FERC adopts grid physical security reliability standard

As expected, federal regulators have approved a new physical security standard for the high-voltage electricity grid.

On November 20, the Federal Energy Regulatory Commission approved Reliability Standard CIP-014-1 (Physical Security).  The standard, proposed by Commission-certified Electric Reliability Organization North American Electric Reliability Corporation (NERC), is designed to enhance physical security measures for the most critical parts of the nation's "bulk-power system," the high-voltage backbone of the nation's electric grid.

In the wake of a 2013 California incident in which a major substation was damaged by gunfire, in March 2014 the FERC directed NERC to prepare a draft standard to protect the physical security of the grid.  In response, NERC proposed a standard requiring owners and operators of transmission facilities toidentify and protect critical transmission stations, substations, and control centers whose damage through physical attack could result in spreading outages or other reliability problems.

On November 20, 2014, the FERC issued its Order No. 802 approving the physical grid reliability standards.  In a press release, the Commission described Order No. 802 as enhancing the physical security for the most-critical Bulk-Power System facilities and reducing the overall vulnerability of the grid to attacks.

As described by the FERC in Order No. 802, Reliability Standard CIP-014-1 has six requirements:

• Requirement R1 requires applicable transmission owners to perform risk assessments on a periodic basis to identify their transmission stations and substations that, if rendered inoperable or damaged, could result in widespread instability, uncontrolled separation , or cascading within an Interconnection. Requirement R1 also requires transmission owners to identify the primary control center that operationally controls each of the identified transmission stations or substations.
• Requirement R2 requires that each applicable transmission owner have an unaffiliated third party with appropriate experience verify the risk assessment performed under Requirement R1. Requirement R2 states that the transmission owner must either modify its identification of facilities consistent with the verifier’s recomme ndation or document the technical basis for not doing so. In addition, Requirement R2 requires each transmission o wner to implement procedures for protecting sensitive or confidential info rmation made available to third - party verifier s or developed under the Reliability Standard from public disclosure.
• Requirement R3 requires the transmission owner to notify a transmission operator that operationally controls a primary control center identified under Requirement R1 of such identification to ensure that the transmission operator has notice of the identification so that it may timely fulfill its obligations under Requirements R4 and R5 to protect the primary control center.
• Requirement R4 requires each applicable transmission owner and transmission operator to conduct an evaluation of the potential threats and vulnera bilities of a physical attack on each of its respective transmission stations, transmission substations, and primary control centers identified as critical in Requirement R1.
• Requirement R5 requires each transmission owner and transmission operator to develop and implement documented physical security plans that cover each of their respective transmission stations, transmission substations, and primary control centers identified as critical in Requirement R1.
• Requirement R6 requires that each transmission owner and transmission operator subject to Requirements R4 and R5 have an unaffiliated third party with appropriate experience review its Requirement R4 evaluation and Requirement R5 security plan. Requirement R6 states that the transmission owner or transmission operator must either modify its evaluation and security plan consistent with the recommendation, if any, of the reviewer or document its reasons for not doing so. Requirement R6 also requires each transmission owner to implement procedures for protecting sensitive or confidential information made available to third-party reviewers or developed under the Reliability Standard from public disclosure

While the Commission adopted the standard, it directed NERC to submit an informational filing within 2 years that addresses whether the physical security reliability standard should be applicable to additional control centers.  It also gave NERC 6 months to propose modifications to clarify the use of the phrase "widespread" instability in Requirement R1.

The FERC's rule will become effective 60 days after its publication in the Federal Register.

MA considers expanding net metering for small hydro

Massachusetts energy regulators are investigating whether to allow more small hydroelectric projects to benefit from a policy known as "net metering."
 
Net metering allows electric customers with their own small generators to sell the power they produce to the utility grid, offsetting the customer's bill for power purchased from the grid.  This effectively incentivizes electricity consumers to develop customer-sited generation that can generate power at a lower cost than grid-delivered power.  Many states have adopted net metering programs to encourage renewable and other distributed generation.  Most states' programs are restricted by size (a project's maximum generating capacity, or the program's total enrolled capacity) and by technology (e.g. solar photovoltaics usually qualify, but coal usually doesn't).

Massachusetts' current version of net metering allows customers to qualify by installing any type of generating facility, including a hydroelectric facility, as long as the facility is smaller than 60 kilowatts.  Size limits are larger for certain projects powered by wind, solar photovoltaics, or anaerobic digestion, as well as for farm-related "Agricultural Net Metering Facilities" -- up to 2 megawatts for most such projects, or 10 MW for some publicly owned facilities.  But under Massachusetts' current rules, hydroelectric facilities that are larger than 60 kW and are not Agricultural Net Metering Facilities are not eligible for net metering.

Whether that restriction makes sense is now the subject of an investigation by the Massachusetts Department of Public Utilities.  The 2014 enactment by the state legislature of An Act Relative to Credit for Thermal Energy Generated with Renewable Fuels, Chapter 251 of the Acts of 2014, directed the Department to study the feasibility, impacts and benefits of allowing customers to net meter electricity generated by micro-hydro and other small hydroelectric facilities.  The Act directed the Department to develop a report based on this analysis, and to submit the report to the legislature by July 1, 2015.

The Massachusetts DPU opened its investigation on October 16, 2014.  In the Department's order opening the investigation, it posed 13 questions to the public.  Topics ranged from the proper definition of "small hydroelectric" to the pros and cons of allowing new or existing small hydroelectric projects to net meter.   Written comments on these questions are due by the close of business on December 5, 2014.  In addition, the DPU held a technical conference on November 7 at which these issues were explored.

What will the Massachusetts Department of Public Utilities find regarding net metering and small hydroelectric projects?  How will the state legislature respond to the DPU's report expected this coming summer?  Will Massachusetts expand net metering opportunities for small hydropower?

Managing a FERC audit

What happens when the Federal Energy Regulatory Commission audits a public utility?

The Federal Energy Regulatory Commission has jurisdiction over interstate transmission of electricity, natural gas, and oil, as well as hydropower projects, liquefied natural gas (LNG) terminals and interstate natural gas pipelines. Under Section 301 of the Federal Power Act (codified at 16 U.S.C. § 825), public utilities and licensees must keep records of their business activities.  By law, the FERC has the right to inspect these records on a confidential basis.

The Commission's Office of Enforcement manages many of the agency's investigations.  Its Division of Audits and Accounting periodically audits public utilities and licensees to evaluate their compliance with the statutes and regulations administered by the Commission.

For example, on November 17, 2014, the Commission issued a letter to public utility Calpine Corporation noting the Division of Audits and Accounting's commencement of an audit.  That letter describes the objectives of the audit as "to evaluate Calpine's compliance with: ( 1) market rules regarding uplift payments from organized markets in which Calpine participates; (2) terms and conditions of its market-based rate authorization tariffs; and (3) Electric Quarterly Report filing requirements under 18 C.F.R. § 35.10b (2014)."  The audit will cover the period from January 1, 2012 through the present.

The letter to Calpine notes several provisions of the Federal Power Act that govern recordkeeping and audits.

• Section 301(b) of the Act requires Calpine to furnish, within reasonable time frames, any information the Commission may require; requires Calpine to grant agents of the Commission free access to its property, accounts, records, and memoranda; and allows Commission staff to keep copies of any accounts, records, or memoranda that pertain to the audit.
• Section 301(c) allows Commission staff to examine the books, accounts, memoranda, and records of any person who controls, directly or indirectly, Calpine, and of any other company controlled by such person, insofar as they relate to transactions with or the business of Calpine.

The audit letter also points to additional recordkeeping and retention requirements found in sections 301, 304, and 311 of the Federal Power Act, 16 U.S.C. §§ 825, 825c, and 825j (2012), and 18 C.F.R. part 125 (2014).  For example, it states that Calpine must preserve and retain, and shall not discard or destroy, any and all existing and future records or communications, including but not limited to electronic documents, emails, instant messages, text messages, and voice recordings, relating to this audit.

What this means for Calpine -- beyond the obvious audit -- is unclear.  The letter notes that Commission staff will contact Calpine soon to explain the audit process and answer any questions.  While many audits find no problems, some audits do lead to further enforcement action, penalties, or refunds.  In the Commission's 2013 Report on Enforcement, it noted that in 2013, staff from the Division of Audits and Accounting conducted 29 financial, compliance, and performance audits of public utilities, natural gas pipelines, and gas storage companies.  These audits resulted in 360 recommendations for corrective action and directed refunds totaling over $15.4 million.

Other public audits recently initiated by the Commission include audits of MidAmerican Energy Holding Company, Dynegy, Inc., and Bangor Hydro Electric Company.

Report: New England electric sector will face gas supply deficit

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

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

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

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

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, 2007.  NYTEC 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

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

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

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 10 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

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

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

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.

• Louisiana LNG Energy, LLC has proposed the Mississippi River LNG Project, to be located in Plaquemines Parish south of the Port of New Orleans.  The project would have an initial capacity of 2 million metric tonnes per annum (MTPA), with a targeted start-up in late 2017.

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

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?