Auction set for NJ offshore wind sites

Friday, September 25, 2015

The U.S. government has scheduled an auction for the rights to lease two areas of federal ocean space off New Jersey for offshore wind energy development.  The auction, to be held November 9, 2015, will be the fifth competitive lease sale for renewable energy on the outer continental shelf.

Under the Outer Continental Shelf Lands Act, the Department of the Interior has responsibility for managing use and development of the federally controlled outer continental shelf and the waters above it.  The Bureau of Ocean Energy Management exercises key functions in support of this role, managing resource evaluation, planning, and site leasing for energy activities ranging from oil and natural gas exploration and production to hydrokinetic, offshore wind, and other renewable ocean energy projects.

Since early in the Obama administration, BOEM has worked to offer leases to federal ocean sites for offshore wind development or related activities.  To date, BOEM has awarded seven offshore wind site leases through competitive lease sales, plus two more commercial wind leases offshore New Jersey awarded through earlier interim policies.  BOEM's competitive processes have generated over $14.5 million in high bids for over 700,000 acres in federal waters off states including Massachusetts, Maryland, Virginia, and Rhode Island.

Since at least 2009, BOEM has been involved in efforts to lease sites off New Jersey for offshore wind development, including multiple task force meetings, a 2011 Call for Information and Nominations – Commercial Leasing for Wind Power on the Outer Continental Shelf Offshore New Jersey, and a 2014 Proposed Sale Notice.  That notice described a 343,833-acre Wind Energy Area split in two parts, known for leasing as OCS-A 0498 and OCS-A 0499:

BOEM has now announced that it will publish a Final Sale Notice setting a commercial lease sale for November 9, 2015, for the Wind Energy Area offshore New Jersey.  Similar in format to other recent BOEM offshore wind site auctions, the New Jersey sale will include consideration of both monetary factors (the bid) and nonmonetary factors (i.e., whether a bidder has obtained a Power Purchase Agreement or New Jersey Offshore Renewable Energy Certificate award).

No offshore wind projects are in commercial operation in the U.S., although Deepwater Wind is currently constructing its Block Island Wind Farm in state waters offshore Rhode Island.

Propane inventory in US sets new record

Thursday, September 24, 2015

As the U.S. prepares for another winter, government records show stockpiles of propane have reached record levels.  What's in store for propane markets?

Propane is a hydrocarbon gas liquid used mostly for space heating and as a feedstock for other chemicals like ethylene and propylene, as well as for drying agricultural crops.   Natural gas processing plants and petroleum refineries are the two largest sources of propane. 

The U.S. Energy Information Administration has collected weekly propane inventory data for 22 years.  According to its most recent report, U.S. inventories of propane and propylene reached 97.7 million barrels as of September 11.  EIA describes this as the highest level of propane inventory on record.

What explains the buildup of propane in storage?  Record high propane inventories are partly due to seasonal dynamics in supply and demand.  Demand for propane for heating and agricultural uses is highly seasonal, while demand for propane as a chemical feedstock lacks strong seasonality.  Over recent years, propane and propylene stocks are typically drawn down during the winter heating and agricultural drying season (October to March), and then rebuild from early April through September. 

This year, EIA data shows inventories began increasing in mid-February.  EIA notes that domestic consumption is relatively flat, but found increases in propane production.  In particular, EIA's latest data shows that natural gas processing plants are producing a greater share of propane than in previous years (rising from 62% in 2008 to 76% in 2014), while propane production at refineries has remained relatively constant.

Maine considers net metering alternative

Wednesday, September 23, 2015

The Maine Office of the Public Advocate has proposed a new mechanism to encourage the development of solar energy capacity in the state.

Under Maine’s existing law, customers with onsite generation may choose “net energy billing” treatment. Similar to “net metering” policies in other states, Maine’s program gives eligible consumers credit for the power they send back to the grid from their onsite generation. Presently, the value of that credit varies with the applicable retail electricity rate.

But according to the Public Advocate, Maine’s version of net metering raises concerns including net metering customers’ uncertainty over the future value of power, the potential for cost-shifting to non-net metered customers, and a lack of transparency.

In its white paper, “A Ratepayer Focused Strategy for Distributed Solar in Maine”, the Office of the Public Advocate offers an alternative to Maine’s existing net metering program. It envisions policies to support development of two types of solar energy projects in Maine: customer-sited systems and wholesale systems.

For customer-sited systems, the white paper proposes a “Solar Standard Buyer” to serve as an aggregator of the attributes solar energy can provide. Customers would enter into a Customer-sited Solar Contract or CSC, a fixed-price, 20-year contract with the solar aggregator. As under Maine’s existing net metering structure, the “payment” to customers would be based on a per kWh rate that would appear as a monthly bill credit on the customer’s bill. Under the Public Advocate’s vision, the level of compensation would be capped at $0.20/kWh.

As more solar capacity comes online in Maine, the Public Advocate proposes incremental “step downs” in the CSC contract price paid to solar customers. Both the payments to customers under a CSC and the revenues received through this aggregation and sale would be credited to all customers through transmission and distribution utilities’ existing stranded cost mechanisms.

For wholesale systems between 1 megawatt and 5 megawatts in scale, the white paper envisions that the Commission would solicit competitive bids, with the ultimate purchaser being the Solar Standard Buyer. The white paper notes an expectation that economies of scale will enable these larger, utility-side solar projects to reduce the price per kilowatt-hour to Maine’s non-participating ratepayers. It proposes to compensate developers of wholesale systems at a fixed rate, with contracts procured by the state’s utilities through bi-annual competitive processes.

The Public Advocate suggests that its proposal is consistent with recent analysis of the value of solar energy in Maine. Pursuant to the 2014 “Act to Support Solar Energy Development in Maine”, the Maine Public Utilities Commission developed a methodology for determining the value of distributed solar energy generation in the state. Its Maine Distributed Solar Valuation Study, released this spring, provided a methodology for estimating the cost and benefits of solar, values for each cost and benefit, and options to encourage solar adoption within Maine’s existing utility framework.

According to the Public Advocate’s white paper, its proposal could drive up to 300 MW of new solar capacity in Maine by 2025.  It has been characterized as an addition to net metering, not a replacement.  But the Maine Public Utilities Commission continues to evaluate Maine’s solar energy policies.  Its process could have outcomes ranging from continuation of Maine's net energy billing programs to the creation of some new mechanism to address solar and distributed generation's integration into the grid.

North Carolina offshore wind advances

Tuesday, September 22, 2015

Federal efforts to lease ocean sites off the North Carolina coast for offshore wind development advanced last week, when the Bureau of Ocean Energy Management issued a report finding that there would be no significant environmental or socioeconomic impacts from issuing wind energy leases in three specific areas.  The determination brings BOEM one step closer to auctioning off leasing rights off North Carolina for offshore wind development.

The Bureau of Ocean Energy Management is part of the U.S. Department of the Interior.  BOEM performs key duties under the Outer Continental Shelf Lands Act, including resource evaluation, planning, and site leasing.  In furtherance of President Obama’s Climate Action Plan, BOEM has auctioned off the rights to lease sites in federal waters for offshore wind development off states including Massachusetts, Maryland, Virginia, and Rhode Island.  Altogether, BOEM has awarded nine commercial wind leases.  Seven of these were awarded through its competitive lease sale process, generating over $14.5 million in high bids for over 700,000 acres in federal waters. 

Federal law prescribes the process BOEM must undertake to lease sites for offshore wind development.  Under the National Environmental Policy Act (NEPA), BOEM must evaluate the environmental and socioeconomic impacts of proposed actions.

For the proposed leasing off North Carolina, in January 2015 BOEM published its Environmental Assessment (EA) of the impacts of granting commercial wind leases and allowing of site characterization and assessment activities on the Atlantic Outer Continental Shelf.  On September 17, BOEM issued a revised Environmental Assessment.  That EA found there would be no significant environmental or socioeconomic impacts from issuing wind energy leases and allowing site characterization activities.  This "Finding of No Significant Impact", or FONSI, enables BOEM to proceed to the next step in the leasing process.

That next step will occur in October, when BOEM will convene a public meeting of the North Carolina Renewable Energy Task Force.  After considering the input from the Task Force, BOEM will publish a “Proposed Sale Notice” in the Federal Register, which will include a 60-day public comment period. That notice would be followed by a lease auction, likely similar to those held for sites off other states.

In addition to its proposed North Carolina activity, BOEM expects to hold a competitive lease sale for sites offshore New Jersey later this year.

NH regulation of solar PPAs, leases

Monday, September 21, 2015

If a solar energy company installs solar panels on its customers' roofs, and sells those customers the power they produce, will it be regulated like a public utility under state law?  A petition by Vivint Solar, Inc. has asked the New Hampshire Public Utilities Commission to declare that it will not regulate Vivint Solar as a public utility, competitive electric power supplier, or limited producer of electrical energy under state law.

Vivint Solar describes itself as the second largest installer of residential solar energy systems in the U.S. residential market, with approximately 42,000 residential customers and 274 megawatts of solar systems installed.  The company describes two primary business structures for residential solar projects: long-term power purchase agreements or PPAs, under which a customer agrees to purchase all of the power generated by a solar energy system installed on the customer’s rooftop; and solar leases, under which a customer leases the solar energy system which is installed at the customer’s site. In either case, the solar facilities are owned by Vivint Solar’s affiliates and financing parties to enable efficient use of tax benefits and low-to-no upfront costs for customers.

In its August 14, 2015 petition, Vivint Solar asked New Hampshire regulators for “regulatory clarity on how it may be regulated” if it enters the state to offer its PPAs and solar leases to New Hampshire customers. In particular, Vivint Solar argues that because it would not sell the electricity generated by its solar energy systems to the broad “public,” it is not a public utility under New Hampshire law. Vivint Solar also argues that its contractual relationship with residential customers is fundamentally different from the relationship between a competitive electric power suppliers and its customers, largely because Vivint Solar’s activity occurs on the customer’s side of the utility meter. The company  also asks the Commission to declare that it would not be a limited producer of electric energy, a kind of generator regulated lightly by the Commission. Vivint Solar also notes that its PPAs and solar leases promote New Hampshire’s goal of encouraging competition for retail access, and customer choice for more affordable electricity, as well as New Hampshire’s renewable portfolio standard and other clean energy policies.

The New Hampshire Public Utilities Commission has issued an Order of Notice in the case, with interventions due and a prehearing conference scheduled for early October.

NH explores electric grid modernization

Friday, September 18, 2015

New Hampshire regulators are considering whether and how to modernize the state’s electric grid. In a recently opened investigation, the New Hampshire Public Utilities Commission seeks to educate stakeholders about grid modernization and to explore to what extent that grid modernization is workable in New Hampshire.

Last year, the New Hampshire Office of Energy & Planning issued its 10-Year State Energy Strategy.  In that document, the administration called for "a more flexible and resilient electric grid to support new technologies, increase consumer participation in energy management, and fortify our resiliency in the face of price and supply volatility and extreme weather events."  The first step identified in the Energy Strategy was to open a PUC docket on grid modernization:
The electric grid is aging, and changing consumer use patterns, a new generation mix, and increased threats from severe weather events require a more modern system. The New Hampshire Public Utilities Commission should open a docket to determine how to advance grid modernization in the state. In light of the potential breadth of the topic, which could include dynamic pricing, better consumer access to technology, and even rethinking the role of utilities, an investigation or information ‐ gathering proceeding may be an appropriate first step. This less formal proceeding would give all stakeholders a chance to learn about grid modernization and could inform the specific areas that should be pursued within future dockets. This would allow the PUC and stakeholders to determine which approaches will benefit New Hampshire consumers, and when and how they should be implemented.
Earlier this summer, the New Hampshire legislature enacted House Bill 614, implementing the recommendations in the Energy Strategy.  As Governor Hassan noted in her signing statement, the bill requires the Public Utilities Commission to "begin a process focused on modernizing our electric grid to ensure that we are prepared for an innovative energy future and to set an electricity peak time reduction goal, which can help lower the high costs of producing electricity when demand is greatest."

That process is now underway.  The New Hampshire Public Utilities Commission opened its investigation by order dated July 30, 2015.  The Commission gave interested parties until September 17, 2015 to provide comment on the definition, or elements, of grid modernization that should be included in its investigation.  The Commission directed its staff to schedule a technical session following a review of comments submitted, and to develop a procedural schedule for the rest of the case.

Maine PUC considers community energy projects

Thursday, September 17, 2015

The Maine Public Utilities Commission is evaluating the viability of proposed community-based renewable energy projects that remain under development.

Maine has run a community-based renewable energy program since 2009.  The program gives qualified wind, solar, and other renewable energy projects long-term contracting opportunities to sell the facility’s output to a Maine transmission and distribution utility at attractive rates.

In 2015, the Maine Legislature adopted P.L. 2015 ch. 232, An Act to Amend the Community-based Renewable Energy Program”.  Beyond minor revisions to the law, the act adds strict deadlines for key program milestones: the Public Utilities Commission has until December 31, 2015 to order or allow utilities to enter into long-term contracts under the program, and all projects selected for a contract must become operational and commence generating electricity by December 31, 2018.

Section 5 of the Act also created a new "viability assessment" process designed to make sure the program is as effective as possible.  The program size is capped at 50 megawatts statewide; all of this capacity was quickly claimed by certified projects.  But not all projects that have been certified are operational; some have yet to be built.  Some stakeholders expressed concern over "permit banking" -- developers obtaining and holding onto program capacity, without actively developing it, while other projects would move forward if they could get the capacity.

As a result, the Legislature directed the Commission to review all certified projects that have not yet reached commercial operations, to determine whether the projects are reasonably likely to achieve commercial operations within a 3-year period.   If the Commission determines a project will not be viable by December 31, 2018, the Act directs the Commission to revoke any contract awarded, but such projects will remain certified under the program.   If the removal of nonviable projects frees up program capacity for contracting, the law directs the Commission to conduct an expedited request for proposals to select community-based renewable energy projects to become program participants and enter into long-term contracts.

The Commission's viability assessment process is now ongoing.  A July 13, 2015 procedural order identified six projects as having been either certified or awarded a contract, but not been placed in commercial operation.  Project developers were invited to submit information related to the viability assessment by August 7. 

The Commission meets on September 22 to deliberate on the viability assessments.

CT examines energy storage, grid improvements

Tuesday, September 15, 2015

The Connecticut Department of Energy and Environmental Protection has opened a proceeding to implement a state law advancing energy storage systems and other improvements to the electric grid.  The Distributed Energy Resource Integration Demonstration Project program is designed to find best practices on how different grid-side system enhancements can be reliably and efficiently integrated into the grid in a manner that is cost-effective for all ratepayers.  The recently opened case has the potential to lead to significant investment in energy storage in Connecticut and other grid advancements.

The Department of Energy and Environmental Protection, or DEEP, was established on July 1, 2011 as a combination of the Department of Environmental Protection, the Department of Public Utility Control as well as other state energy policy staff.  DEEP has a dual mandate of conserving, improving and protecting Connecticut's natural resources and environment, as well as supporting economic development by making cheaper, cleaner and more reliable energy available.

In June 2015, the Connecticut legislature passed a sweeping bill formally known as June Special Session Public Act 15-5, An Act Implementing Provisions of the State Budget for the Biennium Ending June 30, 2017, Concerning General Government, Education, Health and Human Services and Bonds of the State (“the Act”).  Section 103 of the Act requires Connecticut electric distribution companies to submit a proposal or proposals to DEEP for demonstration projects to build, own, or operate grid-side system enhancements, such as energy storage systems.  Proposals are supposed to:
  • Demonstrate and investigate how distributed energy resources (DER) can be reliably and efficiently integrated into the electric distribution system;
  • Maximize the value provided to the electric grid, electric ratepayers, and the public from distributed energy resources; and
  • Complement and enhance the programs, products, and incentives available through the Connecticut Green Bank, the Connecticut Energy Efficiency Fund, and other similar programs.
As an initial step in the implementation of this program, DEEP has opened a proceeding to establish priority goals and objectives for the DER Integration Demonstration Projects.  The proceeding includes opportunity for public comment, as well as a stakeholder workshop scheduled for October 5.

Ultimately, Connecticut's electric distribution companies will propose specific demonstration projects for approval first by DEEP, then by the Connecticut Public Utilities Regulatory Authority or PURA.  Much emphasis has been placed on energy storage systems as a likely beneficiary of the program.  Other grid-side system enhancements could include distribution system automation and controls, intelligent field systems, advanced distribution system metering, communication, and systems that enable two-way power flow.  DEEP has until January 1, 2017 to evaluate the approved proposals and report to the state's legislative committee with jurisdiction over energy.

Energy Dept 2015 Quadrennial Technology Review

Monday, September 14, 2015

The U.S. Department of Energy has released its second Quadrennial Technology Review, a 505-page report describing the nation’s energy landscape and the dramatic changes that have taken place over the last four years.

The 2015 Quadrennial Technology Review examines the current status of energy technologies and research opportunities to advance them in addition to key enabling science and energy capabilities.  The updated report comes four years after the Energy Department's original Quadrennial Technology Review, issued in 2011.

The 2015 report notes, "The last four years have been defined by dramatic change in the nation’s energy landscape." Huge growth in domestic production of oil and natural gas has made the U.S. the world leader in combined oil and natural gas production for the last three consecutive years. Wind energy capacity has increased by 65 percent and wind energy generation has nearly doubled; solar capacity has increased 9 fold and solar photovoltaic generation over tenfold; old, inefficient power plants are being replaced by cleaner, more efficient ones; transportation efficiencies continue to improve.

It also highlights the Energy Department's view of "the most promising research, development, demonstration, and deployment (RDD&D) opportunities across energy technologies to effectively address the nation's energy needs. Specifically, this analysis identifies the important technology RDD&D opportunities across energy supply and end use in working toward a clean energy economy in the United States."  Individual chapters focus on specific technology types, including grid modernization, clean power, buildings, manufacturing, fuels, and transportation. 

The report also draws some overarching conclusions:

  • Energy systems are increasingly interconnected through the internet and other technologies, which could enable new paradigms for cost and emissions reduction. 
  • Increasingly diverse options are available to meet the nation’s energy needs is increasing, creating a more dependable and flexible energy system for consumers.
  • Substantial energy efficiency opportunities remain untapped.
  • More research and development could lead to innovation and breakthroughs in how to deliver clean energy cheaper and faster.

Maine PUC solicits standard offer proposals

Thursday, September 10, 2015

The Maine Public Utilities Commission has issued Requests for Proposals for retail electricity standard offer service.  At stake is the right to supply default electricity service to customers of Maine's two largest utilities -- as well as the price those customers will pay for power.

Maine restructured its electricity sector in the late 1990s.  Formerly, utilities owned both power plants and the wires and other infrastructure needed to supply consumers with electricity.  But as of March 1, 2000, investor-owned transmission and distribution utilities may own and operate wires, but generally cannot have a financial interest in or otherwise control generation or generation-related assets.  Power plants became "deregulated" from the perspective of state retail rate regulation, and were sold off by the utilities.  At the same time, Maine law created a new kind of entity called a "competitive electricity provider" to perform the role of supplying electricity as a commodity.

Customers can choose among supply offers from competitive electricity providers.  Suppliers can offer specific types of product (e.g. 100% renewable power, locally-sourced) or particular contract terms (e.g. pricing schedules, payment terms).  Most large industrial energy consumers choose competitive electricity supply under this option, as do many commercial accounts and some homes.

If a customer does not choose a competitive electricity provider, that customer is placed on "standard offer service" by default.  Maine law requires the Maine Public Utilities Commission to arrange for standard offer service though a competitive bid process, and to ensure that standard offer service is available to all customers in Maine.

The pending RFPs cover retail electricity standard offer service for calendar year 2016 for all customer classes in the territories of Central Maine Power (CMP) and Emera Maine-Bangor Hydro District.  Collectively, CMP and Emera Maine deliver approximately eleven million megawatt hours annually, of which about 45% currently comes from standard offer service.

The RFPs and related materials are available on the MPUC website.  Initial proposals are due on October 6, 2015. Following negotiation of non-price terms and a submission of final bid prices, the Commission is expected to select one or more proposals,  Service terms will begin on January 1, 2016.

DOE report finds Solyndra gave "false and misleading" info

Tuesday, September 1, 2015

The Department of Energy's Office of Inspector General has released a special report finding that failed solar panel maker Solyndra, Inc. provided the Department with inaccurate and misleading information during the application process for a $535 million loan guarantee.  The report summarizes the results of a 4-year investigation into what went wrong with the Solyndra matter, and what lessons the Department can learn as it proceeds to exercise its authority to grant an additional $40 billion in loan guarantees.

In 2005, Congress established a federal loan guarantee program for eligible energy projects that employed innovative technologies. Title XVII of the Energy Policy Act of 2005 authorized the Secretary of Energy to make loan guarantees for a variety of types of projects, including those that “avoid, reduce, or sequester air pollutants or anthropogenic emissions of greenhouse gases; and employ new or significantly improved technologies as compared to commercial technologies in service in the United States at the time the guarantee is issued.”

The Department of Energy loan guarantee program was expanded by the American Recovery and Reinvestment Act of 2009, which added billions of dollars of new authority to support renewable energy, electric transmission, and advanced biofuels projects.  The Department's Loan ProgramsOffice has supported a portfolio of more than $30 billion in loans, loan guarantees, and commitments covering more than 30 projects across the United States.

The Department made its first award under this program in September 2009, approving a $535 million loan guarantee to a company called Solyndra, Inc.  Solyndra said it would build a solar photovoltaic equipment manufacturing facility in Fremont, California.  The Energy Department disbursed over $500 million to Solyndra through the program.  But just two years later, Solyndra showed signs of failure, as it ultimately stopped operations and manufacturing, let 1,100 employees go, and filed for bankruptcy.  U.S taxpayers lost over $500 million.

The Solyndra matter drew significant public attention, with even the Department calling it an "ordeal" and many labeling it a scandal.  What went wrong?  Should the government have guaranteed Solyndra's loans?  Was the loan guarantee program flawed?  Or was it acceptable bad luck that the first awardee failed?

Since 2011, the Department of Energy's Office of Inspector General has investigated the Solyndra matter.  Its special report released August 24, 2015, describes the Inspector General's findings:
Our investigation confirmed that during the loan guarantee application process and while drawing down loan proceeds, Solyndra provided the Department with statements, assertions , and certifications that were inaccurate and misleading , misrepresented known facts , and, in some instances, omitted information that was highly relevant to key decisions in the process to award and execute the $535 million loan guarantee. In our view, the investigative record suggests that the actions of certain Solyndra officials were, at best, reckless and irresponsible or, at worst, an orchestrated effort to knowingly and intentionally deceive and mislead the Department.
In particular, the report identified "notable misrepresentations and omissions made to the Department by Solyndra" relating to Solyndra's sales contract commitments and ability to command a premium market price for its panels.  The report suggests this false and misleading information led the Department to approve the loan guarantee, when it might not have done so with the right information.  The report found that Solyndra failed to meet contractual obligations from the loan guarantee documents relating to truth and full disclosure.

The Inspector General's special report also found that the Energy Department's due diligence efforts were "less than fully effective", with missed opportunities to detect and resolve indicators that portions of the data provided by Solyndra were unreliable.  Nevertheless, the report concludes that ultimate blame should fall on the company: "the actions of the Solyndra officials were at the heart of this matter, and they effectively undermined the Department’s efforts to manage the loan guarantee process. In so doing, they placed more than $500 million in U.S. taxpayers’ funds in jeopardy."

The Department of Energy continues to offer loan guarantees for a variety of technologies and projects.  The report suggests that the Department strengthen its due diligence process, and reemphasize to loan applicants their absolute obligation to be truthful, complete, timely and transparent.

Navy signs solar energy deal

Thursday, August 27, 2015

The U.S. Department of the Navy has announced an agreement for the development of a 210 megawatt (DC) solar project to supply electricity to Navy and Marine Corps facilities in California.  The Navy described the deal as the largest purchase of renewable energy by a federal entity to date.

Solar photovoltaic panels in Utah - much smaller project than the Navy project.
The Navy has expressed interest in renewable and alternative energy for some time, buying biofuels and renewable electricity.  According to the website for Deputy Assistant Secretary of the Navy - Energy, Joseph Bryan:
The Navy's energy strategy takes the "long view" necessary to keep our Navy and our nation strong. Bottom line: incorporating energy initiatives now will allow us to more effectively carry out our mission in the future.
In 2009, Congress mandated that 25 percent of the energy used in Department of Defense facilities come from renewable sources by 2025.  Secretary of the Navy Ray Mabus then set an accelerated goal for his branch of the military: 1 gigawatt of renewable energy procurement by the end of 2015.  In the Navy's view, resources like solar power can help diversify its shore energy portfolio and provide long-term cost stability, which ultimately contributes to the Navy's overall energy security priorities.

In furtherance of this goal, last year the Western Area Power Administration issued a request for proposals for renewable energy projects to supply power to Navy facilities in California.  Through a competitive process, Sempra U.S. Gas & Power LLC was selected to develop the Mesquite 3 Solar project.  Sempra is a subsidiary of San Diego-based Sempra Energy, a major energy services holding company. It has developed a variety of solar and wind energy generation projects, including the existing Mesquite 1 Solar project about 60 miles west of Phoenix, Arizona.

The Navy announced that it had signed the agreement on August 20, at a ceremony co-hosted by Western Area Power Administration and Sempra.  Under the Navy deal, Sempra will develop the Mesquite 3 project as an expansion of the existing Mesquite site.  Mesquite 3 will feature over 650,000 photovoltaic panels on ground-mounted, horizontal single-axis trackers.  Construction is scheduled to begin in August, with completion expected by the end of 2016.  While pricing terms have not been disclosed, the Navy reports that it will save at least $90 million over the life of the project.

Will other units of federal government follow the Navy's model in contracting for renewable energy in this manner?  How will solar project business structures change if federal entities start playing a larger role as buyers?

Cross-border infrastructure and presidential permits

Wednesday, August 26, 2015

A recent report casts doubt on whether proposed federal legislation would actually accelerate decisions on the siting of cross-border energy infrastructure.

Cross-border pipelines and electric transmission lines play an important role in the North American energy industry.  Under U.S. law, cross-border energy infrastructure projects require a presidential permit and a finding of consistency with the national interest.  Executive orders give the State Department jurisdiction over cross-border oil pipelines, the Department of Energy jurisdiction over electric transmission lines, and the Federal Energy Regulatory Commission jurisdiction over natural gas pipelines. 

Recent projects like the Keystone XL pipeline have focused attention on the presidential permit process, as that project's presidential permit application has remained pending for years.  Some have raised questions about the scope of agency review and perceived differences in the approaches taken by the State Department, Energy Department, and FERC.

As a result, several members of Congress have proposed legislation designed to accelerate the permitting process.  These bills include:

These bills take various approaches, including limiting agency jurisdiction over cross-border energy infrastructure or the scope of agency review, or setting strict deadlines for agency action following completion of environmental review.

Could federal legislation like this speed up the process for reviewing proposed cross-border pipeline and electric transmission projects?  A recent report by the Congressional Research Service suggests that overall timelines for project review are driven by the scope of the environmental review process, not by delays following that environmental review or agency idiosyncrasies.

In particular, the report found that agency review is "driven largely by the National Environmental Policy Act (NEPA)", which requires federal agencies to consider the environmental impacts before acting.  Moreover, the report notes that the same NEPA requirements apply to all three:
Faced with Presidential Permit applications for energy projects of similar physical scope, the agencies appear to perform NEPA reviews of similar proportion. Very short, smaller projects are generally reviewed more narrowly and quickly, whereas multi-state projects of large capacity are subject to more expansive environmental review and tend to face much greater public scrutiny and comment—regardless of which agency has jurisdiction. 
The report also found that NEPA review is the key driver of overall permitting decision timelines:
As long as agencies apply NEPA to Presidential Permitting decisions, changes to the delineation of, or jurisdiction over, the border-crossing portion of large projects for permitting purposes may not change the scope of project environmental review. The imposition of decision deadlines on the permitting agencies after NEPA review is complete, either for national interest or public interest determination, could provide greater process certainty to stakeholders. However, the overall project review would still be contingent on the completion of NEPA review. Thus, the effects of legislative proposals to change cross-border infrastructure permitting on the review or approval of future border crossing energy infrastructure projects are open to debate. 
It's unclear how the Congressional Research Service report will affect pending legislation.  Likely more influential may be any final action by the State Department on the Keystone XL project's application for a presidential permit.  Nevertheless, interest in cross-border energy trade will likely continue to grow.

Northern Pass proposes new transmission plan

Monday, August 24, 2015

The developer of a proposed $1.4 billion electric transmission line connecting Quebec to New Hampshire has released a revised route for the project, following public opposition to earlier plans.  The new vision for the Northern Pass project would bury more of the line underground and reduce the project's overall capacity to haul power.  Will this version of the Northern Pass gain more traction?

First proposed in 2009, the Northern Pass would be a 192-mile high-voltage direct current (HVDC) transmission line.  It would bring up to 1,000 megawatts of power from Canadian power plants into New England, running from the Canadian border to a proposed converter terminal in Franklin, New Hampshire.  From there, a new alternating current (AC) transmission line would deliver the energy to New England’s electric grid at an existing substation in Deerfield, New Hampshire. 

Since it was first proposed, the Northern Pass route has drawn criticism; the project was delayed, and despite revisions to the route public opposition remained.  Throughout the process, many comments have focused on local siting impacts, like the effect of above-ground transmission lines and poles through Franconia Notch State Park, the White Mountain National Forest, and the Appalachian Trail.  Eversource proposed running 8 miles of cable underground to reduce these impacts, but argued that undergrounding more would make the project too expensive.

But the forces motivating the Northern Pass project and other proposed HVDC lines from Canada remain strong: demand in New England and New York for electricity, and in particular for hydropower and other renewable electricity imported from Canada.

On August 18, project lead Eversource Energy announced changes to the route and scope of the project.  While the previous vision included 8 miles of underground cable to avoid visual impacts, the so-called "Forward New Hampshire Plan" now includes 60 miles of underground cable. Eversource described its revised route as striking "a balance between New Hampshire and our region’s need for a reliable new energy source and avoiding potential impacts to the state’s scenic landscapes."  At the same time, the revised proposal reduces the line's capacity from 1,200 megawatts to 1,000 megawatts, ostensibly to hold total costs at the previously estimated $1.4 billion.  The plan now includes $200 million to establish the "Forward NH Fund", a pool of money designed to support clean energy innovations, economic development, community investment, and tourism.

The Northern Pass project now faces public hearings.  Eversource is expected to file an application for site review with the New Hampshire Site Evaluation Committee in mid-October.

Block Island offshore wind celebrated, challenged

Thursday, August 20, 2015

U.S. and Rhode Island officials recently celebrated the start of construction on the Block Island Wind Farm, which is on track to be the first commercial offshore wind farm in the U.S.  The five-turbine, 30-megawatt project under development by Deepwater Wind is scheduled to come online in 2016; turbine foundation construction and other "steel in the water" activities are underway.  As a pioneer in U.S. offshore wind development, the Block Island project has survived years of permitting uncertainty and repeated legal challenges by project opponents.  But another such lawsuit was filed this week in federal court.  What does the future hold for the Block Island Wind Farm?

Project developer Deepwater Wind is owned principally by an entity of the D.E. Shaw group.  Its Block Island project is currently under construction in Rhode Island state waters about three nautical miles southeast of Block Island.  The project will feed power directly to consumers on Block Island, but also includes a 25-mile bi-directional submerged transmission cable between Block Island and the mainland. The project's finances rest in part on a power purchase agreement through which Deepwater Wind will sell power to utility National Grid.

That power purchase agreement, or PPA, has been the subject of several legal challenges.  Those challenges often cite the deal's cost: pricing for the Block Island power starts as high as 24.4 cents per kilowatt-hour, and escalates 3.5 percent annually.  These prices are more than double the typical Rhode Island energy price, for an estimated $497 million in above-market costs over the 20-year deal.

In 2009 and early 2010, the Rhode Island Public Utilities Commission rejected proposals by Deepwater Wind and National Grid, largely over cost.  The parties then returned with a revised proposal.  In 2010, TransCanada Power Marketing Ltd. unsuccessfully argued that the Rhode Island commission shouldn't consider that proposal due to constitutional infirmities in the Rhode Island law favoring renewable power contracts with in-state projects.  On August 16, 2010, the Commission issued its order approving the PPA.  After that order was appealed to the state Supreme Court, the Supreme Court issued a written opinion upholding the Commission's Order on July 1, 2011.  In 2012 and in 2015, project opponents petitioned the Federal Energy Regulatory Commission to invalidate the Rhode Island commission's action, which FERC declined to do.  Through all this, the project moved forward and ultimately began local construction earlier this year.

But the project is not yet completely out of stormy seas.  On August 14, 2015, plaintiffs with a history of engagement in some of these earlier challenges filed a lawsuit in U.S. District Court in Rhode Island.  As in previous challenges, this complaint argues that the Rhode Island Public Utilities Commission violated federal laws in approving the Block Island deal because only the Federal Energy Regulatory Commission may regulate wholesale electricity sales.  While it is possible that this case could be swiftly dismissed, if it lingers it could add uncertainty to the project until its resolution.  Last year a federal court invalidated a FERC ruling on the grounds that it impermissibly tread on state rights to set retail electricity rates.  That case, Electric Power Supply Association v. Federal Energy Regulatory Commission, has been appealed to the U.S. Supreme Court.

With construction underway, the Block Island project now has significant inertia behind it.  What impact will the recently filed lawsuit have?  Will it affect Deepwater Wind's position as "first in the water" in the race for U.S. commercial offshore wind development?

EPA proposes methane rules for oil and gas

Wednesday, August 19, 2015

The U.S. Environmental Protection Agency has proposed a suite of new and modified rules affecting the oil and natural gas industry.  Collectively, the proposed rules released on August 18 are designed to reduce methane emissions from oil and natural-gas drilling activities.

As the world tackles climate change and greenhouse gas emissions, methane plays a dual role.  As the key constituent of natural gas, methane offers society an abundant and efficient fuel that can displace reliance on costlier and more carbon-polluting fuels like coal and oil.  At the same time, methane in the atmosphere can act as a greenhouse gas itself, with a global warming potential more than 25 times greater than that of carbon dioxide.  According to EPA, methane is the second most prevalent greenhouse gas emitted in the United States from human activities, and nearly 30 percent of those emissions come from oil production and the production, transmission and distribution of natural gas.  At the same time, U.S. production of oil and natural gas has increased, giving the sector important economic and domestic security impacts.

To address this dynamic, yesterday EPA proposed a series of rules affecting the oil and natural gas sector.  EPA has described the new rules as a "key component" of the Obama administration's Climate Action Plan.  They follow a January announcement of a new goal to cut methane emissions from the oil and gas sector by 40 to 45 percent of 2012 levels by 2025.  Under the administration's view, a key tool supporting that goal is the implementation of standards for methane and volatile organic compound (VOC) emissions from new and modified oil and gas production sources, and natural gas processing and transmission sources.

The rules EPA proposed yesterday include such standards, along with supporting materials.  EPA has described its collective proposal as "a suite of commonsense requirements that together will help combat climate change, reduce air pollution that harms public health, and provide greater certainty about Clean Air Act permitting requirements for the oil and natural gas industry."

EPA's proposed package of rules includes:

According to EPA, the proposed rule will reduce methane emissions by between 340,000 and 400,000 short tons in 2025,  on top of reductions of 170,000 to 180,000 tons of other VOCs and 1,900 to 2,500 tons of hazardous air pollutants.  But industry trade group American Petroleum Institute has called additional regulation "unnecessary for reducing emissions."  Debate over EPA's proposal is likely to be vigorous, before EPA as it considers its proposed rulemaking, as well as before Congress and possibly even federal courts, before the dust settles.

EPA will take public comment on the proposals for 60 days after they are published in the Federal Register.  According to the January announcement, the administration expects the final rule will follow in 2016.  This action on oil and natural gas production follows closely on the heels of EPA's adoption of the Clean Power Plan rules, regulating carbon emissions associated with the electric power industry.

Resources on Clean Power Plan

Tuesday, August 4, 2015

Yesterday President Obama announced his administration's "Clean Power Plan," the U.S. Environmental Protection Agency's new regulations limiting power plant carbon emissions under Section 111(d) of the Clean Air Act.

EPA's final Clean Power Plan rule establishes emission guidelines for states to follow in developing plans to reduce greenhouse gas  emissions from existing fossil fuel-fired electric generating units. 

Here are some quick resources I've compiled as a guide to the Clean Power Plan and its release:

US Clean Power Plan adopted

Monday, August 3, 2015

President Obama will formally unveil the Clean Power Plan today, a set of regulations by the U.S. Environmental Protection Agency (EPA) to reduce carbon emissions associated with the electric power industry.  A blog post by EPA Administrator Gina McCarthy emphasizes the Clean Power Plan's protection of health and the environment, states' rights to choose their own implementation paths, reduction of future energy costs, and leadership on climate issues.  But some politicians, utilities and states have expressed concern about the regulations' impact, and could launch legal challenges -- or states might refuse to comply.  What's in store for the Clean Power Plan?

It has been just over a year since EPA first released its draft Clean Power Plan in June 2014.  These regulations under Section 111(d) of the Clean Air Act are designed to reduce the carbon intensity of the U.S. electric power sector -- essentially, how many pounds of carbon are emitted per megawatt-hour of electric energy produced.  Under the draft Clean Power Plan, EPA sets carbon intensity limits for each state, collectively designed to reduce carbon emissions by 30% below 2005 levels.  Each state then designs its own compliance plan using any combination of "building blocks": types of measures like improving the efficiency of fossil fuel power plants, switching out coal- and oil-fired power plants in favor of natural gas, and increasing low- and zero-carbon generation.

While the final Clean Power Plan's basic structure remains much the same, EPA has made some modifications in reaction to concerns about the greenhouse gas regulations' costs and impacts to grid reliability.

Changes from the 2014 draft include:
  • Two extra years (until 2022) for states to meet their targets, and greater flexibility for states to form regional pacts to facilitate emissions-cutting projects across state lines, such as the Regional Greenhouse Gas Initiative.
  • A new “safety valve” feature, to let states appeal for extensions and other relief if complying with the regulations causes disruptions to power supply.
  • Increased social justice incentives for utilities to construct renewable energy projects in poorer neighborhoods, reducing pollution-related illness and eventually lowering electricity rates.
  • Energy efficiency is still encouraged, but has been eliminated as one of the rule’s "building blocks” for states to use in building their own carbon-reduction plans.
How will the Clean Power Plan story continue to play out?  Will it be challenged in court?  Will states comply?  What impacts will it have on the U.S. electric power industry?

Regulators release updated energy primer

Friday, July 31, 2015

The Federal Energy Regulatory Commission has released an updated version of its "resource manual",  Energy Primer: A Handbook of Energy Market Basics.

The FERC is an independent federal agency that regulates a variety of aspects of the U.S. energy industry, including the interstate transmission of electricity, natural gas, and oil, proposals to build liquefied natural gas (LNG) terminals and interstate natural gas pipelines, and hydropower projects, as well as engaging in strategic planning.

FERC's Office of Enforcement is charged with encouraging compliance with the Commission’s statutes, rules, and orders.  Within the enforcement office, the Division of Energy Market Oversight is responsible for monitoring and overseeing the nation’s wholesale natural gas and electric power markets.

In 2012, the Division of Energy Market Oversight (or DEMO) issued the first edition of its Energy Primer.  This week, DEMO issued an updated 2015 version of the Energy Primer.  As with the previous edition, the 2015 Energy Primer gives the public a broad overview of the physical wholesale markets for natural gas and electricity and energy-related financial markets.  As FERC has noted, the revised edition reflects some of the changes that have occurred in the industry since 2012, including the growth in natural gas supplies and the expansion of organized electric markets under Independent System Operators (ISO) and Regional Transmission Organizations (RTO).

The 2015 FERC Energy Primer offers a useful introduction to the U.S. energy industry as it is regulated by FERC.  As with the 2012 version, FERC staff states that the 2015 edition is intended to be used as either a text or a reference guide.  FERC's website also notes that the Energy Primer is a product of FERC staff and does not reflect the views of the Commission or any individual Commissioner.  Nevertheless it may offer careful readers insight into how Commission staff view the markets' continuing evolution.

U.S. renewable energy share highest since 1930s

Tuesday, July 21, 2015

In 2014, about 9.8% of the total energy consumed in the U.S. came from renewable energy sources, according to the U.S. Energy Information Administration.  This represents the highest share of total domestic energy supply coming from renewable resources since the 1930s.

Prior to the growth of production and distribution networks for petroleum and other fossil fuels in the early 20th century, many homes used wood for heating as did industry.  This reliance on renewable biomass historically satisfied a significant portion of the total domestic energy demand.  But technological advances and the birth of the electric power industry led to greater use of other fuels.  As a result, the EIA reports that renewable resources' share of total domestic energy supply peaked in the 1930s, then declined.

But recent growth in U.S. renewable energy use has brought the country's energy mix back to nearly 10% renewable.  Indeed, from 2001 to 2014, renewable energy use grew an average of 5% per year, largely through increased use of wind, solar, and biofuels:
  • Wind energy grew from 70 trillion Btu in 2001 to more than 1,700 trillion Btu in 2014.
  • Solar energy (solar thermal and photovoltaic) grew from 64 trillion Btu to 427 trillion Btu.
  • The use of biomass for the production of biofuels grew from 253 trillion Btu to 2,068 trillion Btu.
According to EIA, inn 2014, slightly more than half of all renewable energy was used to generate electricity.  Renewable energy accounted for 13% of energy consumed within the electric power sector, the highest renewable use attributable to any sector.

Maine explores non-transmission alternatives coordinator

Thursday, July 2, 2015

Should Maine designate an entity to coordinate the development of lower-cost alternatives to new electric transmission lines?  The Maine Public Utilities Commission has opened an inquiry to obtain comments on the role of a non-transmission alternative (NTA) coordinator and the parameters for procuring the services of an NTA coordinator.

Modern society counts on electric utilities and power plants to supply consumers with electricity.  As consumer needs and plant economics change over time, utilities have traditionally looked to new infrastructure like transmission lines to meet new needs.  But in some cases, transmission development may not be the cheapest or best way to meet consumer needs; rather, "non-transmission alternatives" such as distributed generation, energy efficiency or microgrids may be able to achieve the same ends for a lower total cost.

Grid modernization -- and the tools needed to manage the process efficiently -- can be controversial.  By order dated May 11, 2015, the Maine Public Utilities Commission declined to designate a "Smart Grid Coordinator" to provide a broad array of services to the state, on the grounds that that the record before it did not support a finding that designate a coordinator to provide all these services was in the public interest.

But the Commission indicated interest in designating someone to provide the services of marketing, implementing, and possibly operating non-transmission alternatives.  To that end, the Commission found "there is the potential for benefits from an entity that has the relevant expertise and a commercial interest in the successful development and implementation of NTAs" -- provided that the entity can deliver its services in a way that provides value to ratepayers.

By a June 30 Notice of Inquiry, the Commission initiated the next phase of its exploration of designating an NTA coordinator.  The Commission requested comment on issues it had previously identified in its May 11 order as requiring further factual development to enable the Commission to determine whether it is in the public interest to designate an NTA coordinator:
  1. What duties should be included in the scope of services offered by an NTA coordinator?
  2. Should T&D utilities be allowed to bid on an NTA RFP and if so should such services be provided through an affiliate? 
  3. If an RFP were seeking proposals for having a non-utility entity operate an NTA in a manner consistent with reliability and cyber security standards, how would the incremental costs to operate the NTA be determined?
  4. What type of pricing structures should be considered in developing the RFP?
  5. What factors should be considered in bid evaluation?
  6. What should be the term of the NTA coordinator contract?
  7. What entities should be the counterparties to the contract?
  8. What enforcement mechanisms should be included in the contract?
  9. What type/amount of financial security should be required?
The Commission also invited comment on any other issues relevant to its consideration of designating an NTA coordinator.  The Commission requests that comments be filed by July 21, 2015.  After comments are received, Commission staff will schedule a meeting to discuss the comments and discuss next steps in the development of a request for proposals.

Supreme Court rules on EPA power plant regulations

Wednesday, July 1, 2015

The Supreme Court of the United States has ruled that the U.S. Environmental Protection Agency acted unreasonably in developing new regulations on hazardous air emissions from power plants without considering the cost impact of those regulations.  This ruling reinjects uncertainty into EPA's "Mercury and Air Toxics Standards" and other efforts to regulate power plant emissions under the Clean Air Act.

The federal Clean Air Act was designed to improve environmental quality and human health, among other goals.  It broadly allows federal regulation of air emissions of pollutants of various types and from various sources.

Because certain specific provisions in the Clean Air Act applied specifically to power plants, Congress placed a special restriction on EPA's regulation of power plant emissions under Section 7412(n)(1)(A) of the Clean Air Act.  That provision allows EPA to regulate emissions of hazardous air pollutants from power plants under Section 7412 only if it “finds such regulation is appropriate and necessary.”  In 2000, after a study, EPA concluded that regulating power plants under Section 7412 was "appropriate and necessary."  EPA reaffirmed this finding in 2012, and promulgated standards for emissions from power plants.

Along with those standards, EPA issued a “Regulatory Impact Analysis” estimating that the regulation would force power plants to bear costs of $9.6 billion per year.  That analysis also found that while benefits were hard to fully quantify, estimated benefits were worth $4 to $6 million per year.  Based on this analysis, compliance costs to power plants were thus between 1,600 and 2,400 times as great as the quantifiable benefits from reduced emissions of hazardous air pollutants.  At the same time, EPA argued that it did not have to consider costs in establishing its standards.

Following the issuance of these standards, 23 states sought review of EPA’s rule in the D. C. Circuit Court of Appeals in a series of cases which were later consolidated.  The D.C. Circuit upheld EPA's refusal to consider costs in its decision to regulate, at which point petitioners appealed to the Supreme Court. As my partner Jeff Talbert explains, in a 5-4 decision issued June 29, the Supreme Court held that EPA interpreted §7412(n)(1)(A) unreasonably when it deemed cost irrelevant to the decision to regulate power plants.

So what does the Supreme Court's ruling mean for U.S. power plants?  Uncertainty -- but not necessarily freedom from regulation.  The Supreme Court remanded the case back to the D.C. Circuit for further consideration.  The D.C. Circuit could uphold the rule again (on new grounds, compliant with the Supreme Court's decision) -- or it could invalidate the rule based on the Supreme Court ruling.  If that happens, EPA will likely have to resume the process of developing new regulations for hazardous air emissions from power plants under Section 7412.

New York's 2015 Energy Plan

Tuesday, June 30, 2015

The state of New York has released a sweeping plan for its energy future, featuring strengthened commitments to clean energy over the next four decades.  The 2015 New York State Energy Plan includes reductions in greenhouse gas emissions, increased generation of renewable energy, and improved energy efficiency.

Article 6 of New York's energy law requires the state's energy planning board to develop period state energy plans.  The state released its two-volume 2015 report on June 25, presenting "a comprehensive strategy to create economic opportunities" in New York based on Governor Andrew Cuomo's previously-announced "Reforming the Energy Vision" or REV program.

Among the 2015 plan's elements are a series of clean energy targets, including a 40% reduction in greenhouse gas emissions from 1990 levels; 50% of electricity generation coming from carbon-free renewables; and 600 trillion Btu in energy efficiency gains, which equates to a 23% reduction
from 2012 in energy consumption in buildings.

Whether and how New York will implement its 2015 State Energy Plan remains to be seen.  Notably, the plan was produced by the state's executive branch; it is unclear whether legislators will support or thwart it.  Will the Empire State follow its latest plan?  If so, will it lead to the anticipated economic opportunities?

Maine RGGI report 2015: price impact "relatively modest", programs helpful

Friday, June 12, 2015

For 8 years, states in the Northeastern U.S. have participated in the Regional Greenhouse Gas Initiative.  RGGI, the first market-based greenhouse gas regulatory program in the United States, represents a cooperative effort by participating states to cap and reduce greenhouse gas emissions from the electric power sector, coupled with a market for auctioning and trading emission allowances.  While some groups feared that the RGGI program would increase electricity prices, a recent report by the Maine Public Utilities Commission found that the impact of RGGI on electricity prices in Maine has been relatively modest -- while finding that RGGI-funded programs contribute to economic development and reduce greenhouse gas emissions.

RGGI formed in 2007, when ten states -- Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont -- agreed to first cap, and then slowly reduce, the greenhouse gas emissions of their electrical energy sectors by 10% by 2018.  While New Jersey withdrew in 2012, the program has remained strong; in 2014, the remaining states subsequently tightened the RGGI cap for 2014 from 165 million short tons of carbon to 91 million short tons, then further declining 2.5% per year from 2015 to 2020.

While each participating state adopted its own laws implementing RGGI, in general the RGGI laws require certain generators of electricity to track their carbon emissions and acquire an “allowance” for every ton of carbon dioxide or its equivalent that they emit.  States conduct periodic auctions of allowances, and market participants are free to engage in secondary market trades.  Generators must purchase or trade for enough emissions allowances to match the number of tons of CO2-equivalent emitted.  The cost of acquiring these allowances gives generators an incentive to improve their efficiency or switch to fuels with a lower carbon intensity.

Each state also adopted its own laws governing the use of funds raised by state auctions of RGGI allowances.  In Maine, most funds go to the Efficiency Maine Trust for purposes including measures, investments and arrangements that reduce electricity consumption or reduce greenhouse gas emissions and lower energy costs at commercial or industrial facilities, and for investment in measures that lower residential heating energy demand and reduce greenhouse gas emissions.

RGGI has conducted 27 quarterly allowance auctions since September 2008, through which Maine has received a cumulative total of $ 62.22 million in RGGI auction proceeds.  Maine’s auction proceeds in 2014 totaled $11.37 million. According to the Maine Public Utilities Commission's report:
the annual cost to Maine ratepayers of the RGGI program was approximately $0.0024 per kWh. For the average Maine residential customer using 530 kWh per month, the 2014 RGGI program cost was approximately $ 1.27 per month. For a commercial customer using 25,000 kWh per month the 2014 RGGI program cost was approximately $60.00 per month. A large commercial or industrial customer using 500,000 kWh per month would have had a 2014 RGGI program cost of approximately $1,200 per month.
On the benefits side of the ledger, the Commission's report cites a finding that "all RGGI proceeds since 2008 are expected to return more than $2 billion in lifetime energy bill savings to more than 3 million households and more than 12,000 businesses across the eight states taking part in RGGI."  The Commission also cited its July 2014 report to the Legislature quantifying the increases in employment, real personal income, and gross state product expected to occur in Maine as a result of the cap tightening and other changes implemented in 2014.  That report found:
economic impacts for the New England region include a cumulative increase in Gross Regional Product of over $2 billion, a cumulative increase in employment of 38,900 job-years, and a cumulative increase in real personal income of $1.5 billion including a cumulative increase in Maine Gross State Product of $200 million, a cumulative increase in employment of more than 5,000 job-years, and a cumulative increase in real personal income of $100 million.
Based on these observations, the Maine Public Utilities Commission's 2015 report on RGGI concludes that "the impact of RGGI on electricity prices has been relatively modest, while RGGI-funded programs contribute to the gross state product, job growth, and personal income, and also reduce greenhouse gas emissions."

Transmission line for Canadian imports advances

Tuesday, June 9, 2015

A proposed high-voltage direct current transmission line designed to import Canadian power into the New England grid has received a favorable environmental recommendation from the U.S. Department of Energy. 

The New England Clean Power Link is a high-voltage, direct-current transmission project proposed by TDI New England, a subsidiary of private transmission developer Transmission Developers Inc. and ultimately part of the Blackstone Group.

Designed to feed the New England market with up to 1,000 megawatts of electricity, the proposed $1.2 billion New England Clean Power Link project would feature two parallel cables approximately 5” in diameter, operating at a voltage of approximately 300 to 320 kV.  These HVDC lines would run about 154 miles.  Originating at a DC converter station in Quebec, the U.S. portion of the line would start at the international border in Alburgh, Vermont.  It would run beneath the bottom sediments of Lake Champlain for about 98 miles, then turn east and run over land (but underground, mostly under roadway rights-of-way and railway beds) to a terminal converter station in Ludlow, Vermont, where the power could flow onto the New England grid.

Federal law requires most infrastructure development for international trade in energy to apply for and receive a Presidential Permit before the project may be built.  TDI New England applied for the presidential permit in May 2014, and applied to the state of Vermont for permits in December 2014.

As part of the Presidential Permit process, the federal National Environmental Policy Act or NEPA requires the U.S. Department of Energy to evaluate the potential environmental impacts in the United Statesof the proposed action and the range of reasonable alternatives.  In this case, the proposed federal action is the issuance of a Presidential permit to the applicant, Champlain VT, LLC, doing business as TDI - New England, to construct, operate, maintain, and connect a new electric transmission line across the U.S.-Canada border in northern Vermont.

On June 3, the Department of Energy released its final draft Environmental Impact Statement or EIS for the New England Clean Power Link.  In that document, the Department found relatively minimal and short-term adverse environmental impacts from project construction, operation and maintenance. 

Once notice of the draft EIS is published in the Federal Register, the public will have 60 days to comment on its analysis.  The Department will also hold public informational meetings in Vermont regarding the project.  According to the EIS, TDI New England expects permitting will continue through mid-2016, with construction and in-service dates as early as 2018 and 2019 respectively.

Meanwhile, TDI is simultaneously pursuing other HVDC transmission lines from Canada into the Northeastern US, most notably the Champlain-Hudson Power Express -- another HVDC line beneath Lake Champlain but continuing on overland and under the Hudson River to a converter station in New York City.   The Champlain-Hudson Power Express won a Presidential Permit in 2014.

NYISO solar study announced

Thursday, June 4, 2015

Solar power is booming in the U.S. -- but how will growth in solar photovoltaic generating capacity affect the electricity grid?  The operator of the state of New York's electric grid has announced a study of the potential for growth in solar power resources to determine their impact on grid operations over the next 15 years.

Solar panels recently developed in a farm field in Massachusetts.
The New York Independent System Operator (NYISO) operates New York State's high-voltage transmission network, runs the state's wholesale electricity markets.  NYISO also evaluates trends in utility infrastructure development and usage, and what changes in these patterns imply for future infrastructure needs.

One such trend is the recent rapid growth in installed solar electric generating capacity.  In New York, a state government initiative known as NY-Sun aims to reduce solar installation costs by stimulating demand and increasing the number of solar PV systems installed in the state.  The NY-Sun program envisions the installation of more than 3,000 megawatts of customer-sited solar capacity by 2023, supported by about $150 million in annual state funding for solar PV projects.  Already, in the first two years of NY-Sun, a total of 316 megawatts of solar electric has been installed or is under contract.

Unlike standalone utility-scale solar development, the solar buildout directly triggered by the NY-Sun program will occur “behind the meter” — that is, on the customer's side of the utility meter, as opposed to a typical power plant sited remotely from customer load.  Nevertheless, increased consumption of power produced by distributed generation might affect NYISO's load forecasts or grid operations.  So too might the collective impacts of many generators with variable but correlated output.

To prepare for this future, NYISO has announced a "solar study" to evaluate the growing impact of sun-powered generation.  The study will focus on the following objectives:
  • Developing solar forecasting tools and preparing 15-year forecasts of solar PV capacity for each of the 11 load zones in New York State
  • Researching how other independent system operators and regional transmission organizations have integrated solar resources into their grids
  • Evaluating solar generation variability and its impact on customer load served by the NYS electric systems.
  • Reviewing operational impacts of various levels of solar and wind resources.

The results of NYISO's solar study are expected to be released in a report later this year.

FERC approves Iberdrola-UIL merger

Tuesday, June 2, 2015

Federal utility regulators have issued an order authorizing transactions the merger of utilities affiliated with Iberdrola, S.A. and UIL Holding Corporation.

Iberdrola is a Spanish-owned utility holding company, owning electricity and natural gas systems and electric generation across four continents.  Its direct wholly owned subsidiary Iberdrola USA holds all of Iberdrola’s energy-related operations in the United States through two intermediate holding companies. Iberdrola USA Networks, Inc., holds transmission owning public utility affiliates, including New York State Electric & Gas Corporation (NYSEG), Rochester Gas and Electric Corporation, Central Maine Power Company, Maine Natural Gas Company, and interests in Maine Electric Power Company. Iberdrola Renewables Holdings, Inc. owns and operates its generation segment in the United States through a number of indirect subsidiaries.

UIL is in the business of ownership of operating regulated utilities in Connecticut and Massachusetts. It owns and controls the United Illuminating Company, a business engaged in purchasing, transmitting, and distributing electric power to customers in southwestern Connecticut. United Illuminating owns a 50 percent equity interest in GCE Holding LLC which in turn owns two companies owning 187.6 MW dual-fuel generating plants in Milford and Middletown, Connecticut. UIL also owns natural gas local distribution companies in central and southern Connecticut and western Massachusetts, as well as Total Peaking Services, LLC which provides liquefied natural gas storage services.

On February 26, 2015, Iberdrola S.A. announced the boards of directors of Iberdrola S.A. and Iberdrola USA had approved a combination of Iberdrola USA with UIL Holdings in a friendly transaction, reportedly for about $3 billion.  On March 25, 2015, Iberdrola and UIL applied to the Federal Energy Regulatory Commission for authorization under section 203(a)(1) and (a)(2) of the Federal Power Act (FPA) for a series of transactions in which UIL will become an indirect wholly owned subsidiary of Iberdrola USA and, in turn, a wholly owned subsidiary of Iberdrola.

In a Section 203 case, the Commission examines a merger’s effect on competition, rates and regulation, and the potential for cross-subsidization.  Applicants must demonstrate that a proposed disposition or acquisition of jurisdictional facilities meets the standards of Section 203.   In the Iberdrola-UIL case, the applicants stated that their subsidiaries' portfolios of generation, transmission, natural gas assets, and other jurisdictional facilities had only de minimis overlap, that the transaction would not adversely affect rates or regulation, or result in cross-subsidization of a nonutility associate company or pledge or encumbrance of utility assets for the benefit of an associate company.

On June 2, 2015, the Commission issued an order finding that the proposed transaction is consistent with the public interest and is authorized, subject to routine conditions.  While other regulatory approvals may be required before the merger can proceed, securing prior authorization under Section 203 is an important milestone for the proposed deal.

According to Iberdrola, the combined company will have a 2014 pro forma EBITDA of approximately $2 billion, net income of $570 million, 3.1 million of points of supply, around 6.7 GW of installed capacity.  Iberdrola anticipates that the company will become the US's second largest wind operator and one of the nation's largest utilities.

Feds settle on final 2011 Southwest blackout penalty

Friday, May 29, 2015

Over four years after a major 2011 power outage in Southern California and parts of the Southwest, federal energy regulators have approved the sixth and final settlement of penalties for violations of law and reliability standards

After the September 8, 2011 blackout left more than 5 million people in Southern California, Arizona and Baja California, Mexico, without power for up to 12 hours, the Federal Energy Regulatory Commission began investigating what had happened.  After conducting that investigation jointly with electric reliability organization North American Electric Reliability Corporation (NERC), in an April 2012 report FERC found that the outage started when a 500-kilovolt transmission line owned by utility Arizona Public Service Company tripped.

The FERC continued its investigation into the 2011 Southwest blackout after its staff report was made public.  It identified six entities believed to have been involved: Arizona Public Service Company, the California Independent System Operator, the Imperial Irrigation District, Southern California Edison, the Western Area Power Administration, and the Western Electricity Coordinating Council Reliability Coordinator.

FERC's enforcement process typically offers the accused an opportunity to agree to a stipulation of facts (for example, that the utility violated a particular reliability standard) and to pay a civil penalty and perform mitigation measures.  In its enforcement actions related to the 2011 Southwest blackout case, all six entities ultimately agreed to stipulations and penalties that were accepted by the Commission.

In July 2014, the FERC accepted Arizona Public Service's stipulation with NERC and FERC's Office of Enforcement, under which APS agreed to pay $3.25 million and improve its system reliability.  In August 2014, California's Imperial Irrigation District agreed to a $12 million fine.  Utility Southern California Edison agreed to a $650,000 fine in October.  In December, FERC settled with federal power marketing agency Western Area Power Administration with no penalty.  Grid operator California ISO agreed to pay $6 million.

This week the FERC announced a settlement with Western Electricity Coordinating Council.  WECC promotes grid reliability in the Western Interconnection, a broad area of the western United States.  According to the FERC order, FERC enforcement staff and NERC determined that WECC as the Reliability Coordinator violated nine requirements of the Interconnection Reliability Operations and Coordination (IRO) and the Facilities Design, Connection and Maintenance (FAC) groups of Reliability Standards.  Enforcement staff and NERC concluded that WECC failed to identify and prevent violations of system operating limits and Interconnection Reliability Operating Limits and was unaware of the impact of protection systems, and used an inadequate system operating limit methodology that exposed its area to cascading outages.

As a result, the settlement calls for WECC to pay a $16 million civil penalty.  $3 million of this will be split evenly between the U.S. Treasury and NERC, and $13 million will be invested in reliability enhancement measures that go above and beyond mitigation of the violations and the requirements of the Reliability Standards.  WECC and its successor as Reliability Coordinator, Peak Reliability, also agreed to mitigation and reliability activities and to submit to compliance monitoring.

FERC has described the WECC settlement as marking "final resolution" of the investigation by FERC Enforcement staff and NERC into the 2011 Southwest blackout.