NH SEC denies Northern Pass certificate

The New Hampshire Site Evaluation Committee has unanimously voted to deny an application to develop a major new electric transmission line across that state, according to an article in the Union Leader. According to that article, the Committee felt the Northern Pass Transmission developer had not satisfied its burden under state law to show that the line's development would not “unduly interfere with the orderly development of the region.”

Northern Pass Transmission, LLC has proposed a 192-mile transmission line project capable of bringing 1,090 megawatts of power into New England. The project includes a new direct current (DC) transmission line from the Canadian border to a new converter terminal to be built in Franklin, New Hampshire, as well as a new AC transmission line connecting to the existing grid at a substation in Deerfield.

To develop the project, the developer needs approval from the New Hampshire Site Evaluation Committee in the form of a Certificate of Site and Facility. Northern Pass applied to the SEC for a certificate in 2015; the case before the Committee has been ongoing since then, with extensive testimony and hearings held last month.

Successful project development involves not just securing all required permits, but also finding or creating suitable commercial arrangements. While the project's siting application was pending, the project won some commercial success last week, when a group of Massachusetts utilities seeking to jointly procure clean electricity selected a Northern Pass-affiliated proposal to supply about 9,450,000 megawatt-hours per year from Canada. After reviewing over 40 bids, the bid committee selected the "Northern Pass Transmission, Hydro" option for negotiation of a final long-term power sales agreement under the state's Section 83D clean energy contracting program.

Today's decision by the New Hampshire Site Evaluation Committee relates directly to siting, not to commercial matters. The developer may be able to challenge the Committee's permitting decision. In the meantime, could the SEC decision affect the Northern Pass project's commercial fate? According to the Massachusetts 83D website, "If the bid selected to advance to contract negotiation at this stage does not successfully negotiate contracts, it may result in other bid(s) being selected to advance to contract negotiations." If the lack of SEC approval (for now) means Northern Pass does not successfully negotiate contracts with the Massachusetts utilities, it could open the door for other 83D bidders to move forward.

BLM rule for renewable energy leasing of federal lands

The federal Bureau of Land Management has issued a final rule establishing a competitive process for leasing federal lands for renewable energy development.  The Obama administration describes the rule as strengthening the agency's existing "Smart from the Start" leasing program, consistent with the president's Climate Action Plan.  But following the 2016 election, the future Trump administration could change the agency's course.

Part of the Department of the Interior, the BLM manages federal lands across the U.S.  While BLM lands have been used for mining for years, under the Obama administration BLM took steps to open up federal lands for leasing for renewable energy projects.  Under federal laws including the Federal Land Policy and Management Act (FLPMA) and the Mineral Leasing Act (MLA), BLM is authorized to issue what it calls "grants" -- easements, leases, licenses, and permits to occupy, use or traverse public lands for particular purposes -- for facilities for the generation, transmission, and distribution of electric energy, and oil and gas pipelines.

On November 10, BLM released its final rule, "Competitive Processes, Terms, and Conditions for Leasing Public Lands for Solar and WindEnergy Development and Technical Changes and Corrections for 43 CFR Parts 2800and 2880.”  It amends BLM's regulations governing rights-of-way issued under two federal laws.  BLM described the amendments as necessary to "facilitate responsible solar and wind energy development on BLM-managed public lands and to ensure that the American taxpayer receives fair market value for such development."

The final rule includes provisions to promote the use of preferred areas for solar and wind energy development.  These areas, called “designated leasing areas” (DLAs), are defined parcels of land with specific boundaries identified by the BLM land use planning process as being a preferred location for solar or wind energy that can be leased competitively for energy development.

The rule expands BLM's existing regulations, allowing BLM to offer lands competitively on its own initiative, both inside and outside DLAs, even in the absence of identified competition. Within DLAs, the rule will require competitive leasing procedures except in certain circumstances, when applications could be consider ed outside the competitive process. Outside DLAs, the BLM will have discretion whether to utilize competitive leasing procedures.

The final rule also updates payments charged by BLM, to ensure that it obtains fair market value for the use of public lands.  Updated fee structures include both an acreage rent and a megawatt-capacity fee.

Given the November 8 election results, it is unclear whether the Trump administration will continue in this direction.  While campaigning, President-elect Trump emphasized leasing more federal land for fossil fuel production.  The BLM renewable energy rule's future is thus in question.

FERC denies Oregon LNG project applications

U.S. energy regulators have denied applications to site, construct, and operate the proposed Jordan Cove liquefied natural gas (LNG) export terminal, an associated pipeline and related facilities slated for development in Oregon.

The Jordan Cove LNG Terminal and the Pacific Connector Pipeline were proposed as two segments of a single, integrated project.  According to the FERC record, the applicants designed the facilities to enable the production of up to 6.8 million metric tons per annum (MMTPA) of LNG, using a feed of approximately 1.04 billion standard cubic feet per day (Bcf/d) of natural gas, for export to international or domestic markets in the non-contiguous United States.  The proposed pipeline would carry natural gas to the LNG terminal, for liquefaction, storage in cryogenic tanks, and loading onto ocean-going vessels.

Under U.S. federal law, the Federal Energy Regulatory Commission exercises permitting authority over several types of natural gas infrastructure, including LNG terminals and interstate pipelines.  In 2013, Jordan Cove Energy Project, L.P. applied under section 3 of the Natural Gas Act (NGA) and Parts 153 and 380 of the Commission’s regulations to site, construct, and operate the LNG terminal.  Several weeks later, Pacific Connector Gas Pipeline, LP applied under NGA section 7(c) and Part 157 of the Commission’s regulations for a certificate of public convenience and necessity to construct and operate an approximately 232-mile-long, 36-inch-diameter interstate natural gas pipeline running to the Jordan Cove LNG Terminal.

Over the next few years, Commission staff engaged in a back-and-forth with the applicants over the status of liquefaction contracts for the LNG terminal and precedent agreements for pipeline capacity.  The Sierra Club and others intervened and filed protests.  Concerns stated included environmental issues and landowner complaints, as well as an alleged lack of need for the projects.  Meanwhile the Commission issued the project a generally favorable environmental assessment.

The Commission ultimately denied the applications on March 11, 2016.  In its order denying the applications, the Commission cited its Certificate Policy Statement as providing "guidance for evaluating proposals to certificate new construction."  In the Commission's words:

The Certificate Policy Statement establishes criteria for determining whether there is a need for a proposed project and whether the proposed project will serve the public interest. The Certificate Policy Statement explains that in deciding whether to authorize the construction of major new pipeline facilities, the Commission balances the public benefits against the potential adverse consequences. The Commission’s goal is to give appropriate consideration to the enhancement of competitive transportation alternatives, the possibility of overbuilding, subsidization by existing customers, the applicant’s responsibility for unsubscribed capacity, the avoidance of unnecessary disruptions of the environment, and the unneeded exercise of eminent domain in evaluating new pipeline construction. 

The threshold requirement for pipelines proposing new projects under this policy is that the pipeline must be prepared to financially support the project without relying on subsidization from its existing customers.  In this case, the Commission found that Pacific Connector satisfies the threshold "no subsidization" requirement of the Certificate Policy Statement because it is a new natural gas company and does not have existing customers. 

Next, the Commission determine whether the applicant has made efforts to eliminate or minimize any adverse effects the project might have on the applicant’s existing customers, existing pipelines in the market and their captive customers, or landowners and communities affected by the route of the new pipeline. If these interest groups face residual adverse effects after efforts have been made to minimize them, the Commission essentially performs an economic balancing test on the evidence of public benefits to be achieved as compared to the residual adverse effects. Only when the benefits outweigh the adverse effects on economic interests will the Commission proceed to complete the environmental analysis where other interests are considered.

The benefits test proved problematic for the Pacific Connector pipeline.  The Commission found no adverse impact to existing customers, existing pipelines in the market or their captive customers.  But the Commission noted the landowner concerns, and a lack of evidence that the applicant had obtained any easement or right-of-way agreements for the necessary use of private lands.  In the Commission's view, these concerns must be weighed against the benefits to be gained from the project.

But the Commission found that "Pacific Connector has presented little or no evidence of need for the Pacific Connector Pipeline."  The Commission noted that the pipeline applicant had "neither entered into any precedent agreements for its project, nor conducted an open season, which might (or might not) have resulted in “expressions of interest” the company could have claimed as indicia of demand." According to the Commission, the applicant offered only "generalized allegations of need."  These did include the fact that Jordan Cove received U.S. Department of Energy authorization for export of LNG to free trade agreement and non-free trade agreement nations as "consistent with the public interest."  But the FERC noted that this DOE authorization for LNG was pursuant to different statutes, and moreover did not apply to the pipeline

The Commission noted that it "has not previously found a proposed pipeline to be required by the public convenience and necessity under NGA section 7 on the basis of a DOE finding under NGA section 3 that the importation or exportation of the commodity natural gas by an entity proposing to use the services of an associated LNG facility is consistent with the public interest."  As a result, the Commission found that "the generalized allegations of need proffered by Pacific Connector do not outweigh the potential for adverse impact on landowners and communities." Because the record did not support a finding that the public benefits of the Pacific Connector Pipeline outweigh the adverse effects on landowners, the Commission denied Pacific Connector’s request for certificate authority to construct and operate its project.

Turning next to the LNG terminal, the Commission noted that the Pacific Connector Pipeline is the only proposed transportation path for natural gas to reach the Jordan Cove LNG Terminal, and that the Commission has not previously authorized LNG export terminal facilities without a known transportation source of natural gas. Because the Commission concluded that the record did not support a finding that the Jordan Cove LNG Terminal can operate to liquefy and export LNG absent the Pacific Connector Pipeline, the Commission instead found that authorizing its construction would be inconsistent with the public interest. Therefore, it also denied Jordan Cove’s request for authorization to site, construct and operate the Jordan Cove LNG Terminal.

Maine court interprets wind energy law

Maine's highest court has issued an opinion interpreting Maine's laws governing wind energy project development.  The opinion, Champlain Wind, LLC v. Board of Environmental Protection, 2015 ME 156, is noteworthy for its analysis of "competing legislative purposes" in Maine wind energy law -- those designed to expedite the development of wind power in Maine, and those designed to protect scenic resources.

The Maine Supreme Judicial Court's December 3, 2015 opinion affirms an earlier decision by the state Board of Environmental Protection to deny a permit for the Bowers Wind Project.  In 2012 developer Champlain Wind had filed a consolidated application with the Maine Department of Environmental Protection, seeking state permits to construct the project.  As described in the opinion, that project would include 16 wind turbines with a combined generating capacity of 48 megawatts.  Geographically, the turbines fell "just within the boundary" of an area designated by the state Legislature for expedited wind energy development.  However, its turbines would be visible from nine great ponds classified as a "scenic resource of state or national significance" under state law.  Maine law gives enhanced protections to such scenic resources in wind project siting decisions affecting specified geographic areas.

After some process, the Department ultimately denied Champlain's application.  In so doing, the Department concluded that the project met all but one applicable standard.  The Department found that the project “would have an unreasonable adverse effect on the scenic character and existing uses related to the scenic character” of the nine affected great ponds.  This failure of the statutory scenic character standard led the Department to deny the requested consolidated permit.

Champlain appealed from the Department's denial to the Board of Environmental Protection.  The Board issued an order in June 2014 affirming the Department's denial.  Champlain appealed again, this time to the Maine Supreme Judicial Court.

The court's opinion on that case was published today.  Much of the court's opinion focuses on specific legal arguments in play -- for example, whether the Board could take an aggregated or "holistic approach" when considering a proposed project's impact on multiple scenic resources of state or national significance, and the level of judicial deference the court should afford the Board.

But for those interested in Maine wind energy development law, the most interesting parts of the opinion are likely those showing how the court interprets the Maine Wind Energy Act and related statutes.  As characterized in the introduction to the court's opinion,

the Board considered and balanced competing statutorily defined policies applicable to wind energy projects in Maine. The applicable statutes establish the dual policies of expediting wind energy development in defined geographic areas of Maine and at the same time providing enhanced protection for specific scenic resources. 

In its discussion, the court noted:

The generating facilities and wind turbines that make up the Project are proposed to be sited within the expedited permitting area; however, most of the nine great ponds affected by the Project—all of which are rated as outstanding or significant from a scenic perspective—are fully excluded from the expedited permitting area. Thus, as previously noted, the Board was confronted with a project that falls directly between competing legislative priorities.

The court recited the Board's consideration as having included:

• the “existing character of the surrounding area” and “significance of the potentially affected scenic resource,” see 35-A M.R.S. § 3452(3)(A), (B);
• the Legislature’s intent in balancing the goal of encouraging and expediting wind power development with the goal of protecting Maine’s scenic resources by limiting the geographic scope of the expedited permitting area; 
• the exclusion of most of the nine affected great ponds from the expedited permitting area; and 
• the unique interconnectedness of the affected great ponds, which would result in users being repeatedly confronted with views of the turbines from multiple scenic resources of state or national significance when traveling from one lake to another.

The court described these as "unique circumstances" and a "context of competing legislative priorities and unusually interconnected scenic resources."  In the court's view, presented with these circumstances and this context, it wasn't unreasonable, unjust, or unlawful for the Board to decline to issue the permit.  Because the court could not conclude that the Board acted unlawfully or arbitrarily or that the statutes compel a different result, the court deferred to the Board’s interpretation of the Maine Wind Energy Act and the statutes governing expedited permitting for grid-scale wind energy projects.

This opinion likely is most direct in its effect on those interested in the Bowers Wind Project, the parties and other stakeholders.  The Champlain Wind, LLC v. Board of Environmental Protection opinion may also catalyze renewed discussion about balancing what the court labeled "competing legislative purposes" in Maine wind energy project siting law -- on the one hand, to expedite the development of wind power in Maine; on the other, to protect scenic resources. 

Maine considers nuclear energy law change

The Maine legislature is considering a proposal to amend state laws regarding the siting and construction of new nuclear power plants. The bill known as LD 1313, "An Act To Amend the Laws Regarding Nuclear Power Generating Facilities", is listed as a "Governor's Bill", indicating its origin from Maine Governor Paul LePage. What might LD 1313 mean for Maine?

Maine is not currently home to any operating nuclear power plants.  From 1972 to 1996, the Maine Yankee Nuclear Power Plant operated a 900 megawatt reactor in Wiscasset.  While it operated, Maine Yankee was the state's largest generator of electricity.  But a Nuclear Regulatory Commission investigation launched in 1995 identified safety and other problems that ultimately rendered continued plant operation uneconomic; the site was decommissioned from 1997 through 2005, with spent fuel remaining on site to date.

Maine Yankee was controversial from its inception, with significant opposition to its construction from anti-nuclear groups and others.  Partially in response to this controversy, in 1987 Maine enacted a law "to provide for citizen participation in any decision to construct a nuclear power plant within the State."  As part of that law (as amended in 1999), the Legislature enacted a finding "that construction of a nuclear power plant is a major financial investment, which will have consequences for consumers for years to come."  The law also included a finding that, "In the recent past, investments in nuclear power plants have caused severe financial strain on consumers."  In addition, the law required a statewide voter referendum prior to the construction of any nuclear power plant in Maine, and prohibited construction of a nuclear power plant without this voter approval.

Governor LePage's proposal would amend those two sections of existing law relating to the process for siting nuclear power plants.  First, LD 1313 would delete the legislative finding that "In the recent past, investments in nuclear power plants have caused severe financial strain on consumers." Second, LD 1313 would limit the referendum requirement to nuclear power plants "with capacity greater than 500 megawatts."

LD 1313 would appear to encourage the construction of relatively small nuclear power plants in Maine -- that is, those with capacity of 500 megawatts or smaller, roughly half of Maine Yankee's size.  But of the approximately 100 nuclear power plants in commercial operation in the U.S. today, nearly all can generate more than 500 megawatts of power.  The Omaha Public Power District's Fort Calhoun plant in Nebraska is rated at 476 megawatts, and is one of the only commercial reactors in the U.S. smaller than 500 megawatts.  The technical and security aspects of nuclear power have traditionally pushed utilities to develop relatively large nuclear power plants, making the development of small but traditional nuclear power in Maine relatively unlikely.

Perhaps more likely to benefit if LD 1313 is enacted would be the development of small modular nuclear reactors.  According to the U.S. Department of Energy, small modular reactors offer the advantage of lower initial capital investment, scalability, and siting flexibility at locations unable to accommodate more traditional larger reactors.  They also have the potential for enhanced safety and security.  The Department of Energy has expressed interest in advancing small modular reactor technology.  If LD 1313 is enacted, it could eliminate the requirement of statewide voter approval of the construction of a nuclear power plant using small modular reactor technology.

But whether LD 1313's enactment would actually lead to the construction of small modular reactors in Maine is unclear.  Is the voter referendum requirement really the chief obstacle to small modular reactor construction in Maine?  Or can Maine's lack of small modular reactors be explained by other limitations -- like technology, financing, or safety regulations?

LD 1313 has been referred to the Maine State Legislature's Joint Standing Committee on Energy, Utilities and Technology.  To date, no public hearing has been scheduled.

US to auction Massachusetts offshore wind sites

The U.S. Department of the Interior has announced plans to auction more than 742,000 acres offshore Massachusetts for commercial wind energy development.

On January 29, 2015, the Department's Bureau of Ocean Energy Management will hold a competitive commercial lease sale for the rights to site offshore wind facilities in the federally designated Massachusetts Wind Energy Area.  Generally located south of the islands of Martha's Vineyard and Nantucket, the area will be auctioned as four leases.  It starts about 12 nautical miles offshore Massachusetts; from its northern boundary, the area extends 33 nautical miles southward and runs about 47 nautical miles from east to west.  The Massachusetts Wind Energy Area is significantly larger than previously auctioned areas off Massachusetts, Rhode Island, Virginia, and Maryland.  The U.S. Department of Energy’s National Renewable Energy Laboratory has estimated that fully developing the Massachusetts area could support between 4 and 5 gigawatts of commercial wind generation.

BOEM has found twelve companies to be legally, technically and financially qualified to participate in the auction for the Massachusetts Wind Energy Area:

• Deepwater Wind New England, LLC
  
• EDF Renewable Development, Inc.
• Energy Management, Inc.
  
• Fishermen’s Energy, LLC
  
• Green Sail Energy, LLC
  
• IBERDROLA RENEWABLES, Inc.
  
• NRG Bluewater Wind Massachusetts, LLC
  
• OffshoreMW, LLC
  
• RES America Developments, Inc.
  
• Sea Breeze Energy, LLC
  
• US Mainstream Renewable Power (Offshore), Inc.
  
• U.S. Wind, Inc.

Bidders will be ranked based on a combination of monetary factors (primarily their bids) and non-monetary factors (whether or not the bidder has a Community Benefits Agreement or Power Purchase Agreement in place).

The Massachusetts auction will be the fourth competitive lease sale for renewable energy on the Outer Continental Shelf, following previous auctions for sites off Massachusetts-Rhode Island, Virginia and Maryland.  Bidders winning previous auctions have committed over $14 million in bids to secure over 357,500 acres in federal waters.  BOEM expects to hold another lease auction for sites offshore New Jersey in 2015.

Canada's Energy East Pipeline Project

A subsidiary of Canadian energy company TransCanada has proposed a crude oil pipeline running 4,600 kilometers from Alberta and Saskatchewan to Saint John, New Brunswick.  The proposed Energy East Pipeline Project would enable Western Canadian crude oil to be shipped east across six Canadian provinces, expanding economic opportunities for refining and export -- but like other major pipeline projects, the Energy East project faces regulatory hurdles.

On March 4, 2014, Energy East Pipeline Ltd., a wholly owned subsidiary of TransCanada Oil Pipelines (Canada) Ltd., proposed the project which entails the conversion of about 3,000 kilometers of existing natural gas pipeline to an oil transportation pipeline, new pipelines in Alberta, Saskatchewan, Manitoba, Ontario, Québec and New Brunswick, and marine facilities that enable access to other markets by ship.  If built, the $12 billion project could carry up to 1.1 million barrels of crude oil per day.

The major motivation behind the line is the relative surplus of Western Canadian crude oil, including fuel produced from the Alberta oil sands.  While Alberta and Saskatchewan produce substantial oil, relatively little capacity to ship that crude to refineries means relatively low prices for producers.  Meanwhile, refineries in Quebec and Atlantic Canada currently receive 86% of their crude oil from foreign sources.  TransCanada pitches the Energy East project as giving these Eastern Canadian refiners access to "reliable, low-cost Western Canadian crude."  The developer also points to positive economic development impacts, including about 10,000 jobs and an estimated $35 billion added to Canada’s gross domestic product over 40 years, as well as the relative safety of shipping oil by pipeline as opposed to by rail or truck.  Notably, the project also allows TransCanada to make better use of its existing natural gas pipeline system, which has excess unused capacity.

Like the Keystone XL pipeline in the U.S., the Energy East project faces opposition from both local siting concerns and global worries about the environmental impacts of "tar sands" crude production.  Some have also expressed concerns that the project would disrupt natural gas flows to Canadian consumers, although TransCanada has said that it has plans to build more lines to meet any increased demand.

Under Canadian law, interprovincial pipelines are federally regulated by Canada's National Energy Board (NEB).  According to its website, TransCanada expects final regulatory approval in the fourth quarter of 2015, with the project commissioned and placed in service in 2018.  How the regulatory process plays out will affect when -- and whether -- the Energy East pipeline project moves forward.

New England Clean Power Link proposed

A developer of electric transmission lines has proposed a new line that would connect New England to Quebec.  The so-called New England Clean Power Link would run about 150 miles from the U.S.-Canadian border to Ludlow, Vermont.  While the line shares some features with other proposed ties to the Canadian power grid -- including its development team -- the New England Clean Power Link differs from prior proposals in several regards.

Demand for electricity in the northeastern United States, and in particular for renewable power, has led to interest in developing several transmission lines to Canada.  Provincial crown corporation Hydro-Quebec has many large hydroelectric dams, and continues to develop Quebec's rivers for power production.  Meanwhile, Newfoundland utility Nalcor is developing gigawatt-scale hydropower on the Churchill River in Labrador, with aims to export the power to eastern Canada and the U.S.

This relative surplus of Canadian hydropower has led developers to propose transmission lines connecting Quebec resources to New England consumers.  These lines include the Champlain-Hudson Power Express from Canada to New York City, and the Northern Pass from Canada into New Hampshire.

The $1.2 billion Clean Power Link would have a capacity of 1,000 megawatts, roughly equal to the size of a nuclear power plant.  Like previous proposals, the newly-proposed line is motivated by the perceived opportunity to sell Canadian power in New England.  The Clean Power Link also shares features in common with other proposals, in that it would be a high-voltage direct current or HVDC line.  Notably, it would also be developed and financed by TDI New England, a Blackstone Group subsidiary led by the team behind the Champlain-Hudson Power Express.

Like that line, it would run about 100 miles under Vermont's Lake Champlain.  South of the lake, the Clean Power Link proposal features lines buried underground.  This contrasts with the Northern Pass, whose traditional wires-on-towers architecture has drawn significant opposition in New Hampshire.

The Clean Power Link faces a regulatory process including environmental and energy permitting, and is also dependent on the market forces that motivated its proposal.  It is unclear whether any of the proposed transmission lines to Canada will actually be built, let alone which one.  For now, TDI aims to build the line and place it in service by 2019.

Massachusetts to develop wind energy siting guidance

As interest continues to grow in the generation electricity from wind energy, the siting of wind projects is an important issue.  While producing power from wind energy avoids the use of fossil fuel along with the emission of carbon dioxide and other pollutants, society has an interest in ensuring that wind projects are developed responsibly and in appropriate locations.  Regulation of sites for wind energy development generally occurs at the state and local levels, and some observers - both wind developers and opponents of specific wind projects - have complained of bad results from a patchwork of regulations, some of which are not based on good science.

Wind turbines in Ipswich, MA, visible across Plum Island Sound from the Parker River National Wildlife Refuge.

In Massachusetts, the state Department of Public Utilities has launched an initiative to remedy this defect.  On October 31, 2013, the Department opened an investgation into best practices for the siting of land-based wind energy facilities.  According to the Department's notice:

The investigation will result in the development of wind energy facility siting guidance based on sound scientific, technical, and policy information. Specifically, the Department will examine the following topics related to land-based wind energy facilities: design, environmental and human health, safety, construction impacts, socio-economic impacts, decommissioning, and the review process for wind projects.

The Department has docketed this case as D.P.U. 13-165, Investigation into Best Practices for Siting of Land-Based Wind Energy Facilities, and has solicited public comment by December 6. Following receipt and review of the comments, the Department anticipates holding public hearings beginning in January.

The guidelines developed through this process will shape the siting and development of land-based wind projects in Massachusetts.  Massachusetts has a strong commitment to renewable energy, as evidenced in the Green Commnities Act, its renewable portfolio standard, and in public sentiment.  That said, to date most wind power consumed in Massachusetts comes in the form of renewable energy certificates representing power generated from wind facilities in Maine and other states, largely due to the relative difficulty of siting a wind energy project in Massachusetts.  Will this process lead to more wind energy development in Massachusetts?

 

Utilities plan over $51.1 billion in transmission development

Growth in renewable electricity production will drive significant upgrades to the U.S. electric transmission grid, according to a study released by the Edison Electric Institute.  EEI's seventh annual "Transmission Projects: At a Glance" identifies over 150 transmission projects planned by EEI member utilities for development over the next decade.  According to the report, these projects entail investments of at least $51.1 billion through 2023.  While the transmission projects may advance multiple goals, the majority of the projected investments will be for projects supporting the integration of renewable resources into the grid.

EEI is a trade association composed of investor-owned electric utilities.  Its members represent approximately 70 percent of the U.S. electric power industry.  EEI tracks transmission investment by its members.  According to the report, annual transmission investment is increasing, from 11.1 billion in 2011 to approximately $15.1 billion in 2013.  At the same time, EEI has revised its total future projection downward.  In 2012, EEI members reported $64 billion in planned transmission over the next decade, but changing projections of system needs have revised that number downward to $51.1 billion.

Under federal laws including the Energy Policy Act of 2005, utilities are given incentives to develop transmission lines and related assets.  These incentives are designed to ensuring a safe and reliable electric grid, but also reward utilities for developing projects to integrate renewable resources like wind farms into the grid.  Because ratepayers ultimately bear the cost of transmission infrastructure, the Federal Energy Regulatory Commission and state public utilities commission regulate utility proposals to expand the grid. 

According to EEI, most proposed transmission projects advance multiple goals.  The study shows that 76% of projects (approximately $38.7 billion) are pitched as supporting the integration of renewable resources. In the aggregate, these projects entail the addition or upgrade of 13,300 miles of transmission lines.  Similarly, most projects are designed to enable electricity to flow across state lines; 52% ($26.5 billion) represent large interstate transmission projects spanning multiple states.

Whether each project identified in the EEI report will be built remains to be seen.  As demand for electricity shifts -- whether due to energy efficiency improvements, a declining economy, or newly proposed generating projects -- the need for any given transmission line may diminish.  For example, last year the $2 billion Potomac Appalachian Transmission Highline (PATH) project was canceled after it was deemed unnecessary.  The proposed Northern Pass transmission project connecting Quebec to New Hampshire is facing significant opposition due to the siting of its planned route, as well as on environmental and economic grounds.  Nevertheless, the significant transmission development projected by EEI remains likely to occur in the aggregate.

Keystone XL pipeline explained

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

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

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

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

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

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

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

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

Vermont wind project contested

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

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

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

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

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

April 25, 2011 - Maine legislative committee considers wind

Today, the Joint Standing Committee on Energy, Utilities and Technology of the Maine State Legislature is considering an array of bills about generating electricity from wind.  Among the bills up for public hearing today include a number of proposals to modify the Maine Wind Energy Act and Maine's expedited permitting process for wind energy development.  Another proposal would make wind energy developers compensate nearby landowners for any lost property value.

Electric transmission lines cross a field near Colchester Pond, Vermont.

The Committee room is full, with significant public interest in these bills; both citizens and legislators alike have their work cut out for them.

March 29, 2011 - Delaware offshore wind site lease moves forward

Offshore wind in Delaware just got a boost, as the U.S. federal government is moving forward with a site lease with NRG Bluewater Wind.  This represents the first commercial wind lease under the “Smart from the Start” Atlantic Offshore Wind program.  Under that program, the Department of Interior's Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) is charged with streamlining the regulatory process for offshore wind projects.  An early step in the Smart from the Start process is BOEMRE's issuance of a request for interest (RFI) in obtaining commercial leases for the construction of wind energy projects on the Outer Continental Shelf (OCS).  Under the federal OCS Lands Act, before developers can lease sites from the government, BOEMRE must determine if there is competitive interest in developing projects in a particular zone of the OCS.  If two developers’ staked areas of interest fully or partially overlap, BOEMRE will determine that there is competitive interest in the area, triggering a competitive leasing process for that zone.  If developers’ interests do not overlap, BOEMRE may proceed with a simpler noncompetitive lease process.

For the Delaware OCS sites, BOEMRE's April 2010 RFI received only one qualified response: Bluewater Wind Delaware, LLC's proposal to site a project 11 miles east of Dewey Beach.

To see if any other developers were interested in Bluewater's proposed site, BOEMRE published a second notice in January 2011, which did not reveal any additional expressions of interest.  (You can find the public comments here.)  BOEMRE thus determined that there is no competitive interest for commercial wind energy development in this area of the Outer Continental Shelf, placing Bluewater's project on the faster non-competitive track.  This determination will soon be published in the Federal Register.

NRG, which joined with Bluewater in developing the Delaware project, has entered into an agreement to sell power from the project to Delmarva Power, Delaware's largest utility.  Next steps include moving forward with the noncompetitive leasing, which will entail several layers of environmental reviews, other regulatory approvals, and technical engineering for the project.