Report: New England electric sector will face gas supply deficit

Friday, November 21, 2014

A recently released report on the adequacy of New England’s natural gas pipeline infrastructure has identified the potential for shortfalls in gas supply to electric generators through 2020.  The November 20, 2014 report, Assessment of New England’s Natural Gas Pipeline Capacity to Satisfy Short and Near-Term Electric Generation Needs: Phase II, was prepared by consulting group ICF International for regional electric grid operator ISO New England Inc.  It found “a high probability that the electric sector will have a gas supply deficit on 24 to 34 day per winter by 2019/20.”

The Phase II report follows on a 2011/12 “Phase I” study by ICF of the adequacy of the natural gas pipeline infrastructure in New England to serve the combined needs of the core natural gas market and the regional electric generation fleet.  In the years since the Phase I study, existing natural gas and electric power systems have experienced significant changes, with further changes projected.  ISO-NE also identified the need to extend the power sector gas supply adequacy analysis beyond the peak winter and summer demand day, to examine supply adequacy throughout the peak winter demand period (December 1 through February 28).

ICF’s Phase II report presents its updated findings given these changes.  Its conclusions include:
  • Despite the likelihood of 450 MMcf/d of new interstate natural gas transportation capacity being added by the end of 2016, the New England market is likely to remain supply constrained through 2020.
  • Updating projections for energy efficiency has a significant impact on projected gas consumption for electric generation. The studied cases reduced projection winter peak day gas consumption by as much as 550,000 Dth by 2019/20.  However, this was not sufficient to eliminate the projected winter peak day supply deficits.
  • Future imports of liquefied natural gas (LNG) into the region are likely to be well below the rated capacity of the import terminals.  Neither the Northeast Gateway nor Neptune offshore import terminal has received any shipments since 2010, and neither was projected to receive any future LNG shipments in this study.
  • The Maritimes & Northeast Pipeline from Eastern Canada into New England is expected to continue to flow at full capacity on a peak winter day. Eastern Canadian gas production is expected to decline overall from 2015 through 2020, even as the Deep Panuke field ramps up its production. Historically, the Canaport LNG terminal in St. John, New Brunswick, has been managed to keep the pipeline full on peak winter days (when New England gas demand and gas prices are highest). In the future, with fewer LNG shipments coming in, the pipeline will flow full on fewer winter days, reducing natural gas supplies into New England.
  • The Winter Near-Peak analysis indicates that gas supply deficits may occur not just on peak days, but also on multiple high demand days throughout the winter. Based on projected gas supplies, local distribution company (LDC) demands for retail gas supply, and electric generator gas demands, there is a high probability that the electric sector will have a gas supply deficit on 24 to 34 day per winter by 2019/20.
With the Phase II report now in ISO New England's hands, the grid operator has an updated analysis of the adequacy of the region's natural gas pipeline infrastructure to meet all the demands on it through 2020.  ISO New England describes itself as playing three critical roles: grid operation, market administration, and power system planning.  From all three of these perspectives, projections of a high probability of gas supply deficit for the electric power sector are troubling.  ICF's findings thus may shape how ISO New England -- or state and federal regulators -- reforms the New England gas and electric markets.

Rhode Island offshore transmission line

Thursday, November 20, 2014

Federal regulators have granted a right-of-way in federal waters for an electric transmission line connecting to the proposed Block Island offshore wind farm off Rhode Island.  The Bureau of Ocean Energy Management describes the grant as the first right-of-way grant offered in federal waters for renewable energy transmission.

Proposed by Deepwater Wind, the Block Island Wind Farm is a 30-megawatt offshore wind farm to be located approximately three miles southeast of Block Island.  Located entirely in Rhode Island state waters, the 5-turbine project is expected to generate over 125,000 megawatt hours annually.  The project received its final required permit in September 2014, and in 2010 secured a 20-year power purchase agreement with Narragansett Electric Co.

Block Island is about 13 miles off the mainland coast, and is not connected to the mainland by a power cable or road.  While the island's population does consume some electricity, most of the wind farm's power will be exported to the mainland electric grid via a newly built 21-mile submarine cable.  Because the proposed Block Island Transmission System is bi-directional, it would also transmit power from the existing onshore transmission grid on the mainland to Block Island, stabilizing supplies of electricity available to islanders.

The Block Island Transmission System is proposed to make landfall in Narragansett, Rhode Island.  Rhode Island's territorial waters extend 3 miles seaward from shore.  To reach the mainland, the submerged transmission line must cross about 8 nautical miles of federal waters.

The Bureau of Ocean Energy Management regulates the use of federally controlled Outer Continental Shelf sites for energy production.  In 2012, Deepwater Wind applied to the BOEM for a right-of-way about eight nautical miles long and 200 feet wide.  Before reviewing this application, BOEM was required to determine whether there are other developers interested in constructing transmission facilities in the same area.  Therefore, BOEM published a Commercial Renewable Energy Transmission on the Outer Continental Shelf (OCS) Offshore Rhode Island, Notice of Proposed Grant Area and Request for Competitive Interest (RFCI) in the Area of the Deepwater Wind Block Island Transmission System Proposal in the Federal Register on May 23, 2012 under Docket ID BOEM-2012-0009.  BOEM also solicited public comment on site conditions and multiple uses within the right-of-way grant area. 

Following the public comment period, BOEM determined there was no overlapping competitive interest in the proposed right-of-way grant area off Rhode Island and published a "Notice of Determination of No Competitive Interest" in the Federal Register on August 7, 2012 under Docket ID: BOEM-2012-0068.

Because most of the activities and permanent structures related to the entire wind farm project will be sited in state waters and on state lands, the U.S. Army Corps of Engineers is the lead federal agency for analyzing the potential environmental effects of the project under the National Environmental Policy Act.   In September 2014, the Corps completed its Environmental Assessment (EA) for the wind farm and transmission system, and issued a Finding of No Significant Impact (FONSI).   BOEM subsequently adopted the Corps EA after conducting an independent review that found no reasonably foreseeable significant impacts are expected to occur as the result of the preferred alternative, or any of the alternatives contemplated by the EA.  On October 27, 2014, BOEM issued a FONSI for the issuance of a ROW grant, and approval of the General Activities Plan (GAP), with modifications.

On November 17, 2014, BOEM announced the agency offered the ROW grant to Deepwater Wind for the Block Island Transmission System.

Southwest Power Pool to expand

Wednesday, November 19, 2014

The Federal Energy Regulatory Commission has largely accepted a proposal to expand the geographic footprint of the Southwest Power Pool, a regional power market that will soon include a significant portion of the Upper Great Plains.

Southwest Power Pool, Inc. (SPP) was founded in 1941 by a coalition of regional power companies interested in keeping an Arkansas aluminum factory supplied with power to meet critical defense needs.  Since 2004, SPP has been recognized by the FERC as a Regional Transmission Organization or RTO.  Today, SPP organizes and operates parts of the electric power grid in nine states: Arkansas, Kansas, Louisiana, Mississippi, Missouri, Nebraska, New Mexico, Oklahoma, and Texas. 

On September 11, 2014, pursuant to section 205 of the Federal Power Act (FPA), SPP submitted to the FERC proposed revisions to its governing documents to facilitate the decision of three major transmission owners of the so-called Integrated System in the Upper Great Plains to join SPP.  The three proposed member-owners are:

  • Western Area Power Administration – Upper Great Plains Region: one of four regions of the United States Department of Energy's Western Area Power Administration. Western is a federal power marketing agency that markets federal power and owns and operates transmission facilities through 15 western and central states, encompassing a geographic area of 1.3 million square miles. Western ’s primary mission is to market federal power and transmission resources constructed with Congressional authorization. The federal generation marketed by Western is generated by power plants that were constructed by federal generating agencies, principally the Department of the Interior’s Bureau of Reclamation and the U.S. Army Corps of Engineers. In the Upper Great Plains Region , or Western - UGP, Western owns an extensive system of high - voltage transmission facilities and markets federally generated hydroelectric power in the Pick - Sloan Missouri - Basin Program - Eastern Division of Western.
  • Basin Electric Power Cooperative: serves 2.8 million customers in territories covering approximately 540,000 square miles using nearly 2,100 miles of transmission lines and 70 switch yards
  • Heartland Consumers Power District: a public corporation and political subdivision of the State of South Dakota. It provides wholesale power to 28 municipalities in eastern South Dakota, southwest Minnesota, and northwest Iowa, to six South Dakota state agencies, and to one electric cooperative in South Dakota.
These entities proposed to join SPP as transmission owning members, to place their respective transmission facilities under the functional control of SPP, and to begin taking transmission service under the SPP Tariff.  Their stated motivation was increasing market size and thus opportunities for both consumers and producers of energy.

By order dated November 10, 2014, the FERC accepted SPP's proposal.  Together, these new SPP members provide the backbone of the bulk electric transmission system across seven states in the Upper Great Plains region consisting of approximately 9,500 miles of transmission lines rated 115 kV through 345 kV.  The FERC order directed SPP to take certain interim steps, and SPP has announced plans to integrate the three new utilities by October 2015.

Setting fees for use of federal dams

Monday, November 17, 2014

Federally owned dams and other structures can create opportunities for private development of hydropower facilities, in exchange for a fee.  While fees charged to hydropower developers for using federally owned dams will likely remain stable in the near term, a look at the history of government dam use charges illustrates the process and dynamics involved in setting these fees.

Under federal law, many aspects of hydropower projects are regulated by the Federal Energy Regulatory Commission.  Section 10(e)(1) of the Federal Power Act (FPA) authorizes the Commission to collect annual charges from hydropower licensees whose projects make use of government dams or other structures owned by the United States.

Before 1984, the Commission assessed charges for the use of government dams and other United States structures on a case- by-case basis.  Typically, the Commission charged licensees half of the project's shared net benefit.  That net benefit was defined as the difference between the value of the power (taken as the least expensive alternative power) and the cost of project power (computed from the costs of building and operating the project). 

In 1984, the Commission issued Order No. 379, replacing its government dam use charges with graduated flat rates.  In that order, the Commission concluded that this method "best balances the statutory goals of providing a reasonable return to the Federal government, encouraging hydropower development, especially small projects, and minimizing costs to consumers."

Congress enacted the Electric Consumers Protection Act (ECPA) in 1986, which amended those portions of Section 10(e) of the FPA that authorize the Commission to collect government dam use charges.  ECPA adopted the method and rate levels of the Commission's new graduated flat rate structure as both the maximum allowable and the only federal dam use charges assessed by any U.S. agency. The Commission currently levies these maximum values, as it has since adopting them in 1984.

Section 10(e)(4) of the FPA requires the Commission to report to Congress every five years on whether the government dam use charges are appropriate.  The Commission's fifth and most recent report, dated October 17, 2013, concluded that the fees continue to provide reasonable compensation to the government.  The report noted that in the last five years some licenses for both constructed and unconstructed projects at government dams have been surrendered or terminated, but that there had been no indication that the dam-use fees played a role in such outcomes.  In addition, the Commission noted that it had issued 18 new licenses to projects located on government dams in the last five years that will be subject to these fees when they begin to generate power.

With a no-action recommendation by the Commission, Congress may choose not to amend Section 10(e) of the Federal Power Act in the near term.  However, the ECPA requires a periodic reassessment of the level of government dam use charges; the next mandatory report will come in 2018.  Moreover, Congress is interested in promoting new hydropower development, as is evidenced by its enactment of the Hydropower Regulatory Efficiency Act of 2013; Congress could, on its own, modify government dam use charges.  Nevertheless, for the near term, U.S. government dam use charges assessed under the Federal Power Act will likely remain stable.

NYC tidal energy project in question

Friday, November 14, 2014

The future of a proposed New York City tidal energy project is in question.  New York Tidal Energy Company's (NYTEC) East River Tidal Energy Pilot Project would be located in the East River at Hell Gate, in New York City, New York.  But a recent letter by federal regulators questions whether the developer intends to continue pursuing the project.

Marine hydrokinetic (or MHK) projects generate electricity from moving water such as tides, waves, and free-flowing rivers without the use of dams.  While technologies vary, many rely on underwater turbines powered by tidal currents.to spin generators.  Hydrokinetic energy development is generally regulated by the Federal Energy Regulatory Commission, which issues preliminary permits and licenses for project development.

The East River project's regulatory process began in 2006, when Oceana Energy Company subsidary NYTEC applied to the FERC for a preliminary permit for what it called the Astoria Tidal Energy Project.  That application described a project composed of between 50 and 150 Tidal In Stream Energy Conversion (TISEC) devices consisting of rotating propeller blades, integrated generators with a capacity of 0.5 to 2.0 MW each, anchoring systems, mooring lines, and interconnection transmission lines.  The project was estimated to have an annual generation of 8.76 gigawatt-hours per-unit per-year, which would be sold to a local utility.  After resolving a dispute with fellow New York City tidal developer Verdant Power, LLC, the FERC granted a preliminary permit for the Astoria project on May 31, 2007NYTEC won another preliminary permit on January 10, 2011.

On June 1, 2009, NYTEC filed a draft application for an original license for the East River Tidal Energy Pilot Project.  That license application described the proposed East River Tidal Energy Pilot Project.  As reenvisioned, the East River project would consist of: (1) a 2-meter-diameter 20 kW capacity hydrokinetic device during Phase 1, which would be replaced by a 6-meter-diameter 200 kW device in Phase 2; (2) an underwater cable connecting the hydrokinetic device to shore at one of two proposed locations; and (3) appurtenant facilities for operating and maintaining the project.  After soliciting comment from stakeholders and agencies, on November 9, 2010, the Commission issued a letter concluding the pre-filing process.

In the ensuing 4 years, while the docket experienced some activity, no final license application for the pilot project has been filed.  On November 10, FERC staff issued a letter to Oceana Energy Company asking for a status update on the proposed project within 14 days.  The letter states that staff wants to "adjust resources to workload requirements," and suggests that staff will close the docket if the developer intends to continue pursuing the proposed East River Tidal Energy Pilot Project.

What does the future hold for the East River Tidal Energy Pilot Project?

FERC considers Physical Security Reliability Standard

Thursday, November 13, 2014

Federal energy regulators are considering a new national standard for protecting the physical security of the U.S. electric grid.  Given the importance of electric reliability and concern over terrorist attacks and sabotage, electric reliability organization NERC has proposed a Physical Security Reliability Standard known as CIP-014-1.  If adopted by the Federal Energy Regulatory Commission (FERC), the standard would become enforceable against transmission owners and operators.

Under U.S. law, the FERC has jurisdiction over the network of wires and transformers that make up the nation's bulk transmission system.  The Energy Policy Act of 2005 expanded the Commission's authority to impose mandatory reliability standards on the bulk transmission system.  Working with the nation's chief electric reliability organization (North American Electric Reliability Corporation, or NERC), the Commission has adopted a series of reliability standards covering matters including communications among utilities, cybersecurity, and interconnections.

On July 17, 2014, the FERC issued a notice of proposed rulemaking proposing to approve NERC’s proposed Physical Security Reliability Standard (CIP-014-1).  NERC has described this standard as designed to enhance physical security measures for the most critical Bulk-Power System facilities and thereby to lessen the overall vulnerability of the Bulk-Power System to physical attacks.  The standard requires owners and operators of transmission facilities to identify and protect critical transmission stations, substations, and control centers whose damage through physical attack could result in spreading outages or other reliability problems.

The proposed physical security reliability standard also includes provisions protecting sensitive or confidential information from public disclosure, calling for third party verification and periodic reevaluation of critical facility identification, threats assessment, and security plans.

The FERC solicited public comment on the proposed physical security reliability standard through September 8, 2014.  Over 30 parties filed comments, with additional reply comments filed by September 22.

With the proposed Physical Security Reliability Standard now pending before the FERC, we may soon see its adoption.  The FERC has scheduled the matter for its November 20 deliberations.  Assuming CIP-014-1 is adopted, owners and operators of regulated facilities will need to comply with the new standard, and to plan for further tightening up of the physical security of the electric grid in the coming years.

Chicago-area battery storage projects announced

Wednesday, November 12, 2014

Energy developer Renewable Energy Systems Americas Inc. has announced two grid-scale energy storage projects near Chicago.

Battery-based energy storage projects can offer benefits to the electricity grid by keeping the alternating current's frequency steady, and can do so at a lower cost than alternatives like ramping generators up and down.  Thanks in part to new federal policies, battery projects capable of providing frequency regulation can now earn increased revenue for their owners. 

This week RES Americas announced plans to pursue two energy storage projects in Illinois.  The company describes itself as a specialist in third-party development and construction services for the renewable energy, transmission, and energy storage industries.  It also builds renewable energy and storage projects that it owns itself.

In an apparent tribute to the Blues Brothers, its two newly announced projects will be named Jake and Elwood.   The Elwood Energy Storage Center will be sited in West Chicago, while the Jake Energy Storage Center will be in Joliet.  Beyond names and locations, the projects bear greater resemblance to each other than to the Blues Brothers.  Both projects were acquired from Glidepath Power in September.  Each will be interconnected to the Commonwealth Edison Co. electric grid, and will have an operational life expectancy of at least ten years.  Each will use lithium iron phosphate batteries with a 19.8 megawatt capacity, capable of storing 7.8 megawatt-hours of energy.

RES Americas expects to begin construction on both projects this winter, and to complete them by August 2015.  When complete, the battery projects will be able to provide real-time frequency regulation service to the PJM Interconnection LLC ancillary services market.  Thanks to recent federal orders including FERC Order No. 784, faster and more accurate regulation resources -- like battery storage arrays -- should be compensated more highly.  These policies both increase consumer demand and reduce developers' barriers to entry into battery-based energy storage projects.

Other battery projects are moving forward, based on values other than frequency regulation.  Last month, Southern California Edison Company brought its Tehachapi Wind Energy Storage Project online.  That $50 million project, the largest currently operating in North America, is capable of storing 32 megawatt-hours, deliverable as an 8 megawatt stream of energy for 4 hours.  The Tehachapi system is designed to help even out the flow of power produced by wind farms, which is naturally variable and intermittent.  Battery systems can also be designed to improve local reliability, support microgrids, or serve as non-transmission alternatives to building more utility wires.

For more information about battery energy storage projects, recent policies favoring energy storage and the opportunities they create, contact Todd Griset at Preti Flaherty at 207-791-3000.

NH conduit hydropower project approved

Monday, November 10, 2014

Federal regulators have determined that a proposed hydropower facility at a New Hampshire wastewater treatment plant can be built without a license, under a recently enacted law.  The Federal Energy Regulatory Commission staff has found that the Ammonoosuc Water Treatment Plant Hydroelectric Project proposed by the City of Berlin Water Works is a qualifying conduit hydropower facility under federal law.  Like other conduit projects, the Ammonoosuc project involves the addition of a turbine into an existing system of pipes and pressure reduction valves, and can create additional renewable energy with few incremental impacts.

Under the Federal Power Act, most hydropower projects in the U.S. require licensure by the Federal Energy Regulatory Commission.  But last year, Congress passed the Hydropower Regulatory Efficiency Act of 2013, easing the regulatory burden on projects.  That law exempts certain so-called "conduit" hydropower facilities from the licensing requirements of the Federal Power Act.  Conduit facilities generate electricity using only the hydroelectric potential of a non-federally owned conduit, such as a tunnel, canal, pipeline, aqueduct, flume, ditch, or similar manmade water conveyance that is operated for the distribution of water for agricultural, municipal, or industrial consumption, and is not primarily for the generation of electricity.  To qualify, conduit facilities must have an installed generating capacity that does not exceed 5 megawatts (MW), and must not have been licensed or exempted from the licensing requirements of Part I of the Federal Power Act on or before August 9, 2013.  The Federal Energy Regulatory Commission subsequently issued Order No. 800, updating its rules to conform to the newly streamlined process.

While qualifying conduit hydropower facilities are not required to be licensed or exempted by the Commission, developers of qualifying facilities must file a Notice of Intent to Construct a Qualifying Conduit Hydropower Facility with the Commission.  On August 28, 2014, the City of Berlin, New Hampshire's Water Works filed such a Notice of Intent.  The proposed Ammonoosuc Water Treatment Plant Hydroelectric Project would have an installed capacity of 21 kilowatts (kW) and would be located on the existing 16-inch-diameter raw water transmission main immediately upstream from the pressure-reducing valve for the City of Berlin's water treatment plant.  The project would have an estimated annual generating capacity of 85 megawatt-hours.

The newly streamlined process can work quickly.  On September 10, Federal Energy Regulatory Commission staff issued a preliminary determination that the proposal satisfies the requirements for a qualifying conduit hydropower facility, which is not required to be licensed or exempted from licensing.  The Commission then posted this preliminary determination for public comment for 45 days.

No public comments were received, so on October 31, Commission staff issued its written determination that the Ammonoosuc Water Treatment Plant Hydroelectric Project meets the qualifying criteria under section 30(a) of the Federal Power Act, and is not required to be licensed under Part I of the Federal Power Act.

With this finding in hand just 64 days after filing its application, the city water department can continue securing the remaining approvals necessary to develop the Ammonoosuc Water Treatment Plant Hydroelectric Project.  Securing a FERC hydropower license can be a major endeavor, so the streamlined regulatory treatment now available to qualifying conduit hydropower facilities can be a major advantage.  How many other water treatment plants and other conduit owners will follow the Berlin Water Works' path and develop their own hydroelectricity assets using this easier regulatory process?

Navy objects to Maryland offshore wind project

Friday, November 7, 2014

An offshore wind energy project proposed off the Maryland coast has drawn opposition from the U.S. Department of Defense over fears that the project would disrupt the nearby Patuxent River Naval Air Station's radar facilities.

The Great Bay Wind Energy Center is a proposed wind farm project off Somerset County in Maryland's portion of the Delmarva Peninsula.  The $200 million project could produce up to 150 megawatts of power, and is currently under development by Pioneer Green Energy, LLC.

Naval Air Station Patuxent River is a U.S. naval air station located on the Chesapeake Bay near the mouth of the Patuxent River.  It operates and tests a variety of radar systems considered by the Navy to be critical to national security.  At several points through the Great Bay wind project's development process, Navy officials have said that their radar systems could be affected by signals bouncing back from the offshore turbines, compromising the Navy facility's mission and effectiveness.  The developer had offered mitigation measures, such as disabling the turbines during Navy testing.

In the latest development, Congressman Steny Hoyer has released a Department of Defense letter objecting to the proposed Great Bay Wind project.  Part of a Federal Aviation Administration process to evaluate whether it can find the project poses “no hazard", the letter to the Department of Transportation lodges the Defense Department's formal objection to the "Great Bay Energy Center project" under regulations codified as 32 C.F.R. 211.  It states that "the proposed project, even if mitigated as offered by the applicant, would constitute an unacceptable risk to the national security of the United States... because it would significantly impair or degrade the capability of the Department of Defense to conduct research, development, testing and evaluation of the Department's advanced airborne weapons systems and would ultimately place our nation's armed forces at greater risk when they go in harm's way."

Congressman Hoyer said in his accompanying statement that although he supports renewable energy, he agreed that the threats this project poses to the Pax River naval facility -- a critical national security asset -- and the 22,000 jobs it supports were too great to allow the project to proceed.

What the letter means for the project remains to be seen.  Clearly, national security is of crucial importance.  Is this the Department of Defense's final answer?  Can the developer find another way to resolve this impasse?  Will another branch of government sweep in to broker a compromise?  Or will the Department of Defense's concerns effectively end the Great Bay offshore wind project?

East coast exports of Western Canadian crude

Thursday, November 6, 2014

As Western Canada produces more heavy crude oil, will it be exported from ports on Canada's relatively distant east coast?

Eastern Canadian exports of Western Canadian crude oil may increase, according to Canadian oil producer Suncor Energy Inc.  In its third quarter investor call, company Chief Executive Officer Steve Williams indicated that it could have long-term opportunities to export Cold Lake-grade crude oil by sending it by rail from Alberta to East Coast ports.  According to ExxonMobil, Cold Lake Blend is an asphaltic heavy crude blend of bitumen and condensate.

If long-term opportunities may exist, so too have recent opportunities.  In September 2014, Suncor confirmed that it had sent its first shipment of Western Canadian crude by rail to a storage facility in Sorel-Tracy, Quebec, from which it was loaded onto a tanker ship and sent to Europe.

Many aspects of the Canadian oil industry are regulated, such as the development of new crude oil pipelines from landlocked Alberta to distant refineries, storage facilities and ports.  Several pipelines have been proposed to increase takeaway capacity from the Western Canadian oil sands region, including the Energy East Pipeline in Canada and the Keystone XL Pipeline in the U.S.  But as securing regulatory approvals for pipelines takes time, shipping crude oil by rail has emerged as a quicker alternative.

In its most recent investor presentation, Suncor touted its near-term access to global markets, with over 600,000 barrels a day of sendout capacity.  Its current capacity includes over 80,000 barrels per day by rail, as well as over 70,000 barrels per day via pipeline to the U.S. Gulf Coast.  By 2015, Suncor plans for the 130,000 barrel per day "Line 9" pipeline to be reversed, allowing flows from Sarnia into Montreal.  Beyond then, Suncor is looking at additional pipeline projects including Keystone XL, Energy East, the Trans Mountain Expansion, and the Enbridge Northern Gateway pipeline to British Columbia.

As Suncor and other Western Canadian oil producers eagerly await new pipeline capacity, rail shipments may continue to serve as a temporary measure.  If pipelines can be developed to key market points, they typically offer a lower shipping cost per barrel than railroads can.  At that point, railroads may see a reduction in the volume of oil they ship  -- but until then, Western Canadian oil producers may continue to rely on rail to reach eastern ports.

Sea level rise and coastal LNG terminals

Tuesday, November 4, 2014

Should federal agencies consider climate change and sea-level rise as they review the environmental impacts of liquefied natural gas terminals?

Yes, according to letters recently filed with the Federal Energy Regulatory Commission by the Sabin Center for Climate Change Law.  Last week the Columbia Law School center submitted comments on two cases involving applications to develop liquefied natural gas export facilities in Maine and Louisiana.

Pursuant to the National Environmental Policy Act (NEPA) and its implementing regulations, in approving an activity, the Commission must consider reasonably foreseeable indirect and cumulative environmental impacts of that activity.  Each case targeted by the Sabin Center involves a proposal to develop facilities for the liquefaction and export of natural gas from coastal or riverine sites: 
  • Downeast Liquefaction, LLC has proposed the Downeast LNG Import-Export Project, to be located in Robbinston, Maine.  The bi-directional terminal on the banks of the Passamaquoddy Bay would be capable of processing an average of approximately 300 MMcf per day of pipeline-quality natural gas (including fuel and inerts) in the liquefaction mode and 100 MMcf per day in the vaporization mode.

Procedurally, each of these cases is at the stage where the Commission solicits comment on the scope of issues it should include in its environmental review.  In similar letters filed in each docket (Downeast and Louisiana), the Sabin Center took no position on the export of liquefied natural gas or on whether the project should be approved. Instead, the center noticed that while the Commission's Notice of Intent to prepare an environmental impact statement included many important issues to consider, the notice did not identify the potential impact of climate change on the LNG project.

Specifically, the Sabin Center's letters note that sea level rise, and an associated increase in flooding and storm surges, may pose a significant risk due to the project sites' coastal location.  The letters argue that NEPA requires the Commission to assess the projected range of sea level rise and storm surge throughout the life of the projects and identify ways to prepare for climate change-related risks.  They also called for requiring the projects' design to incorporate an additional margin of safety, known as “freeboard,” to account for unanticipated risk factors that can contribute to flood heights, such as waves and the effect of development on ground water absorption.

Whether the Commission will agree with the Sabin Center remains to be seen.  As federal agencies issue permits for energy projects, they face increasing pressure from the public -- and presumably from the administration -- to consider the projects' broader implications for and from climate change.

Distributed generation is growing

Monday, November 3, 2014

Customer-sited generation is growing in the U.S.  A look at some of the distributed generation projects that came online in September 2014 shows that universities and institutions are developing projects powered by natural gas, solar photovoltaics, and oil, thanks to policies such as remote net metering and support for microgrid development.

At the University of California at Santa Cruz, Santa Cruz Cogeneration Associates has brought online a new 4.4 megawatt natural gas-fired cogeneration plant. The power generated is used on-site at the UC Santa Cruz campus.   Meanwhile the new unit will generate more than twice as much useful heat as the existing cogeneration unit, with a capacity of 1,391 tons (16,693 kBtu/h) of heating.

At the University of California at Riverside, Solar Star California XXIX LLC’s 3 megawatt UC Riverside Solar project is now online.  All of the power generated is used on-site at the UC Riverside campus, with the project's peak load representing about 30% of the campus's base load.  The University partnered with SunPower Corporation to install the 10.92-acre solar farm on campus open space.

Farther east, Cornell University’s 2 MW Snyder Road Solar Farm project came online. The power generated is used on-site at the Cornell University campus.  Cornell’s first solar photovoltaic project includes a 2MW tilt rack-mounted array on eleven acres of Cornell property in the Town of Lansing.  The Snyder Road Solar Farm is expected to produce 2.5 million kilowatt-hours annually, covering about 1 percent of Cornell’s total electricity use, and is expected to reduce the university’s annual greenhouse emissions by 625 metric tons per year.

Santa Fe Community College’s 1.5 MW Santa Fe Community College Solar project in Santa Fe County, New Mexico is online. The project is sited on 5.4 acres on campus, and consists of 4,620 SunPower 327-Watt photovoltaic modules mounted on fixed racking.  The power generated is used on-site at the Santa Fe Community College campus, generating approximately 43% of the college’s electricity demands, and saving the college more than $200,000 annually.  

Connecticut Municipal Electric Energy Cooperative’s 10 MW oil-fired Matlack Road Microgrid project in New London County, CT is online.  CMEEC supplies power and related electric services to municipal utilities and other wholesale customers that, in turn, provide electricity to roughly 70,000 residential, commercial/industrial and small business customers across the state.  The $9 million Matlack Road Microgrid project serves as emergency backup power for the Backus Hospital campus and adjacent critical facilities including schools, emergency shelters, fire station, supermarket / pharmacy, public water supply, gas station and a shopping center in the event of a sustained power outage.

Businesses and institutions choose distributed generation for a variety of reasons, but most hope for reduced costs and improved reliability compared to traditional utility service.  Will distributed generation continue to grow in the U.S.?  How will utilities -- and policymakers -- adapt as customers continue to adopt consumer-sited generation?

Questions about EPA regulation of power plant carbon emissions

Friday, October 31, 2014

This week the U.S. Environmental Protection Agency issued a public notice relating to its Clean Power Plan, the agency's proposed rule to reduce carbon emissions from the nation's existing power plants.  The notice reiterates questions raised by commenters about issues including the redispatch from coal- to natural gas-fired generation and near-term carbon reductions through 2029.

The Clean Power Plan imposes a federal carbon emissions rate (stated in pounds of carbon emitted per megawatt-hour of electric energy generated) for each state.  The rule is designed to offer states flexibility in developing plans to achieve that level of carbon intensity, and features four proposed "building block" elements that states may choose to include in their program design: increased coal plant efficiency, increased utilization of natural gas plants, increased renewable energy, and increased energy efficiency.  Collectively, EPA projects that by 2030 the Clean Power Plan's implementation will reduce power plant carbon emissions 30 percent below 2005 levels.

Since EPA published its proposal on June 18, 2014, the agency has held at least eight days of public hearings in four cities, attended by over 2,700 people, of whom nearly half spoke or otherwise weighed in.  The draft Clean Power Plan was originally scheduled for public comment through October 16, but EPA extended the comment period by 45 days (until December 1, 2014) in response to both the volume of comments and numerous requests for additional time. 

On October 28, EPA issued a notice of data availability related to the proposed Clean Power Plan.  EPA routinely issues such a notice, or NODA, to provide the public with a targeted opportunity to consider and comment on emerging technical issues and data related to an ongoing rulemaking.  EPA's Notice of Data Availability Related to the Proposed Clean Power Plan (PDF) provides additional information on several topics raised by stakeholders and solicits comment on the information presented.  The three topics covered in the notice are the emission reduction compliance trajectories created by the interim goal for 2020 to 2029, certain aspects of the building block methodology, and the way state-specific carbon dioxide goals are calculated.

EPA's interim goals govern emission reductions over the 2020-2029 period, as states transition to energy resources with lower carbon intensity.  Some stakeholders have expressed concern that, as proposed, the interim goals do not provide enough flexibility for some states which may be forced to rely heavily on re-dispatch from fossil steam generation (e.g., coal- , oil-, or gas-fired boilers) to natural gas combined cycle units to achieve the required reductions, and that this effect of the interim goals severely limits the opportunity to fully take advantage of the remaining asset value of existing coal-fired generation -- particularly challenging with the threat of a "polar vortex" or other disruptive weather event.  EPA requests comment on these interim goals and whether they afford suitable flexibility.

Stakeholders have also raised questions about the building blocks available to states as they design compliance programs.  In particular, building block 2 focuses on shifting utilization from coal- and other fossil-fired steam power plants to more carbon-efficient natural gas combined cycle plants.    Building block 3 focuses on renewable energy and nuclear power.  In response, EPA requests comment on ways that building block 2 could be expanded to include new natural gas combined cycle units and natural gas co-firing in existing coal-fired boilers and ways that state-level renewable energy targets could be set based on regional potential for renewable energy.

Stakeholders have also noted concerns with the way the state-specific carbon dioxide goals are calculated.  These include concerns that the numeric formula for calculating each state's goal is not consistent in its application of the best system of emission reduction (BSER) for each building block, and concerns with the use of data for the single year 2012.

EPA's Clean Power Plan is now open for public comment through December 1, 2014.

Value of distributed solar energy

Thursday, October 30, 2014

What is the value of distributed solar photovoltaic electric generation?  An investigation by the Maine Public Utilities Commission into this question is ongoing, and will culminate in a report to the state legislature this winter.  At stake are policies and incentives to foster the growth of solar energy in Maine.

Distributed solar generation -- such as solar panels on rooftops and ground-mounted solar arrays -- is a small but rapidly growing sector of the U.S. energy mix.  Solar panels can produce renewable electricity, with no direct fuel use, emissions, or reliance on foreign energy sources.  Customer-sited and other distributed generation resources can also enhance the reliability of the local electric grid, and reduce the need for more expensive transmission and distribution upgrades.  The growing shift to solar energy is also seen as a driver of jobs and economic development.

Rooftop solar photovoltaic panels on a business in Patten, Maine.
In recognition of these benefits, states and the federal government have enacted a variety of policies and incentives for solar power development and use.  These policies include renewable portfolio standards which mandate that utilities source certain amounts of their power from renewable resources, as well as net metering policies which allow a customer to offset its power bill with energy produced from on-site solar panels.

But what is the true value of distributed solar energy resources?  In an effort to find out, in 2014 the Maine Legislature enacted An Act To Support Solar Energy Development in Maine.  This law is also known as the Maine Solar Energy Act, P.L 2013 Chapter 562 (codified at 34-B M.R.S. §§ 3471-3473).  The law expresses the legislative finding that Maine's solar energy resources "constitute a valuable indigenous and renewable energy resource."  Moreover, the law is predicated on the findings that solar energy development is unique in its benefits to and impacts on the climate and the natural environment, and that it can help Maine because it can displace fossil fuel combustion and associated air pollution and greenhouse gas emissions.   The Act set a state policy "to encourage the attraction of appropriately sited development related to solar energy generation, including any additional transmission, distribution and other energy infrastructure needed to transport additional solar energy to market, consistent with all state environmental standards; the permitting and financing of solar energy projects; appropriate utility rate structures; and the siting, permitting, financing and construction of solar energy research and manufacturing facilities for the benefit of all ratepayers."

With these findings noted, the Act directed the Maine Public Utilities Commission to construct a report by February 15, 2015 on the value of distributed solar energy generation in Maine.  In so doing, the Act requires the Commission to develop a method for valuing distributed solar energy generation.   By statute, this method must, at a minimum, account for:
  • the value of the energy;
  • market price effects for energy production;
  • the value of its delivery, generation capacity, transmission capacity and transmission and distribution line losses; and
  • the societal value of the reduced environmental impacts of the energy.
The also Act requires the Commission's report to include a summary of options for increasing investment in or deployment of distributed solar energy generation, which may include recommendations for what Maine should do.

The Commission's investigation is ongoing.  On October 23, 2014, the Commission released a draft of its consultants' initial report, "Maine Distributed Solar Valuation Methodology."  That document is designed as a draft of the methodology to be used in the valuation phase, offered for public review and comment.

The Commission will accept written comments on the draft report until November 12, 2014.  In addition, the Commission and its consultant, Clean Power Research, will hold a work session on the Draft Methodology on October 30, 2014.

Following the first phase to establish the valuation methodology, the Commission and its consultants will conduct a second phase in which the methodology will be applied to Maine to calculate the value of distributed solar generation.  The Commission's work will be summarized in its report to the legislative energy committee, a draft of which the Commission plans to release in January 2015.

North America's largest battery energy storage online

Wednesday, October 29, 2014

A California public utility has brought the largest battery energy storage in North America online.  Funded partially by federal stimulus funds, Southern California Edison's Tehachapi Wind Energy Storage Project is designed to demonstrate the effectiveness of large-scale battery storage systems.

Southern California Edison Company is the largest electricity supply company in Southern California.  As part of the U.S. Department of Energy's implementation of the American Recovery and Reinvestment Act of 2009, the utility won funding to develop a major battery energy storage system (or BESS).  The Tehachapi Wind Energy Storage project consists of an array of lithium-ion batteries capable of storing 32 megawatt-hours, deliverable as an 8 megawatt stream of energy for 4 hours.  The LG Chem batteries rely on the same lithium-ion cells installed in battery packs for General Motors’ Chevrolet Volt electric vehicle, and feature 608,832 individual battery cells arrayed in 10,872 battery modules and 604 battery racks.  Along with two 4MW/4.5MVA smart inverters, the project will be housed in a 6,300 square foot facility sited at SCE's existing Monolith substation.

Of the project's $49,956,528 total budget, half will be paid for by SCE, while federal funds will cover $24,978,264.  In return, the project will examine whether and how the battery energy storage system improves grid performance and helps integrate wind and other large-scale variable energy resourced generation.  Project performance will be measured by 13 specific operational uses, most of which either shift other generation resources to meet peak load and other electricity system needs with stored electricity, or resolve grid stability and capacity concerns that result from the interconnection of variable energy resources.  These uses include: providing voltage support and grid stabilization; decreasing transmission losses; diminishing congestion; increasing system reliability; deferring transmission investment; optimizing renewable-related transmission; providing system capacity and resources adequacy; integrating renewable energy (smoothing); shifting wind generation output; frequency regulation; spin/non-spin replacement reserves; ramp management; and energy price arbitrage.  In addition, the project will demonstrate how lithium-ion battery storage can provide nearly instantaneous back-up capacity, minimizing the need for fossil fuel-powered back-up generation.

Between technological advances and a series of recent policy decisions, battery energy storage could be poised for rapid growth.  For example, in 2011 the Federal Energy Regulatory Commission issued Order No. 755, requiring the grid operators in organized markets to compensate battery energy storage systems and other fast-ramping frequency regulation resources based on the actual service they provide.  Last year's Order No. 784 required public utilities to take into account the speed and accuracy of regulation resources such as batteries.  Meanwhile, batteries are hoped to help balance into the grid large amounts of energy from intermittent renewable resources such as solar and wind projects.

After two years, the Tehachapi Wind Energy Storage Project will have completed its initial demonstration run.  Will the project lead to greater deployment of battery energy storage systems in the U.S.?

Constitution Pipeline environmental impact statement

Monday, October 27, 2014

A 124-mile natural gas transmission pipeline proposed from Pennsylvania to New York has received its final environmental impact statement from federal regulators, finding that while the project would cause some adverse environmental impacts but that mitigation would reduce them to less-than-significant levels.

The proposed Constitution Pipeline is designed connect natural gas supplies in northern Pennsylvania with major northeastern markets.  Proposed by Constitution Pipeline Company, LLC, a group whose investors include WilliamsCabot Oil & Gas, Piedmont Natural Gas, and WGL Holdings, the 30-inch underground pipeline would have a design capacity of 650,000 dekatherms of natural gas per day.  Constitution has pitched the project as a response to natural gas market demands in the New York and the New England areas, and interest from natural gas shippers that require transportation capacity from Susquehanna County, Pennsylvania to the existing Tennessee Gas Pipeline Company LLC (TGP) and Iroquois systems in Schoharie County, New York.

Developing an interstate natural gas pipeline requires a series of federal, state, and local approvals.  Under the federal Natural Gas Act, interstate pipelines must obtain a Certificate of Public Convenience and Necessity from the Federal Energy Regulatory Commission prior to construction.  Constitution started the pre-filing process in April 2012, and filed its certificate application under Section 7(c) of the Natural Gas Act with the FERC on June 13, 2013.

Under the National Environmental Policy Act, federal agencies must analyze and document the environmental effects of proposed federal actions such as issuing a certificate of public convenience and necessity for an interstate pipeline.  For the Constitution Pipeline and its associated Wright Interconnect compressor transfer station, FERC staff evaluated the projects' impacts on natural resources including geology, soils, groundwater, surface water, wetlands, vegetation, wildlife, fisheries, special status species, land use, visual resources, socioeconomics, cultural resources, air quality, noise, and safety.  Staff considered the projects' cumulative impacts along with other past, present, and reasonably foreseeable actions in the projects’ area.  Staff also evaluated over 400 alternatives to the projects, including the "no-action" alternative, system alternatives, major and minor route alternatives, and minor route variations.  In a collaborative effort, FERC staff also collected input from cooperating agencies including the U.S. Environmental Protection Agency, the U.S. Army Corps of Engineers, the Federal Highway Administration, and the New York State Department of Agriculture and Markets. 

FERC staff issued their Final Environmental Impact Statement, or EIS, for the Constitution Pipeline and Wright Interconnect projects on October 24, 2014.  In that document, staff concluded that construction and operation of the Constitution Pipeline and the associated Wright Interconnect would result in some adverse environmental impacts, but these impacts would be reduced to less-than-significant levels with the implementation of mitigation measures proposed by the company and additional measures proposed by FERC.  These mitigation measures include implementing plans for upland erosion control, revegetation, and maintenance plan, protecting wetlands and waterbodies, spill plans for oil and hazardous materials, an organic farm protection plan, and a karst mitigation plan. FERC staff also proposed an environmental inspection and mitigation monitoring program to ensure compliance with all mitigation measures that become conditions of the FERC authorizations and other approvals.

For the Constitution Pipeline project, the EIS represents a relatively favorable recommendation by FERC staff to the Commissioners.  The ultimate decision whether FERC will issue the project a certificate rests solely with the Commissioners themselves, but regulators typically rely heavily on their technical staff's evaluation of environmental impacts.  Likewise, while FERC's final EIS is not necessarily binding on cooperating agencies, they may adopt it if it satisfies their own statutory mandates for environmental reviews.

While the applicants had initially proposed to start construction in 2014, FERC staff acknowledged that "the proposed dates for the start of construction are no longer feasible."  Constitution now proposes to start construction in February of 2015 and continue through the end of 2015, pending receipt of all applicable federal authorizations.  The Federal Energy Regulatory Commission may rule on the projects' certificate applications as early as late November this year.

Canada's Energy East Pipeline Project

Friday, October 24, 2014

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, Qu├ębec 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.

FERC revokes hydro license over fish passage

Thursday, October 23, 2014

What happens when the owner of a federally licensed hydroelectric project fails to build the fish passage facilities required by its license?  In the recent case of the East Juliette Hydroelectric Project in Georgia, the Federal Energy Regulatory Commission revoked the project's license, ending the owner's right to operate its generating equipment.

The East Juliette Hydroelectric Project is (or was) based around the East Juliette Dam on the Ocmulgee River, a tributary to the Altamaha River.  Built in 1921, the dam is hundreds of miles inland from tidewater -- but nevertheless represents the first passage barrier that anadromous fish, including American shad, encounter on their migrations upstream from the Atlantic Ocean to the Ocmulgee River.  State and federal fisheries agencies have identified restoring access to historical spawning habitat for American shad as one of their highest priorities for the region.

Since 1995, the East Juliette Hydroelectric Project has been owned by Eastern Hydroelectric Corporation.  The project facilities include a 20-foot-high, 1,230-foot-long concrete gravity dam that creates a 78-acre reservoir with a storage capacity of 418 acre-feet, and two powerhouses with a total installed capacity of 687 kW.

In 2002, the Federal Energy Regulatory Commission amended the project's license to authorize the construction of a new powerhouse and 1,200 kW generating unit.  As part of that amendment, the FERC added language to the project's license requiring the licensee to install new fish passage facilities at the East Juliette Dam.  Similar conditions were imposed by the Georgia Department of Natural Resources as part of its water quality certification for the amendment.

According to the recent FERC order, while the licensee proposed a plan to construct fish lift at the dam, it ultimately did not follow through with its plan.  At several points over the past 5 years, FERC staff licensee directed the licensee to comply or else face civil penalties, an order to cease operation of the project, or revocation of the license pursuant to section 31 of the Federal Power Act.

Under section 31(b) of the Federal Power Act, after notice and an opportunity for an evidentiary hearing, the FERC may issue an order revoking a license, where the licensee is found have knowingly violated a final order after having been given reasonable time to comply fully with that order.  In Eastern Hydro's case, FERC found that despite 12 years of intensive efforts by its own staff and other agencies, "these efforts have met with steady resistance from the licensee."

Ultimately, the FERC found that Eastern Hydro knowingly violated its compliance order and that it was given a reasonable time to comply with the order before FERC commenced the license revocation proceeding. As a result, FERC revoked Eastern Hydro’s license for the East Juliette Project.

While environmental conservation groups asked FERC to require the licensee to remove all project facilities that it owns, FERC declined to do so.  Instead, the FERC order requires that Eastern Hydro disable all of the project’s generating equipment to prevent operation of the project in violation of section 23(b)(1) of the Federal Power Act.  Following revocation of the license, the FERC's jurisdiction will end, and authority over the site will pass to the State of Georgia’s dam regulatory authorities.

The East Juliette case illustrates some of the most severe consequences of failure to comply with FERC hydropower licenses.  Without a license, the project cannot generate electricity, thus depriving the project of much of its value.

FERC settles 3rd Southwest blackout case

Wednesday, October 22, 2014

A California public utility has settled claims by federal electricity regulators related to the September 8, 2011, blackout in the southwestern United States.  Following an investigation by the Federal Energy Regulatory Commission (FERC) and electric reliability organization North American Electric Reliability Corporation (NERC), Southern California Edison Company has agreed to pay a $650,000 civil penalty and undertake additional compliance actions.

According to previous investigative reports, the 2011 blackout started when a 500-kilovolt transmission line owned by Arizona Public Service Company tripped out of service, causing cascading power outages through automatic load shedding as other equipment quickly overloaded.  In the end, the outage affected over 5 million customers, shedding 7,835 megawatts of peak demand and over 30,000 megawatt-hours of energy.

Following the blackouts, both FERC and NERC launched investigations into what had happened.  As a federal agency, FERC has regulatory authority over the reliability of the electric bulk power systemNERC is a not-for-profit international regulatory authority whose mission is to ensure the reliability of the bulk power system in North America, and has been designated by FERC as the nation's electric reliability organization.

In July, FERC announced a $3.25 million settlement with Arizona Public Service.  In August, FERC announced a $12 million settlement with California's Imperial Irrigation District.

Today, FERC announced that it has approved a stipulation and consent agreement between FERC’s Office of Enforcement, NERC, and Southern California Edison Company.  Through a joint investigation, FERC Office of Enforcement staff and NERC determined that the utility violated the Protection and Control group of NERC's Reliability Standards.  In particular, the investigation found that Southern California Edison failed to adequately coordinate its intertie separation scheme at the San Onofre nuclear generating station switchyard with certain other protection systems.  Enforcement staff and NERC found this violation to be a serious deficiency that undermined reliable operation of the Bulk Power System.

Through the settlement, Southern California Edison will pay a civil penalty of $650,000.  Of this penalty, $125,000 will be paid to the U.S. Treasury, $125,000 will be paid to NERC, and $400,000 will be invested in additional reliability enhancement measures.

With Southern California Edison's case resolved, all three of the vertically integrated utilities known to be implicated by FERC's investigation have now settled their alleged violations by agreeing to pay penalties.  Will further penalties be forthcoming?  Will the penalties and ordered reliability measures keep the lights on the next time the grid is stressed?

Polar vortex caused energy price spikes, says FERC staff

Monday, October 20, 2014

Why did energy prices rise during last winter's extremely cold "polar vortex" weather?  A recent report by federal regulators suggests that inadequate infrastructure is largely to blame, while finding no evidence of widespread or sustained market manipulation.

A recent winter in New England: cold ocean, cold snow.  Must high energy prices follow?

The 2013 - 2014 winter season brought prolonged and unusually cold weather events in much of the United States.  While the nation's major electric grids were generally able to maintain reliable operation, prices for natural gas and electricity spiked to unprecedented levels.  Bottlenecks on interstate natural gas pipelines limited the amount of gas flowing into regions like the Northeast, while demand for gas for heating and electric power generation increased beyond the constrained pipelines' capacity.  This imbalance of supply and demand for gas led to extremely high prices for gas as well as for electricity, because the price of natural gas often sets the price for power.  Compounding the problem, some generators could not buy enough gas to operate, while others experienced outages due to equipment failure and frozen coal piles.  In some regions, generators amounting to 30 percent of electric load faced forced outages.

As an immediate response, the Federal Energy Regulatory Commission took actions including changes to rules in the PJM, New York ISO and California ISO electricity markets, the Commission's first use of its emergency powers under the Interstate Commerce Act to direct Enterprise TE Products Pipeline to temporarily provide priority treatment to certain propane shipments, and approving a Winter Reliability Program in the ISO New England region.

According to a recently released report by the staff of the Federal Energy Regulatory Commission, the FERC Office of Enforcement also launched investigations into whether market participant behavior influenced regulated energy prices.  In addition to the Commission's enforcement arm's regular surveillance of natural gas and electric markets for market manipulation and other improper conduct, the past winter's extreme price spikes prompted a closer look by the Office of Enforcement to determine if market manipulation was behind the historically high natural gas and electric prices.

On October 16, FERC’s enforcement staff reported that it found "no evidence of widespread or sustained market manipulation."  Enforcement staff said it reached its conclusions after an extensive review and data analysis related to gas trading behavior, allegations received through the FERC hotline, generator offer behavior and outage behavior.

However, enforcement staff reported that three non-public investigations remain pending.  At stake is whether any market participant was involved with the formation of a single monthly natural gas index to benefit its financial derivative positions, as well as whether certain generators improperly took advantage of constrained conditions in the electric markets by bidding in a way that increased their uplift payments.

Expect these enforcement investigations to continue, either to an informal resolution or a public enforcement process.  With former Office of Enforcement head Norman Bay as the newest FERC Commissioner, FERC's enforcement arm appears to be growing in influence.  Meanwhile, the coming winter may yet again test the nation's electricity and natural gas infrastructure.  What will the 2014 - 2015 winter hold, in terms of energy reliability, pricing, and enforcement actions?

Solar bonds: SolarCity launches first US public debt offering

Wednesday, October 15, 2014

Could publicly offered solar bonds play a significant role in financing solar photovoltaic projects?

Solar energy company SolarCity Corporation appears to think so, as this morning it filed a registration statement with the U.S. Securities and Exchange Commission to issue up to $200 million in solar bonds.  SolarCity describes the move as "the nation’s first registered public offering of solar bonds."  What does SolarCity's solar bond offering mean for solar energy?

Solar panels on a residential rooftop in Massachusetts.

By some metrics, SolarCity is the largest developer of residential solar photovoltaic projects in the U.S.  The company says it is currently providing more than one out of every three new solar power systems in the U.S., and notes that it "installed more residential solar in the second quarter of 2014 than its next 50 competitors combined."  While SolarCity develops projects under several financial models, its typically installs rooftop solar panels at its customers' sites with no upfront costs to the customer, who then pays the company every month for leasing the facilities or for the electricity it uses.  These long-term contracts create more stable ongoing revenues for SolarCity compared to those experienced by developers of turnkey projects who may end their relationship after the project is commissioned.

SolarCity's model has proved attractive to capital, as it has been involved with financing the installation of approximately $5 billion in renewable energy assets.  Much of the capital SolarCity needs to develop these projects has come from investments from major banks and corporations including US Bancorp and Google Inc., as well as individuals owning shares of the company's stock (traded as SCTY).

SolarCity has also turned to debt offerings, making three private placements of solar bonds in the last year.  Generally speaking, SolarCity will pay returns on the bonds using income generated from customers' monthly payments.  Because this income stream is both relatively stable and predictable, it should enable repayment of the bonds plus a steady yield.

But no company has previously publicly offered solar bonds of this type in the U.S.  SolarCity thus views its publicly offered solar bonding model as unique, in that it gives individual investors access to new investment opportunities -- and in turn, it may give SolarCity access to a whole lot more money -- up to $200 million in this round, with the prospect of more to come.

Under SolarCity's new offering, investors will be able to purchase solar bonds for as little as $1,000, with maturities ranging from one year to seven years and interest rates of up to 4 percent.  The relatively short maturity of these bonds, compared to those previously offered to institutional investors, helps reduce the risk that during the bonds' lives utility rates will change in a way that hurts their economics.

The company notes that solar bonds will be available to all U.S. investors who are at least 18 years old and meet SolarCity’s eligibility requirements, with no fees for purchase.  Indeed, the relatively low $1,000 minimum investment for this solar bond offering highlights SolarCity's strategy of targeting the millions of small or "retail" investors.  To facilitate these individual investors' access to the bonds, the company launched a new online investment site (solarbonds.solarcity.com).

How will the new solar bond offering affect SolarCity and the pace of solar development in the US?  With a market capitalization of $4.2 billion, SolarCity is relatively large compared to the $200 million that it may raise pursuant to the current public bond offering.  Nevertheless, individual investors' appetite for opportunities to participate in solar and other renewable energy projects may be significant enough that more bond offerings will follow on the heels of this one.  As the Brookings-Rockefeller Project on State and Metropolitan Innovation found in an April 2014 report, Clean Energy FinanceThrough the Bond Market:A New Option for Progress, "Bond finance holds tremendous potential for clean energy investment, at levels in the tens of billions of dollars in the next several years."  If SolarCity is indeed successful in attractive individual bond investors, other solar developers like First Solar, Inc. and Sunrun may soon follow suit with solar bond offerings of their own.

USDA awards $68 million for energy projects

Thursday, October 9, 2014

The U.S. Department of Agriculture has announced $68 million in grants and loan guarantees for renewable energy and energy efficiency projects.  The latest round of awards under the agency's Rural Development arm's Rural Energy for America Program will support 540 projects at farm and rural business sites across the country.

Since its creation in the 2008 Farm Bill, REAP has supported more than 8,800 renewable energy and energy efficiency projects nationwide with over $276 million in grants and $268 million in loan guarantees to agricultural producers and rural small business owners.  Eligible agricultural producers and rural small businesses may use REAP funds to make energy efficiency improvements or install renewable energy systems including solar, wind, biomass and anaerobic digesters, small hydroelectric, ocean energy, hydrogen, and geothermal projects.  (For looks at previous REAP winners, check out these posts from 2011 and 2013.)

In this year's REAP funding round, USDA awarded about $68 million in investment support.  Of this, $12,376,548 will come in the form of grants, while $56,449,244 will come as loan guarantees.  While most grants are under $100,000 per project (with some below $10,000), there were some larger grant awards: for example, a biomass anaerobic digester in California won $290,000, an off-grid solar project in Hawaii won $123,338, and a direct use geothermal heat pump in Oklahoma won $133,250. Of the loan guarantees, $55.3 million will go to support 22 solar photovoltaic projects in North Carolina, mostly ranging between 2 megawatts and 5 megawatts per project. 

In each case, funding is contingent upon the recipients meeting the terms of the loan or grant agreement. USDA's hope is that these grants and loan guarantees will enable American agricultural producers and rural small business owners to reduce their energy costs.

REAP was reauthorized by the 2014 Farm Bill, so expect USDA Rural Development to solicit more REAP projects later this year.  While not all sites may qualify, USDA's definition of eligibility is more broad than many assume.  The Preti Flaherty team helps our clients understand how to benefit from REAP funding and other incentive programs for renewable energy and energy efficiency.  Contact Todd Griset to learn more.

ISO New England's Winter Reliability Program 2014-2015

Wednesday, October 8, 2014

Keeping the lights on is what electric grid operators do around the clock – but challenges in New England are leading its grid operator to prepare for a winter when the availability of affordable electricity may be challenged.  In preparation, ISO New England, Inc. has received federal approval for a new Winter Reliability Program for the 2014-2015 winter season.

Winter is coming.
ISO New England is the federally-designated regional transmission organization for almost all of New England.  In this role, it is responsible for planning and operating electricity markets to balance supply and demand in real time.   

The grid operator first turned to a Winter Reliability Program in 2013.  ISO New England projected that a limited supply of natural gas and the retirements of several major generating plants would lead to a shortage of about 2 million megawatt-hours of energy during the winter months.  To insure against this gap, the grid operator held a competitive process to procure up to 2.4 million megawatt-hours of energy for the winter season, from a combination of oil-fired generators, dual-fuel generators, and demand response assets.  In exchange for their commitment to provide power when called upon, the selected generators and demand response assets received payments regardless of whether they were actually needed.

In ISO-NE's eyes, the 2013-2014 Winter Reliability Program proved essential in maintaining reliability during the “polar vortex” and other unusually cold conditions.  After adjusting for resource unavailability, the final cost of the 2013/2014 program was approximately $66 million, which came in below the original estimates of about $75 million.

While last year’s program was intended to be a one-time solution to bridge a reliability gap, this summer ISO-NE and regional stakeholder body NEPOOL identified additional challenges for the coming winter.  Specifically, more severe pipeline constraints, difficulty replenishing oil inventories, and large-scale generator retirements continue to threaten the coming winter's reliability and expose consumers to the risk of price spikes.

As a result, ISO-NE asked the Federal Energy Regulatory Commission to approve another program to mitigate reliability concerns for the 2014-2015 winter.  The new program, which the FERC accepted last month, combines features of last year’s program with further modifications.  For example, the new demand-response component is much the same as in last year’s program, while permanent rules related to auditing dual-fuel generators and the partial elimination of higher-cost fuel requirements are based on similar features in last winter’s program.

On the other hand, the new program has been modified as a result of several market changes that will be in effect prior to winter 2014/2015 as well as the FERC's clarification of what generators must do to procure adequate fuel for their expected run times.  The new program also adds a liquefied natural gas (LNG) component to improve fuel neutrality, and changes the basis for compensation from upfront inventory to actual unused inventory at the end of the winter.  While participants in last year's program were paid on an as-bid basis, the new program provides compensation for the fuel inventory and demand response programs based on a set rate of $18 per barrel.  This $18 price is designed to represent the carrying costs, price risk, availability cost and liquidity risk of the last resource needed to meet a cumulative inventory of 3.5 million barrels of oil.

The program also includes incentives for commissioning duel-fuel capacity: the ability to run on either oil or gas. Generators that have not operated on oil since at least December 1, 2011, and that demonstrate a plan for commissioning, or recommissioning a mothballed dual-fuel unit, by December 1, 2016, will be eligible for compensation to offset some of the associated costs.

The new program is moving forward.  On September 9, 2014, the FERC issued an order accepting the region’s proposed 2014/2015 Winter Reliability Program.  In the order, FERC requires ISO-NE to initiate a stakeholder process by January 1, 2015, to develop a proposal to address reliability concerns for the 2015/2016 winter and future winters, as necessary, to schedule meetings and submit progress reports, and to include certain analysis and recommendations in its Annual Markets Report.

For the proposed 2014/2015 program, the Analysis Group estimated costs for the separate components: the maximum cost of the demand response component would be about $2.4 million; the cost of the unused oil inventory and LNG contract volume components would be based on how much fuel remains unused, and assuming, at the high end, that 100% of the targeted amount of fuel is unused, the estimated cost would be $82.6 million; and the maximum cost for the dual-fuel commissioning program is estimated to be $12.9 million for units that commission by December 1, 2015.  The dual-fuel auditing provisions are estimated to cost a maximum, annually, of $7 million.

Consistent with the Commission’s order on the first winter program, the costs will be allocated to real-time load obligation, which is paid by load-serving entities, rather than to regional network load, which is paid by transmission owners.

Requests to Participate in the Oil Program, LNG Program, or Demand Response Program were due to ISO New England Customer Service by October 1, 2014. Dual Fuel Commissioning Requests are due by December 1, 2014