 24% of the energy.  Households consumed about 11%, and commercial businesses consumed about 9%.

This analysis of energy use leaves about 27% of the energy unaccounted for.  This energy was consumed in the generation of electricity, but was "rejected", meaning that it could not be captured for a useful purpose.  Waste heat being emitted from a generator is a classic example of this rejected energy.  End users from industry to residences also waste or reject energy; in fact, according to the chart, 57% of the total energy consumed in the U.S. in 2011 was rejected, while only 43% was put to a useful purpose.

Vermont transmission line vandalism

Friday, November 9, 2012

Vermont's electric transmission authority has reported vandalism to a section of high-voltage line connecting Hydro-Quebec's grid to southern New England markets.  According to the Caledonian Record, 167 insulating discs were shot out from a transmission line in the town of Concord, Vermont.

Vermont Electric Power Company (VELCO) manages Vermont's electric transmission system, which includes, 738 miles of transmission lines, 13,000 acres of rights-of-way, 55 substations, switching stations and terminal facilities, interconnection facilities with Hydro-Quebec, as well as fiber optic communication networks that both control the electric system and provide the backbone for high-speed data internet access. VELCO was formed by the state's utilities in 1956 as the nation's first statewide, "transmission only" public utility.

Vandals reportedly used a shotgun to shoot the glass insulating discs which are spaced along the transmission lines and are designed to keep the lines safe from shorting out.  In all, 167 out of over 400 insulating discs were destroyed.  As a result, VELCO depowered the line until the discs could be replaced, which took from last Friday until last Sunday.  The repair itself cost about $250,000, but the biggest cost arose when regional grid operator ISO New England was forced to turn to the spot market to replace the electricity normally imported over the line from Quebec while the line was down.  The cost of that replacement power was reportedly over $1 million per day.

The incident is now the subject of a federal investigation.  Laws enacted after the widespread eastern blackout in 2003 and the September 11 terrorist attacks have increased the penalties for disrupting electric transmission and other infrastructure.  The insulating disc shooting may be treated as a "terrorist act" under federal law.

Transmission lines provide value to society, but are typically expensive and are often located in remote areas.  Hunting often occurs along or near transmission lines; just this year, VELCO won the National Wild Turkey Federation's Energy for Wildlife award for the company’s ongoing commitment to develop and improve wildlife habitat along its rights-of-way.  The extent of the damage to the insulating discs makes the shooting appear to be intentional, and thus more than a "hunting accident".  How will the incident affect transmission line owners' policies about public access to areas near lines?  How can transmission lines be better protected against vandalism?

Connecticut coal-fired power plant air permit issued

Thursday, November 8, 2012

The U.S. Environmental Protection Agency has approved a five-year permit for the last coal-fired power plant operating in Connecticut.  The plant, PSEG Power LLC's Bridgeport Harbor Generating Station, can generate 529 megawatts of energy by combusting coal and oil.

While the plant has operated since 1961, its permit renewal was questioned for economic and environmental reasons.  Across the nation, operators of coal plants have announced plans to close or convert plants to other fuels such as natural gas and biomass.  Between the low cost of natural gas - projected to stay low for the foreseeable future - and tighter environmental regulations affecting the electric utility sector, many older and smaller coal-fired power plants are no longer economic to operate.  Additionally, environmental activists have targeted coal-burning plants as polluters, and had argued against the Bridgeport Harbor plant's new permit.

Under the federal Clean Air Act, existing major stationary sources (i.e. those capable of emitting 100 tons per year or more of any criteria air pollutant) must obtain a so-called Title V permit every five years.  Generally, Title V permits are issued by the state or local air pollution control agency, but EPA has 45 days to review any proposed permit and request changes.  In September, Connecticut recommended that EPA renew Bridgeport Harbor's permit.  After the 45-day review process, EPA approved the permit's issuance.

What does the Bridgeport Harbor air permit mean?  Most directly, it means PSEG may continue to operate its plant for another five years -- if it wants to. According to the Connecticut Post, by mid-summer the plant had only operated 24 days this year.  The Bridgeport Harbor plant can provide both baseload power and peaking power needed to satisfy peak consumer demand, but generally the fewer days an asset operates, the harder it is to recover the cost of ownership and operations.

Moreover, coal-fired power plants are declining in the U.S.  This is particularly true in New England, a region far from coal mining.  Will PSEG hold onto the Bridgeport Harbor station and seek another Title V permit in 2017?  For how long will the plant continue to burn coal?  Will PSEG or another owner seek to repurpose the plant to burn other fuels?

Election 2012 and energy recap

Wednesday, November 7, 2012

With yesterday's general election behind us, people across the United States are considering its impact on energy policy.  From President Obama's retention of the White House to state elections and ballot measures, voters have reshaped the energy landscape.  Here are some highlights:

  • Congress remains divided.  At the federal level, Democrats held onto control of the Senate, while Republicans retained control in the House.  The chambers' partisan nature may lead to gridlock, or at least to consensus-based, relatively moderate measures as the only kind of legislation likely to meet the approval of both chambers of Congress.

  • Michigan rejects constitutional amendment on renewable energy.  Michigan voters rejected a proposed amendment to the state constitution that would have increased the amount of renewable energy that utilities must buy to serve their customers.  Proposition 3 would have required electric utilities to generate at least 25 percent of their annual retail sales of electricity from renewable energy sources by 2025.  Only 36% voted in favor of the measure to increase the renewable portfolio standard, meaning the RPS initiative failed.
Other election results, ranging from congressional races to state governor contests, will also shape energy policy in 2013 and beyond.  People and businesses that can react quickly will be in a better position to capitalize on the election results.

How Election 2012 affects energy policy

Tuesday, November 6, 2012

Today voters across the United States cast ballots in the 2012 general election. At stake are a broad range of political offices, ranging from the presidency to local municipal roles. How will the election's outcomes affect energy policy, energy-related businesses, and consumers?

The presidential contest has drawn the greatest attention over the past year. Whether President Obama will retain his office or Governor Romney will take the White House is the largest question. Based on the candidates' past actions and current campaign platforms, voters have some sense of how each would exercise his presidential powers. On energy issues, both candidates appear to favor increased domestic production of natural gas and oil. The candidates differ in their philosophies on the role of governmental incentives and subsidies -- whether for fossil fuel production or for renewable electricity generation -- and on emissions regulations for coal-fired and other power plants. The candidates also disagree on specific energy projects and programs ranging from the Keystone XL pipeline to the Navy's Great Green Fleet biofuels initiative.

Beyond the presidency, federal elections will determine the composition of Congress. While energy policy is more sensitive to presidential changes than to individual congressional elections, the makeup of Congress drives federal energy policy in the aggregate. All seats in the House of Representatives are up for grabs, as are a third of Senate seats. Of the 33 Senate seats, Democrats need to win 21 seats to retain their majority while Republicans need to win 14 seats to take control. The senators elected in 2012 will participate in setting any national energy policy.

State elections will also shape energy policy for the coming years. Voters will select governors in 11 states, and state legislative offices are widely contested. While federal energy policy draws the most attention, the U.S. federalist system leaves significant authority to individual states to set their own policies on energy issues. For example, states may establish electric renewable portfolio standards or otherwise regulate the resource mix used to produce usable energy. The outcomes of state elections will also affect policies on energy efficiency, smart meters and smart grid infrastructure.

Voters in some states will also cast ballots on measures directly affecting energy policy, such as the Michigan citizens' initiative seeking to increase utilities' use of electricity produced by renewable resources.

It may be some time until all the ballots are finally counted, but by tomorrow night we will have a better understanding of the results for most of the races and ballot questions. Those who can translate the election results into an understanding of future policies - and business opportunities - will have a leg up on the competition.

Hurricane Sandy prompts Jones Act waiver

Friday, November 2, 2012

Hurricane Sandy's disruption of petroleum shipments and refining has led Secretary of Homeland Security Janet Napolitano to issue a temporary waiver allowing foreign oil tankers to enter ports in the northeastern United States.

The Jones Act, a federal law enacted as part of the Merchant Marine Act of 1920, limits who may carry on coastal shipping between domestic ports.  This so-called cabotage law generally requires that all goods transported by water between U.S. ports be carried in U.S.-flag ships, constructed in the United States, owned by U.S. citizens, and crewed by U.S. citizens and U.S. permanent residents.

Hurricane Sandy's impacts to northeastern energy infrastructure included disruption of oil and gasoline supplies in the area near New York City and New Jersey.  Between reduced supply and concentrated demand, gasoline is reported to be in shortage conditions.  Long lines are reported at gas stations, and demand at some stations has led them to run out of gasoline. 

In an attempt to alleviate the shortage, today Secretary of Homeland Security Janet Napolitano issued a temporary, blanket waiver of the Jones Act.  The waiver is designed to allow foreign-flagged oil tankers, that would otherwise be barred from the U.S. coastwise trade, to ship petroleum products from the Gulf of Mexico to Northeastern ports.  The waiver will remain operative through November 13th.

Will Michigan vote for renewable energy as a constitutional amendment?

Thursday, November 1, 2012

Voters will decide a broad slate of issues in the upcoming U.S. elections on November 6, including many that address energy policy.  Questions range from who will serve as president to the role of government in managing the mix of energy resources used to power society.  In several states, voters will decide whether to increase renewable energy mandates.  One example of such a question is Michigan Proposal 3, a citizen-initiated ballot measure that would mandate that 25% of the state's electricity must come from renewable resources by 2025.
Under current law, Michigan's renewable portfolio standard requires electric suppliers to procure at least 10 percent of electricity from renewable sources such as wind, solar, hydro and biomass by 2015.  If enacted, Proposal 3 would increase this RPS requirement to 25% by 2025, and limit the impact of the requirement on electric rates to no more than a 1% annual increase.

The official text of Proposal 3 reads:

This proposal would:
  • Require electric utilities to provide at least 25% of their annual retail sales of electricity from renewable energy sources, which are wind, solar, biomass, and hydropower, by 2025.
  • Limit to not more than 1% per year electric utility rate increases charged to consumers only to achieve compliance with the renewable energy standard.
  • Allow annual extensions of the deadline to meet the 25% standard in order to prevent rate increases over the 1% limit.
  • Require the legislature to enact additional laws to encourage the use of Michigan made equipment and employment of Michigan residents.
Should this proposal be approved?
YES __
NO ____

The effort to place this question on the ballot has been led by a group called Michigan Energy, Michigan Jobs.  Supporters project that the amendment would help the local economy by creating over 40,000 jobs and attract $10 billion in new investments, as well as promoting public and environmental health.  Opponents, including a group called the Clean Affordable Renewable Energy for Michigan Coalition or (CARE) argue both that the increased renewable mandate would cost too much and that such a measure does not belong in the state constitution.

How will Michigan voters respond to this issue?  We will find out within the next week.

Assessing Hurricane Sandy's energy impacts

Tuesday, October 30, 2012

Yesterday Hurricane Sandy made landfall in New Jersey, but the magnitude of the storm meant that heavy winds, strong rains, and a powerful coastal storm surge affected a broad swath of the mid-Atlantic and northeastern parts of the United States.

One consequence of the storm is widespread power outages.  As of 8:00 AM yesterday, about 36,000 electricity customers had lost power in Connecticut, Delaware, New Jersey, New York, North Carolina, Rhode Island, and Virginia.  By 2:00 PM yesterday, outages were up to over 316,000, in the states listed above as well as in Maryland, Massachusetts, New Hampshire, and Pennsylvania.  At that time, New York had the most outages (105,089 customers, or about 1%), but New Hampshire was the hardest hit in terms of percentage affected (18,190 customers, or about 3%).  These reported outages came six hours before the storm officially made landfall, making outage numbers much higher today -- some reports indicating 8 million customers without power.

[Update: as of 9:00 AM this morning, the Department of Energy reports 8.1 million customers without electricity, including 62% of New Jersey, 31% of Connecticut, and 23% of Rhode Island.]

In addition to these power outages, some electricity generating facilities have shut down.  The U.S. Nuclear Regulatory Commission (NRC) reports three nuclear power units in the Northeastern United States had to shut down and two units reduced as a result of impacts from Hurricane Sandy.  Reasons range from water pump failure to encroaching high water to problems on the external power grid.

Another consequence of the storm is disruption to oil refineries.  By 1:00 PM yesterday, two mid-Atlantic refineries had closed, with four more shutting down part of their production.  In total, 1.1 million barrels per day of refining capacity had been disrupted due to the storm.

Today, as the storm has moved inland, crews are working hard to recover from the storm.  It is still early to assess the total damage from the storm, as well as whether its disruption to energy infrastructure will be temporary or longer-lasting.

Hurricane Sandy's effects on energy

Monday, October 29, 2012

Hurricane Sandy is expected to make landfall near the southern coast of New Jersey this evening.  The storm has already dealt damage to Cuba, Jamaica, and Haiti, and is expected to carry significant storm energy northward into the mid-Atlantic and northeastern United States.  Power outages are already being reported, but many more are expected: according to a Johns Hopkins engineering model, up to 10 million people may lose electricity in the mid-Atlantic over the next week.  Utilities are already staffing up and hiring external contractors to assist in the storm recovery efforts.  State governors are declaring a state of emergency to waive limits on how many hours utility workers can drive and work, to allow workers from other states and Canadian provinces to assist.

Hurricane Sandy's effects on energy are not limited to electric infrastructure.  Petroleum refineries - and by extension oil and gas markets - will also be impacted by the storm. According to a situation report released this morning by the U.S. Department of Energy's Office of Electricity Delivery & Energy Reliability, at least one petroleum refinery has already shut down.  Phillips 66's Linden, NJ refinery has shut down its production; the Linden refinery is capable of producing 238,000 barrels per day.

The report also cites trade press reports indicating reduced production at two other mid-Atlantic oil refineries, Philadelphia Energy Solutions’ Philadelphia, PA refinery (335,000 b/d capacity) and PBF Energy’s Delaware City refinery (182,200 b/d capacity).  Hurricane Sandy's impacts to refineries are not limited to those processing crude oil; the report also cites reduced production rates at Hess Corporation’s Port Reading, NJ facility (70,000 b/d capacity), which processes gas oils to produce petroleum products.

Collectively, these refineries do not account for a significant portion of the nation's refining capacity.  However, the impacted facilities' concentration in the mid-Atlantic may temporarily raise gasoline prices in the mid-Atlantic and northeastern U.S.  A key factor affecting the extent of this price bump will be how quickly the refineries can return to full production.

When tomorrow morning comes, the storm's direct impacts will be well underway, as will restoration efforts.  Last year's October storm, Hurricane Irene, left many electric utility customers without power for over a week.  How will Sandy compare to Irene?

NY releases Energy Highway Blueprint

Friday, October 26, 2012

This week New York Governor Cuomo released the New York Energy Highway Blueprint (12 megabyte PDF), the state’s plan to “rebuild and rejuvenate New York State’s electric power system and enable the state to meet the needs of a 21st century economy and society.”

The Blueprint outlines 13 recommended actions in four focus areas, including:
  • Expand and Strengthen the Energy Highway: building $1 billion of new electric transmission totaling over 1,000 MW of capacity, develop reliability contingency plans for power plant retirements (including energy efficiency and demand response), and support flexibility in public power authority contracting
  • Accelerate Construction and Repair: advance up to $800 million of investments in electric generation, transmission, and distribution, and advance up to $500 million of investments in natural gas distribution to reduce costs to customers and enhance reliability, safety, and emission reductions
  • Support Clean Energy: execute new contracts for up to $250 million within the next year with renewable energy developers under the Renewable Portfolio Standard to leverage an additional $425 million in private-sector investment to build up to 270 MW, study NY’s Atlantic offshore wind resource, and repower 750 MW of inefficient power plants on Long Island
  • Drive Technology Innovation: facilitate smart grid initiatives with the investment of up to $250 million
Nothing in the Blueprint is mandatory, but it appears to have significant political force behind it.  What will the Blueprint likely lead to?

One likely result is significant transmission development.  If this happens, the new transmission lines could enhance reliability and create opportunities for energy produced upstate or in rural areas to be transmitted to load centers like New York City.  Transmission line development typically involves significant construction work and related employment, but can be expensive.  How this transmission development will be paid for remains to be seen, and may not be resolved for several years.

Another area of interest involves the development of reliability contingency plans for power plant retirements.  The Indian Point nuclear plant, located about 30 miles north of NYC, is currently undergoing a relicensing proceeding before the Nuclear Regulatory Commission.  It is unclear whether either or both of the two reactors at Indian Point will be relicensed, meaning New York may need to secure replacement power by 2016 (or sooner).  The Blueprint recommends that contingency plans for partial or full retirement of the Indian Point plant include energy efficiency and demand response.

The Blueprint also includes plans to increase the availability of natural gas, including for the purpose of switching customers from oil to gas. The NY Department of Public Service is slated to issue a notice on natural gas expansion policies by the end of 2012. It is unclear how the program will split its focus between residential, commercial, and industrial customers, but it could help reduce the cost and environmental impacts of oil use in New York.

Overall, the Blueprint could result in the addition of up to 3,200 megawatts of additional electric generation and transmission capacity through up to $5.7 billion in private investments.  Over the upcoming months, state agencies and the New York legislature will consider the Blueprint, and whether and how it can be implemented.  At the same time, businesses are evaluating the Blueprint to see if it can help them develop renewable and traditional generation, transmission lines, energy efficiency, demand response, and other energy projects.

Renewables dominate new electric generating capacity

Wednesday, October 24, 2012

In September 2012, the United States added 433 megawatts of new utility-scale electric generating capacity - and according to a federal report, it all came from renewable resources.

The Federal Energy Regulatory Commission's September 2012 energy infrastructure update provides a summary of recent developments of natural gas, hydropower, electric generation, and electric transmission facilities.  For electric generation, the report provides a breakdown of newly installed capacity by resource type.

According to the report, 5 wind projects came online in September, totaling 300 megawatts of capacity:
  • EDF Group’s 140 MW Phase 1 Pacific Wind in Kern County, California
  • Forsyth Street Advisor LLC’s 57.6 MW Phase 1 Horse Butt Wind Farm in Bonneville County, Idaho
  • KODE Novus I LLC’s 80 MW Phase 1 Novus Wind Farm in Texas County, Oklahoma
  • Fire Island Wind LLC’s 17.6 MW Phase 1 Fire Island Wind Project in Anchorage Borough, Alaska
  • Kodiak Electric Association’s 4.5 MW Phase 2 Pillar Mountain Wind project expansion in Kodiak Island Borough, Alaska
Additionally, 18 solar projects came online in September, totaling 133 MW of capacity.  Among these are a number of projects earning "largest" ranks:
  • NRG Energy & MidAmerican Renewables, LLC’s 50 MW Phase 5 Aqua Caliente Solar Project expansion in Yuma County, Arizona came online.  The expansion brings the Aqua Caliente Project's operational photovoltaic capacity to 250 MW, making it currently the largest photovoltaic facility in the country.
  • Zongyi Solar America’s 20 MW Tinton Falls Solar in Monmouth County, New Jersey, the largest photovoltaic project in New Jersey
  • Southern Sky Renewable Energy LLC’s 5.6 MW Canton Landfill Solar Project in Canton County, Massachusetts, the largest solar facility in New England
The report indicates that no fossil fuel-fired generation came online last month.  The growth in renewable energy may be due to a variety of factors, including a rush to get wind projects built before the federal production tax credit expires at the end of the year, state renewable portfolio standards, and future projections about the cost of traditional fuels.  Nevertheless, wind and solar remain relatively small players in the nation's energy mix, with 4.43% of the nation's total generating capacity coming from wind and only 0.29% coming from solar.  Still, the growth of these resources illustrates recent investment's focus on the renewable power sector.

Wisconsin nuclear plant closing as gas boom cuts electricity prices

Tuesday, October 23, 2012

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.

Plan for solar on U.S. public lands advances

Monday, October 15, 2012

The U.S. Department of the Interior has finalized its general assessment of the environmental impacts of developing solar electric generation on public lands in six western states.  Last Friday's issuance of a Programmatic Environmental Impact Statement (PEIS) will expedite the permitting of solar energy projects in designated solar energy zones on federal land.

A view of the back a solar panel on public land in the Utah desert.
Part of the Obama administration's plan to encourage utility-scale solar energy development on federal lands, the finalization of the record of decision for the PEIS established an initial set of 17 Solar Energy Zones (SEZs) in Arizona, California, Colorado, Nevada, New Mexico and  Utah.  (Refer to DOI's map to see the general location of the zones.)

These initial 17 zones cover about 285,000 acres of public lands, and were designated based on factors including environmental suitability and access to transmission lines.  The Interior Department projects that if fully built out, the designated zones could be home to up to 23,700 megawatts of solar energy, an amount sufficient to power about 7 million homes.

The approved solar plan also allows a case-by-case evaluation of solar projects on another 19 million acres in “variance” areas outside the designated zones.  At the same time, the plan excludes almost 79 million acres deemed "inappropriate for solar development based on currently available information."

Notably, the PEIS does not pre-approve any specific plan.  Each project proposed in the designated zones will still require its own environmental review and other permitting.  Nevertheless, the solar plan may facilitate significant development of solar energy projects on public lands in the western United States.

NJ declares NRG Bluewater abandoned offshore wind project

Thursday, October 11, 2012

Finding that the developer has abandoned the project, New Jersey regulators have withdrawn $3 million in financial support for an offshore wind project proposed by NRG Bluewater Wind

The U.S. and New Jersey flags, flying in the sea breeze at Cape May, NJ.

Bluewater Wind New Jersey Energy LLC proposed a 350 megawatt wind project off the New Jersey coast.  In 2008, the company won a $4 million grant from the state to install an offshore meteorological tower as part of a state-sponsored offshore wind grant solicitation.  The grant agreement required Bluewater to install the tower by 2010, and took the form of a rebate: if Bluewater installed the tower by the deadline, it would receive $4 million back from the state.

NRG Energy - a Fortune 250 wholesale power generation company controlling nearly 26 gigawatts of capacity - acquired Bluewater in 2009.  Also in 2009, Bluewater asked for and received a one-year extension of the met tower deadline.

In October 2010, Bluewater requested another extension, this time for two years.  Bluewater pointed to difficulties in obtaining federal permits for the project.  The NJ BPU granted the extension on April 27, 2011, requiring regular progress reporting and installation of the met towers by January 9, 2013.  The BPU also lowered the rebate amount to $3 million.

According to the BPU's October 4, 2012 order cancelling the rebate, Bluewater filed progress reports with the BPU in 2011 and January 2012, but ultimately stopped reporting.  But in December 2011, NRG announced that it was putting active development of offshore wind projects on hold.  By September 2012, BPU staff put NRG on notice that they planned to recommend that the Board cancel its rebate commitment "due to project abandonment and lack of reporting".  According to the BPU's order, "the company did not object or otherwise respond when advised of staff's recommendation to withdraw the rebate commitment".

As a result, last week the BPU found that the company had not complied with the order requiring status updates, and thus "that NRG Energy and Bluewater have abandoned the project and will not meet the rebate commitment requirements."  The Board cancelled the met tower rebate, and directed BPU staff to reallocate the funding to other New Jersey Clean Energy Programs.

Maine energy corridor proposals solicited

Wednesday, October 10, 2012

Maine is soliciting letters of interest in using state-owned highway corridors as paths for electric transmission lines.  Resulting from a state law enacted in 2010, the solicitation may lead to the development of transmission lines along state-owned highway routes including I-95 and I-295.

Siting transmission lines and other linear infrastructure can be challenging, as routes typically are narrow but must be uninterrupted over long distances.  The diversity of landowners along most proposed routes can lead to difficulties in negotiating leases or purchase prices for the land rights, or enmity if the developer uses eminent domain powers.  Because state-owned highway routes have a single owner and are already linear, existing highway corridors can provide a natural route for transmission lines.  If lease payments are set properly, the state can create a new source of revenue to support energy initiatives or other governmental objectives.

Maine sits in a strategic position that may enhance its opportunity to capitalize on highway corridor leasing.  Maine is viewed as the New England state with the best sites for development of renewable electricity generation; this electricity generally must flow out of state to more power-hungry markets in Boston and points south.  The state also sits between generation in Canadian provinces and southern New England's significant consumer demands, increasing the pressure for transmission development.

But allowing transmission line development in highway corridors may not come without risk.  If lines are permitted, they may limit future opportunities to develop higher-value infrastructure along the same key routes.  Transmission lines allowing Canadian power to flow to Boston could also dampen the market for development of in-state energy projects, which typically provide greater economic development prospects than would a transmission line connecting out-of-state resources.  Depending on how their costs are allocated at the regional level, transmission lines could also lead to higher electricity rates for Maine consumers.

Under the 2010 law, Maine formed an interagency review panel to develop rules and conduct a competitive solicitation for potential energy corridor developers.  The law also provides that highway corridor transmission developments are subject to a standard of review requiring developers to demonstrate that their projects will not impede in-state electricity generation, but will lower electricity rates and energy costs for Maine consumers.

The interagency review panel is now soliciting letters of intent to seek corridor rights.  Proposals will be reviewed on a rolling basis.  Once the panel receives one or more proposals, it will begin the process of evaluating their specifics to screen out proposals that fail to meet the standards.

Maine PUC declines to OK Statoil offshore wind term sheet

Thursday, October 4, 2012

Today the Maine Public Utilities Commission declined to approve a term sheet offered by Statoil North America, Inc. for a long-term power purchase agreement from its proposed Hywind Maine floating offshore wind project.

Sutton Island, Maine, about 80 miles downeast of the proposed Hywind Maine project.
In 2010, Maine enacted a law designed to support the development of offshore wind and other marine renewable energy projects.  Among other features, that law required the state Public Utilities Commission to conduct a competitive solicitation for proposals for deep-water offshore wind energy pilot projects, meaning grid-tied floating wind projects at least 10 nautical miles offshore.  The statute gave the commission authority to direct mainland utilities to enter into power purchase agreements with one or more responding developers if certain minimum criteria were met.  This authority was discretionary, meaning the commission could choose not to order the utilities to sign a deal even if it met those criteria.

In September 2010, the commission issued its request for proposals under the program. Over the ensuing years, Statoil emerged as the apparent leading respondent, proposing the "Hywind Maine" project, a four-turbine, twelve megawatt project south of Boothbay Harbor.  Commission staff and Statoil negotiated the terms of a proposed power purchase agreement, which became public this summer.  Among those terms was a proposed energy price of between $290 and $320 per megawatt-hour, escalating annually, for the first 41 gigawatt-hours of energy produced each year.

That term sheet was the subject of deliberations by the Maine commission this morning.  After two hours of discussion, two of the three commissioners had stated that they would vote against approving the term sheet.  They expressed concerns about the cost of the contract, as well as uncertainty over the deal's benefit to Maine and Maine ratepayers.

The Maine commission's action bears some resemblance to that of the Rhode Island Public Utilities Commission in 2010 when it rejected a proposed contract between utility National Grid and offshore wind developer Deepwater Wind on the grounds that $244 per megawatt-hour was not a "commercially reasonable" price.  The Rhode Island commission ultimately approved a renegotiated deal with Deepwater Wind at a comparable price.  Similarly, the Maine commission invited Statoil to revise its proposal to offer more benefits to Maine, and to present a renegotiated deal for further deliberation.  Will Statoil be able to sweeten its offer and convince the commission that its contract is a good deal for Maine?

National Park Service OKs transmission line on park lands

Wednesday, October 3, 2012

The National Park Service has given its final approval to a proposed high-voltage electric transmission line that would cross public lands in Pennsylvania and New Jersey, including the Delaware Water Gap National Recreation Area, the Middle Delaware National Scenic and Recreational River as well as the Appalachian National Scenic Trail.

The 500 kilovolt transmission line, known as the Susquehanna-Roseland line, has been proposed by utilities PPL Electric Utilities and Public Service Electric and Gas Co. It would run 145 miles from Susquehanna, Pennsylvania to Roseland, New Jersey.  Mid-Atlantic electric grid operator PJM, Inc. and national electric reliability organization NERC had called for the line to protect the grid's reliability by preventing existing power lines from facing overloaded conditions.  The line also received a fast-track review by federal agencies under the auspices of the Interagency Rapid Response Team for Transmission, a group formed to coordinate on an expedited review of transmission projects designed to increase grid reliability, integrate new renewable energy, and cut consumer costs.

While the line's route largely followed existing rights-of-way, environmentalists and park activists challenged the National Park Service's approval of expansions to the rights-of-way through these national parklands.  The New Jersey Board of Public Utilities' approval of the project was also challenged, on the grounds that the state board failed to give adequate consideration to non-transmission alternatives that could have met consumer demand, such as programs promoting demand response and energy efficiency.  That case remains pending.

On Monday, the National Park Service issued its record of decision approving the line (31-page PDF).  As a condition of approval, the NPS required the developing utilities to contribute at least $56 million to a
fund to mitigate the line's impacts on federal lands by purchasing or otherwise conserving land for public use, compensating for impacts to wetlands affected by the line, and funding cultural and historic preservation in the affected parks.

In a Facebook post issued yesterday, the New Jersey chapter of the Sierra Club vowed to challenge the NPS's approval of the line in court.  PPL and PSE&G plan to place the line in service by June 2015.

Commercial fishing and solar energy

Tuesday, October 2, 2012

Commercial fishing businesses tend to consume significant amounts of energy, but may be able to offset their energy expenses by turning to solar panels and other distributed electric generation.

The winter fishing fleet of Northeast Harbor, Maine.

According to the National Marine Fisheries Service, the U.S. commercial fishing sector landed $5.3 billion in seafood last year.  Alaska led the nation in total catch value in 2011, landing $1.9 billion in fish and shellfish.  Massachusetts came in second at $570 million, with Maine coming in third at $426 million.

Catching this seafood comes at a price.  Diesel and other marine fuels account for a significant fraction of commercial fishermen's expenses.  Onshore, electricity powers stationary facilities like freezers, refrigerators and pumps for holding tanks, with seafood processing operations consuming even more power.

The location of many commercial fishing businesses -- typically located on the coast, often on a pier or wharf exposed to the sun and wind -- may create an opportunity for fishermen to offset their energy costs by producing their own electricity.  One Maine lobsterman recently added a 10-kilowatt solar array to his wharf in Harpswell. Funded in part by an $11,750 grant through the U.S. Department of Agriculture's Rural Energy for America Program, last month Potts Harbor Lobster added 44 solar panels to two roofs on the Reversing Falls Lobster wharf in South Harpswell.

In addition to USDA REAP grants, additional incentives are available that may shorten the payback period for distributed generation projects at commercial fishing facilities.  For example, Maine's net energy billing law allows consumers to use solar or other distributed generation to effectively spin their electricity meters backwards.  Consumers in almost every state can use similar net metering programs to sell excess power back to the grid, offsetting their electricity bill.  Other states, like Massachusetts and New Jersey, allow consumers to produce and sell solar renewable energy credits (sometimes called SRECs) from grid-connected solar photovoltaic panels.  These SREC sales can create a significant revenue stream for people and businesses who develop qualified renewable power projects.

Not every site may be well-suited for distributed generation projects.  Given relatively high capital costs for many small renewable power projects, payback periods may be too long for some businesses to make the investment.  However, as the cost of electric transmission increases across the country, the traditionally self-reliant fishing industry may increasingly turn to solar energy and other distributed generation technologies.

Obama blocks Chinese co wind acquisition

Monday, October 1, 2012

President Obama has blocked a Chinese-owned company's acquisition of four Oregon wind farm development companies, citing "credible evidence" that the company "might take action that threatens to impair the national security of the United States."

Wind energy project Ralls Corporation had acquired four wind project development companies in Oregon earlier this year.  Those companies -- Lower Ridge Windfarm, LLC, High Plateau Windfarm, LLC, Mule Hollow Windfarm, LLC, and Pine City Windfarm, LLC -- were developing wind projects in or near restricted airspace at the Naval Weapons Systems Training Facility in Boardman, Oregon. Ralls is owned by two executives of Chinese wind turbine manufacturer Sany Group, whose turbines were to used in the Oregon projects.

Earlier this summer, as Ralls acquired the project companies from Terna Energy USA Holdings Corporation, the Committee on Foreign Investment in the United States (CFIUS) began to review the transactions.  The CFIUS -- an interagency panel whose purpose is to review transactions that could result in the control of a U.S. business by a foreign person in order to determine the effect of such transactions on the national security of the United States -- determined that "there are national security risks to the United States that arise as a result of the Transaction" and issued a series of orders compelling Ralls and the project companies to cease work and stay away from the project sites.

In an order issued last Friday, President Obama formally prohibited the transaction, and ordered Ralls to divest itself of the project companies and their assets within 90 days.  Ralls is prohibited from selling the companies and assets until it removes everything from the project sites, and must give the CFIUS an opportunity to reject the proposed third-party buyer.  The order cites Section 721 of the Defense Production Act of 1950 as authority.  The Ralls order appears to be the first presidential exercise of this power since 1990, when President George Bush issued an order banning the China National Aero-Technology Import and Export Corporation from acquiring a Seattle-based aerospace developer.

Ralls has reportedly challenged the order in a lawsuit filed with the U.S. District Court in Washington, D.C.

Champlain Hudson Power Express debated

Thursday, September 27, 2012

As policymakers seek to secure energy supplies for the future, how far abroad should they cast their nets?  In addition to cost, reliability, and energy mix goals like renewable electricity standards, should decisions be made based on other factors such as local economic development?

New York legislators debated these questions yesterday in hearings over a proposed transmission line that would connect New York City to Canadian hydroelectric generation.  The $2.2 billion high-voltage direct current line, known as the Champlain Hudson Power Express, would run from the U.S.-Canadian border to the New York metro area. The line would run underwater through Lake Champlain, the Hudson River, and East River for much of its route, with the remainder of the line buried underground.

The Champlain Hudson Power Express was first proposed in 2010, and has been the subject of controversy.  New York Governor Andrew Cuomo has launched the N.Y. Energy Highway program, a public-private initiative to upgrade and modernize New York State’s energy system.  The Champlain Hudson Power Express's developer, Blackstone Group, L.P. subsidiary Transmission Developers Inc., is promoting the line as part of that solution.  It would connect over 1,000 megawatts of Canadian generation - primarily Hydro-Quebec's hydropower projects, as well as some wind - to power-hungry consumers in the New York City area.

Some stakeholders question the effects of the line on existing and new generation in New York.  Older domestic power plants may be unable to compete with the Canadian power; if imports are priced just below what domestic generation needs to operate, the result could be a loss of jobs and tax revenues without significant consumer savings.  Stakeholders such as the International Brotherhood of Electrical Workers Local 97, representing more than 4,000 workers in electric generation and utility jobs in New York, have publicly opposed the project on these grounds, while calling for growth of domestic generation projects.

The Canadian power might also compete with existing and proposed indigenous renewable power projects.  New York has adopted a renewable portfolio standard of obtaining 30 percent of its electricity from renewable sources by 2015.  New York currently excludes large-scale hydropower projects from qualification for its RPS, but Canadian imports could dampen market demand for in-state renewable generation.

The Champlain Hudson Power Express reportedly featured prominently in a public hearing held yesterday by the New York Senate Standing Committee on Energy and Telecommunications to "consider and analyze the long-term base load energy generation and transmission needs of the State of New York".  Debate over the proposed line is likely to continue, with economics and regulation likely to play key roles in its fate.

Arctic sea ice and oil drilling

Friday, September 21, 2012

This week has held several precedential events in Arctic policy, with both record low sea ice extent and changes to plans for Arctic oil exploration and production.

According to a preliminary report by the National Snow & Ice Data Center, this week Arctic sea ice appeared to have reached its minimum extent for the year of 3.41 million square kilometers (1.32 million square miles).  Sea ice extent refers to the area of the Arctic Ocean and its nearby seas covered by sea ice.  While the seasonal climate appears to have turned to conditions favoring more sea ice for the fall and winter - colder temperatures and the setting Arctic sun - the September 16, 2012 sea ice extent represents the lowest seasonal minimum extent since the satellite record began in 1979.

Coincidentally, the next day Royal Dutch Shell plc announced that it will suspend its Arctic oil exploration and production efforts in the U.S. Chukchi Sea until next summer.

Earlier this month, a Shell subsidiary began preliminary drilling at its leased Berger prospect site, located about 70 miles off the coast of Alaska.  But one day after the Noble Discoverer drill ship began drilling at the site, advancing sea ice forced the ship to retreat to a safer location.

Oil spill prevention and containment is essential in any offshore drilling operation, and may be especially so in the Arctic given the sensitivity of the environment and the challenges posed by sea ice.  This month Shell tested its Arctic Containment System, but during a final test a critical containment dome was damaged.  Between the dome's failure to meet Shell's acceptance standards, concerns over operational safety amidst ice floes, and steps taken to protect local whaling operations, Shell announced this week that it has revised its plans for the 2012-2013 exploration program.  Rather than drilling into hydrocarbon zones this year, Shell plans to drill top holes - think of pilot holes that stop short of the oil-bearing layers -  and then cap and temporarily abandon the wells until next summer.

The market pressures driving Shell and other upstream oil companies to prospect for Arctic resources will likely remain for the foreseeable future.  But some political forces are questioning the wisdom of Arctic oil production.  Yesterday the Environmental Audit Committee of Britain’s House of Commons called for an international moratorium on oil and gas drilling in the Arctic until the eight-nation Arctic Council establishes universal standards for spill or other disaster response, as well as strong financial safeguards to ensure spills are both deterred and capable of full remediation.

Utility coal plants closing, natural gas to replace

Monday, September 17, 2012

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.