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

Exporting compressed natural gas from the US

Monday, October 6, 2014

In a divided opinion, the Federal Energy Regulatory Commission has found that it does not have jurisdiction over facilities proposed by Emera CNG, LLC to compress natural gas for export to the Bahamas by ship.

Natural gas is an important fuel used globally for electric power generation, heating, and industry.  Throughout most of the U.S., an abundant supply of natural gas means domestic pricing for gas is lower than overseas.  This creates a potentially profitable opportunity to export natural gas from the U.S., if regulatory conditions allow.

Natural gas can be exported by pipeline as a gas, or by truck or ship as either compressed natural gas (CNG) or liquefied natural gas (LNG). Liquefying natural gas enables massive quantities of gas to be transported anywhere in the world, but requires the construction of expensive facilities to liquefy and regasify the fuel.  The federal Natural Gas Act gives the Federal Energy Regulatory Commission jurisdiction over the siting and construction of most LNG facilities in the U.S., and authorizes FERC to issue certificates of public convenience and necessity for LNG facilities engaged in interstate natural gas transportation by pipeline.  For example, Dominion Cove Point LNG, LP recently secured the FERC's approval for its Cove Point LNG export facility.

By comparison, compressing natural gas to high pressures is a relatively lower-cost way to improve the energy density of the fuel and reduce its transportation costs, albeit not to the degree of LNG.  CNG exports are already happening, and may soon increase.

Emera recently proposed to construct a CNG compression and truck-loading facility at the existing Port of Palm Beach in Riviera Beach, Florida, in order to export CNG to the Commonwealth of the Bahamas.  At the site, Emera would draw natural gas from the Riviera Lateral, a pipeline owned and operated by Peninsula Pipeline Company.  Emera would then dehydrate and compress the gas to fill containers that would be loaded onto trucks.  The proposed CNG facility would initially be capable of loading 6 million cubic feet per day (MMcf/d) of CNG, with expansion capabilities up to 25 MMcf/d.  Once loaded onto trucks, Emera will haul the containers to a berth about a quarter mile away at the Port of Palm Beach.  At the port, the containers will be loaded onto a roll-on/roll-off ocean-going carrier and shipped to Freeport, Grand Bahama Island, where the containers would be unloaded, the CNG decompressed and injected into a pipeline for transport to electric generation plants owned and operated by Emera affiliate Grand Bahama Power Company and other customers on Grand Bahama Island.

To reduce regulatory uncertainty, Emera petitioned the Federal Energy Regulatory Commission for a declaratory order that its project will not be subject to the Commission’s jurisdiction under the Natural Gas Act.  Last month, a majority of the FERC Commissioners found that the construction and operation of the CNG facility described by Emera would not be subject to FERC's authority over natural gas exports under the Natural Gas Act.  In particular, the majority opinion held that Emera’s facilities to compress and load CNG onto trucks are not jurisdictional export facilities.

In reaching this conclusion, the majority found that the proposed CNG facilities were unlike the border-crossing pipelines and coastal LNG terminals that the Commission traditionally has regulated under section 3 as import/export facilities, and more like existing, unregulated facilities that deliver LNG into trucks which are subsequently driven across the border into Canada or Mexico.  Indeed, the opinion cites the example of Xpress Natural Gas, which has a CNG plant in Maine that receives gas from an interstate pipeline and loads CNG containers onto trucks for delivery to customers in Canada and in New England.  The Commission does not regulate the CNG facility under either section 3 or 7, nor does it exercise jurisdiction over the trucks’ passage across the border under section 3.

The majority opinion similarly found that because Emera said that all of the natural gas to be compressed at Emera’s planned facility will be exported in foreign commerce to the Commonwealth of the Bahamas, the Commission’s section 7 jurisdiction over transportation and sales of gas for resale in interstate commerce would not be implicated by Emera’s proposal.

Notably, new Commissioner Norman Bay dissented from the majority opinion.  Noting language in section 3 of the Natural Gas Act giving FERC jurisdiction over natural gas exports, Commissioner Bay's dissent describes the majority’s argument as that because the CNG will leave Emera’s facility by truck and travel a quarter of mile before being loaded onto ocean-going carriers for export – rather than by a pipeline running across a border or to a tanker – the facility is not an “export facility” under section 3 of the Natural Gas Act. In Commissioner Bay's words, "It cannot be that the Commission’s jurisdiction turns on this 440-yard truck journey."

With FERC regulation under the Natural Gas Act behind it, Emera will still need other approvals to export CNG; for example, Emera has filed an application with the U.S. Department of Energy's Office of Fossil Energy for authorization under Section 3 of the Natural Gas Act for export of natural gas.

What role will CNG exports play in the U.S.'s energy future?

Washington tidal energy project cancelled

Thursday, October 2, 2014

A tidal energy project proposed off the Washington coast will be scrapped due to cost overruns, according to the project developer.

Public Utility District No. 1 of Snohomish County's proposed Admiralty Inlet Pilot Tidal Project was envisioned as a temporary, experimental project to evaluate the commercial viability of tidal energy development in Puget Sound.  The 600-kilowatt hydrokinetic project would have generated electricity from the force of water moving through turbines mounted in tidal currents.  Earlier this year, the project won a pilot license from the Federal Energy Regulatory Commission, making it among the first tidal projects to qualify for the Commission's pilot licensure program.

But the estimated costs of the project were significant relative to its projected energy output.  Since it was first proposed in 2006, the Public Utility District estimated that the project would cost $20 million to build.  Based on these numbers, the Commission estimated that the levelized annual cost of operating the project would be about $1,848,294.  Dividing this by the project's expected production of energy, the power could cost $7,574.98 per megawatt-hour of energy generated -- an amount over 250 times higher than the estimated $30/MWh cost of alternative power.

Nevertheless, the PUD had designed the project's finances to avoid the need for ratepayer financing.  Rather, the project relied on funding from federal grants and in-kind contributions from project partners, as well as some money from the sale of excess renewable energy credits from the District's wind power projects.  To date, the District has invested about $3.5 million in the effort, over the past 8 years.

With the FERC license in hand, the District moved forward to solicit bids for project engineering and construction.  When those bids came in, the District realized the project would likely cost closer to $37 million, or $17 million more than previously expected.  According to a September 30 announcement by the Public Utility District, the District tried to seek more funding for the project from the U.S. Department of Energy and other project partners, but did not succeed.  As a result, the District has announced that it will not move forward with the project.

While the District is no longer actively pursuing the Admiralty Inlet Pilot Tidal Project, some other developer may try to pick up where the District left off.  Indeed, the District's announcement notes that the project "remains worthwhile to pursue on behalf of the nation to further the potential development of marine renewable energy."  Will another developer seek to advance the Admiralty Inlet Pilot Tidal Project?  Will other tidal current and marine hydrokinetic projects be developed given the challenges of ocean energy project economics?

Feds approve Quebec-to-NY power line

Wednesday, October 1, 2014

A proposed electric transmission line connecting Quebec to New York will receive a key federal approval, according to the U.S. Department of Energy.  The Energy Department's decision to issue a Presidential permit to Champlain Hudson Power Express, Inc. focuses attention on the nation's international trade in electricity, and may suggest increased reliance on power imports.

Pursuant to two Executive Orders -- EO 10485 (September 9, 1953), as amended by EO 12038 (February 7, 1978) -- no electricity transmission facilities may be constructed, operated, maintained, or connected at the U.S. border without first obtaining a Presidential permit from the Department of Energy.  In 2010, Champlain Hudson Power Express, Inc. applied to DOE for a Presidential permit to construct, operate, maintain, and connect a 1,000-megawatt (MW), high-voltage direct current (HVDC) merchant electric power transmission system across the U.S./Canada border.

As currently envisioned, the Champlain Hudson Power Express project would cross the U.S./Canada border near the town of Champlain in northeastern New York State.  From there, the line would extend southward about 336 miles to the Consolidated Edison Company of New York, Inc. Rainey substation in Queens, New York.  Notably, the aquatic portions of the transmission line would primarily be buried in sediments of Lake Champlain and the Hudson, Harlem, and East rivers, while the terrestrial portions of the line would be buried within existing roadway and railroad rights-of-way.

The Department may issue or amend a permit if it determines that the permit is in the public interest and after obtaining favorable recommendations from the U.S. Departments of State and Defense.  In making this determination, DOE considers factors including the proposed project's potential impacts on the environment and electricity reliability.

In the case of the Champlain Hudson Power Express, the Department of Energy's record of decision states that its decision to grant the Presidential permit was based on "consideration of the potential environmental impacts, impacts on the reliability of the U.S. electric power supply system under normal and contingency conditions, and the favorable recommendations of the U.S. Departments of State and Defense."  With the Presidential permit in hand, the project developer will be one step closer to success -- but additional steps remain, including both securing regulatory approvals and completing the commercial arrangements necessary for project development.

If the project is built, New York consumers may soon have increased access to electricity generated from Canadian hydropower and other resources across their northern border.  Will the U.S. soon import more power from Canada?  If so, how much, and at what cost?  How will market forces and regulatory agendas combine to affect Canadian exports of electricity to the U.S.?

FERC approves Maryland LNG project

Tuesday, September 30, 2014

A proposed Maryland natural gas liquefaction facility won a key federal approval yesterday, as the Federal Energy Regulatory Commission authorized Dominion Cove Point LNG, LP to build the Cove Point Liquefaction Project in Calvert County, Maryland, and related facilities at an existing compressor station and at metering and regulating sites in Virginia.

Natural gas is an important fuel used globally for electric power generation and heating.  While pipelines offer the most efficient way to transport large volumes of natural gas, liquefied natural gas or LNG can more easily be transported by ship to distant markets.  As US natural gas production has increased in recent years, so too has interest in building facilities to liquefy gas for export or other use.

Under Section 3 of the Natural Gas Act, the Federal Energy Regulatory Commission or FERC authorizes the siting and construction of onshore and near-shore LNG import or export facilities. Section 7 of the Natural Gas Act authorizes FERC to issue certificates of public convenience and necessity for LNG facilities engaged in interstate natural gas transportation by pipeline.

On April 1, 2013, Dominion applied to the FERC for approval under Section 3 of the Natural Gas Act to site, construct, and operate the Cove Point Liquefaction Project for the liquefaction and export of domestically-produced natural gas at Dominion’s existing LNG import terminal in Calvert County, Maryland.  Dominion also requested authority under section 7(c) of the Natural Gas Act to construct and operate facilities at its existing compressor station and metering and regulating sites in Virginia.  Collectively, the project will enable Dominion to transport up to 860,000 dekatherms per day of natural gas form existing pipeline interconnects near the west end of the Cove Point Pipeline to the Cove Point terminal for the export of up to 5.75 metric tons of liquefied natural gas per year.

Dominion's requests triggered a case that stretched for over two years of consideration.  During this time, the FERC heard from more than 140 speakers at three public meetings related to an assessment of the project's environmental impacts, and received more than 650 comments from the public and federal, state and local agencies on the application.  In the end, the FERC determined that Dominion’s proposal, as approved with 79 specific conditions required by the Commission’sauthorization, will minimize potential adverse impacts on landowners and the environment.

According to the FERC, Dominion proposes to complete construction of the liquefaction project so that facilities may start service in June 2017.  Notably, the U.S. Department of Energy has already approved Dominion Cove Point’s export of gas to both Free Trade Agreement and non-Free Trade Agreement countries.

The same economic forces motivating the Dominion project support other proposed LNG export projects.  Indeed, FERC has approved three other LNG export projects, all in the Gulf of Mexico -- the Sabine Pass Liquefaction Project, the Freeport LNG Project, and the Cameron LNG Project -- and 14 more LNG export proposals remain pending.

FERC Order 676-H adopts NAESB standards

Monday, September 22, 2014

Last week the Federal Energy Regulatory Commission issued Order No. 676-H, adopting and incorporating into its regulations most of the latest version of a set public utility business practice standards and communications protocols developed by the North American Energy Standards Board (NAESB).  While most of the NAESB standards will now become mandatory and enforceable, to enable smart grid innovation the Commission posted NAESB's five Smart Grid standards as non-binding guidance.

Industry standards enable cooperation and communication, and can lead to more efficient and competitive markets.  Formally known as Version 003 of the Standards for Business Practices and Communication Protocols for Public Utilities adopted by NAESB's Wholesale Electric Quadrant (WEQ), the newly adopted standards represent the latest evolution of NAESB's consensus-based standards for public utilities.  NAESB is an ANSI-accredited non-profit standards development organization formed to develop and promote business practice standards that promote a seamless marketplace for wholesale and retail natural gas and electricity. Since issuing Order No. 676 in 2006, the FERC has incorporated elements of NAESB's standards into its regulations.

While the FERC made most of the NAESB standards mandatory, it decided to include NAESB's smart grid standards only "informationally, as guidance."  While FERC noted that the smart grid standards have value and should be adopted by public utilities, it ultimately agreed with utility trade group Edison Electric Institute and the ISO/RTO Council that NAESB's five Smart Grid standards should neither be incorporated into formal federal regulation nor be enforceable and mandatory.  Notably, as prepared by NAESB the Smart Grid standards are meant to be optional and informative, not prescriptive or restrictive, and could prove difficult to enforce.

Thus to "encourage further developments in interoperability, technological innovation and standardization", the FERC chose to include NAESB's five smart grid standards in Order No. 676-H as guidance, but not to incorporate them into its formal, enforceable regulations.

Through Order No. 676-H, the FERC hopes to improve business practices and interoperability among public utilities.  The order also shows an intent to foster smart grid technologies, without stifling their development through overly prescriptive or unenforceable regulations.  Will Order 676-H usher in a new era of smart grid and utility cooperation?

FERC Order 800 eases hydropower regulations

Friday, September 19, 2014

The Federal Energy Regulatory Commission has issued an order streamlining its regulations for some small hydropower projects.  FERC Order No. 800 conforms the Commission's regulations to the Hydropower Regulatory Efficiency Act of 2013.  Between Order 800 and the Hydropower Efficiency Act, regulatory processes for developing some small hydropower projects have recently become easier.

Hydropower is one of the nation's most abundant sources of renewable energy -- and yet about 97 percent of the estimated 80,000 dams in the United States do not generate electricity.  While not all are great candidates for hydropower, some non-power dam sites offer significant opportunities to generate renewable electricity with minimal incremental environmental impact.

Congress had these dams in mind when it enacted the Hydropower Efficiency Act on August 9, 2013.  To encourage the use of these dams for electric generation, the Act aims to reduce the costs and regulatory burden on project developers during the project study and licensing stages.  In particular, the Act amended previous statutory provisions covering both preliminary permits and projects that are exempt from licensing.  These statutory changes prompted FERC to update its regulations to conform to the Hydropower Efficiency Act.

Order No. 800 formalizes the Commission's compliance procedures in its revised regulations on preliminary permits, small conduit hydroelectric facilities, and small hydroelectric power projects, and in a new subpart on qualifying conduit hydropower facilities.  Key changes include:
  • New regulations recognize the Commission's new statutory authority to extend a preliminary permit once for not more than two additional years, allowing permittees up to 5 total years to complete their feasibility studies without facing possible competition for the site from others.
  • Exempt small conduit hydroelectric facilities may now be located on federal lands, and all exempt small conduit hydroelectric facilities may now have an installed capacity of up to 40 megawatts.  Previously, non-municipal small conduit exemptions were limited to 15 megawatts.
  • Exempt small hydroelectric power project facilities may now have an installed capacity of up to 10 megawatts.
  • Qualifying conduit hydropower facilities, which do not require licensure under the Federal Power Act but do require the filing with FERC of a notice of intent to construct, are now covered under the regulations.
While several of these categories of facility appear similar, each is defined separately by statute.
  • A small conduit hydroelectric facility, as defined in section 30 of the Federal Power Act, is an existing or proposed hydroelectric facility that utilizes for electric power generation the hydroelectric potential of a conduit, or any 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 not primarily for the generation of electricity.
  • A small hydroelectric power project, as defined in the Public Utilities Regulatory Policies Act of 1978 (PURPA), is a project that utilizes for electric generation the water potential of either an existing non-federal dam or a natural water feature (e.g., natural lake, water fall, gradient of a stream, etc.) without the need for a dam or man-made impoundment.
  • A qualifying conduit hydropower facility, as defined in the Hydropower Efficiency Act, is a facility that meets the following qualifying criteria: (1) the facility would be constructed, operated, or maintained for the generation of electric power using only the hydroelectric potential of a non-federally owned conduit, without the need for a dam or impoundment; (2) the facility would have a total installed capacity that does not exceed 5 MW; and (3) the facility is not licensed under, or exempted from, the license requirements in Part I of the FPA on or before the date of enactment of the Hydropower Efficiency Act (i.e., August 9, 2013).
In Order 800, the Commission is merely formalizing several practices it has already adopted since the enactment of the Hydropower Efficiency Act.  For example, the Commission has issued two-year extensions to preliminary permit holders, granted a small conduit exemption on federal lands, and issued conduit facility determinations on whether proposed projects are qualifying conduit hydropower facilities.  Nevertheless, the Act and Order No. 800 work together to offer an easier regulatory path for developers of small hydropower projects without new dams.

Federal grants support microgrids

Thursday, September 18, 2014

The U.S. Department of Energy has awarded over $8 million in funding for 7 microgrid projects.  Will microgrids play an increasing role in the U.S. electricity industry?

Solar photovoltaic panels can serve as distributed generation for microgrids.


Microgrids -- localized grids capable of operating as energy islands using distributed generation, energy storage, and distribution wires, as well as able to connect to the broader utility grid -- can offer participants and society at large significant value.  These benefits can include increased reliability against storm damage and infrastructure damage, reduced emissions of carbon and other pollutants, and reduced costs.

The Energy Department runs a portfolio of microgrid activities ranging from direct research and development to building community support.  Most recently, the Department announced over $8 million in grant funding to support 7 microgrid projects.  The Department selected these projects based on their ability to develop advanced microgrid controllers and system designs for microgrids less than 10 megawatts:

  • ALSTOM Grid, Inc.: about $1.2 million to research and design community microgrid systems for the Philadelphia Industrial Development Corporation and the Philadelphia Water Department, using portions of the former Philadelphia Navy Yard. 
  • Burr Energy, LLC: about $1.2 million to design and build a resilient microgrid to allow the Olney, Maryland Town Center to operate for weeks in the event of a regional outage, and a second microgrid for multi-use commercial development in Maryland. 
  • Commonwealth Edison Company (ComEd): about $1.2 million to develop and test a commercial-grade microgrid controller capable of controlling a system of two or more interconnected microgrids, serving civic infrastructure including police and fire department headquarters, transportation and healthcare facilities, and private residences. 
  • Electric Power Research Institute (EPRI): about $1.2 million to develop a commercially-viable standardized microgrid controller that can allow a community to provide continuous power for critical loads. 
  • General Electric Company (GE): about $1.2 million to develop an enhanced microgrid control system in Potsdam, New York, by adding new capabilities, such as frequency regulation. 
  • TDX Power, Inc.: about $1.2 million to engineer, design, simulate, and build a microgrid control system on remote Saint Paul Island, an island located in the Bering Sea off mainland Alaska. 
  • The University of California, Irvine (UCI): about $1.2 million for the Advanced Power and Energy Program at UCI to develop and test a generic microgrid controller intended to be readily adapted to manage a range of microgrid systems, and supporting the development of open source industry standards.

Each project also includes an awardee cost share ranging from 20 percent to about 50 percent.  Will the DOE funds lead to better and more widely adopted microgrids?

New generation in 2014 mostly gas, solar, wind

Wednesday, September 17, 2014

Most new power plants placed in service in the first half of 2014 are powered by natural gas, with new solar and wind capacity coming in second and third, respectively, according to the U.S. Energy Information Administration.  Meanwhile, no new coal-fired electric generating capacity was added during that period.

Source: U.S. Energy Information Administration, Electric Power Monthly, August 2014 edition with June 2014 data
Note: Data include facilities with a net summer capacity of 1 MW and above only.
From January through June 2014, EIA data shows the U.S. added 4,350 megawatts of new utility-scale generating capacity. Combined-cycle natural gas plants contributed 2,179 MW of new capacity.  Of this, over half is located at Florida Power & Light's Riviera Beach Next Generation Clean Energy Center in Florida.  New combustion turbine plants added another 131 MW.  In all, natural gas powers over 53% of new capacity coming online in the first half of 2014.  Most of the nation has access to low cost natural gas, which offers significant environmental benefits over other fossil fuels like coal and oil.

Solar projects came in second, with 1,146 MW of new capacity coming online.  Solar capacity is growing quickly, with an increase of almost 70% in new capacity added over the same period in 2013.  Nearly 75% of this solar capacity is located in California, with most of the rest in Arizona, Nevada, and Massachusetts.  Notably, the EIA's data only covers utility-scale projects; it omits most rooftop solar projects and any other solar capacity additions below 1 MW in size.

New wind capacity came in third, with 675 MW added.  Most of the new capacity is sited in California, Nebraska, Michigan, and Minnesota.

Coal was notably absent from the ranks of new generating capacity added in the first half of 2014.  New coal plants face steep headwinds in the form of environmental regulations and stiff competition against natural gas plants.  EIA reports that only two coal plants are planned to come online in 2014.

As regulations and market forces shape the nation's energy mix, where will the new equilibrium be found -- and for how long?

FERC authorizes mine drainage microhydro

Friday, September 5, 2014

The Federal Energy Regulatory Commission has issued a hydropower license to a project whose turbines generate electricity from acid mine drainage. The micro-hydropower license issued to the Antrim Treatment Trust illustrates this unusual approach to the twin challenges of mine remediation and renewable energy.

The power of falling water, in the White Mountain National Forest in New Hampshire.
In the 1980s, Antrim Mining, Inc. operated a surface bituminous coal mine in Pennsylvania.  When water draining through the mine and into streams and rivers was found to exceed pollution limits, the Commonwealth of Pennsylvania charged the company with violations of mining and reclamation law.  The charges led to a series of settlements through which Antrim agreed to improved water treatment facilities, including an off-the-grid hydroelectric facility.  This micro-hydro plant would be powered by treated effluent flowing downhill out of lagoons.  Antrim created the Antrim Treatment Trust to manage treatment of the mine water in 1991, then went out of business.

In an attempt to reduce the cost of treating the site's severe acid mine drainage, the Babb Creek Watershed Association identified micro-hydropower as an option for the site.  In 2008, the association received an Energy Harvest Grant from the Pennsylvania Department of Environmental Protection.  This $428,710 award was designed to support the installation of two hydroelectric turbines on the treatment plant's discharge, which was completed in 2012.

While the Federal Power Act requires most hydropower projects to secure a license from the Federal Energy Regulatory Commission, some off-grid hydropower projects that do not use the waters of the United States do not require licensure.  In 2010, the Antrim Treatment Trust filed a Declaration of
Intent for a 40-kilowatt grid-connected project, but quickly revised its project to be off-grid after the Commission issued an order finding that a license was required for the grid-connected project.  Once the project was off-grid, the Commission ruled that no license was required.

The Antrim treatment plant seems to have then operated one turbine, but left the second turbine non-operational. A 2012 article in the Williamsport Sun-Gazette suggested that with both turbines running and selling power into the electricity grid, the treatment plant could cut $12,000 in annual power costs and make $10,000 per year in new revenue.  But this could require a FERC license, because the project would become connected to the utility grid.

The Trust appears to have decided that these economics were worth pursuing, because in 2013 it filed an application for a project license for a 40-kilowatt project.  In the application, Antrim Trust proposed to bring a second identical turbine (currently in place but non-operational) online by installing additional indoor wiring with appurtenances within the existing powerhouse and treatment plant, and operate both turbines as a grid-connected project using the treated and/or untreated water.

As licensed, the Commission estimates the annual cost to develop and maintain the proposed 40-kW project is $9,356 or $37.42/megawatt-hour (MWh).  The project will generate an estimated average of 250 MWh of energy annually.  Based on Commission staff’s view of the alternative cost of power ($56.93/MWh), the total value of the project’s power is $14,233 in 2013 dollars.  To determine whether the proposed project is currently economically beneficial, staff subtracts the project’s cost from the value of the project’s power. Therefore, in the first year of operation, the project is expected to cost $4,877 or $19.51/MWh less than the likely alternative cost of power - demonstrating economic benefit.

Micro-hydropower projects can make economic sense in some mine drainage situations and other places where water treatment is required and a suitable vertical drop or pressure is available.  In Antrim's case, the project's success can partially be explained by the existence and purpose of the Trust, as well as the DEP grant to support project construction.  If treated and untreated mine drainage can be used to generate hydroelectricity, what other unusual sources of power will arise?

Oregon wave energy project surrenders license

Monday, August 25, 2014

Ocean waves contain tremendous amounts of energy that could be harnessed by humans -- but difficulties have led a pilot project proposed off the Oregon coast to surrender a key federal license.

Calm waters along the shore of Penobscot Bay, Maine.

Ocean Power Technologies subsidiary Reedsport OPT Wave Park, LLC had proposed a wave energy project in the Pacific Ocean off the central Oregon coast.  In 2012, the Federal Energy Regulatory Commission issued a license for the project.  That license authorized the developer to install a single "PowerBuoy" wave energy converter for testing, followed by additional grid-connected buoys.  The developer also envisioned a third phase that could bring the project's capacity to 50 megawatts, and secured a preliminary permit from the Commission to study the site.

Despite securing these key regulatory approvals, the Reedsport project quickly ran into technical difficulties.  Reedsport began construction of the project in September 2012, by installing a single floating gravity based anchor and auxiliary subsurface buoy.  However, this first phase of the project was unsuccessful and the auxiliary buoy sank.  Reedsport removed the buoy and associated tendon and outer mooring lines from the project area on October 17, 2013.  On February 28, 2014, Ocean Power Technologies notified the Federal Energy Regulatory Commission that it intended to surrender its preliminary permit for the 50 megawatt third phase, but left the first phase's license in place for the moment.

On May 30, 2014, Reedsport filed an application to surrender its license for project, stating that financial and regulatory challenges in developing the project have forced it to conclude that it cannot proceed with the development of the project.  The Commission accepted that license surrender by order dated August 14, to be effective following confirmation of the project's decommissioning.

With the Reedsport project shelved, no wave energy project currently holds a FERC license.  Several tidal projects have been licensed, one wave-based hydrokinetic project has secured a preliminary permit, and two other wave energy projects have pending applications for preliminary permits.  The ocean remains a demanding environment, and the economics of most wave energy projects are challenging.  Will others succeed where Reedsport OPT has not?

Maryland offshore wind sites auctioned

Wednesday, August 20, 2014


The U.S. Bureau of Ocean Energy Management has sold the rights to lease sites for offshore wind projects in federal waters off Maryland to US Wind Inc. for $8.7 million.

A lighthouse on an island in the Atlantic Ocean, off Maine.


Part of the Obama administration's "Smart from the Start" offshore wind leasing program, yesterday's auction covered the rights to lease nearly 80,000 acres of the outer continental shelf.  The Maryland Wind Energy Area ranges seaward from about 10 nautical miles offshore Ocean City.  According to Department of Energy’s National Renewable Energy Laboratory, the area could support between 850 and 1450 megawatts of commercial wind generation.

The Maryland auction drew three bidders: US Wind Inc., Green Sail Energy LLC and SCS Maryland Energy LLC.  After 19 rounds, BOEM declared US Wind Inc. the provisional winner.  US Wind Inc. is a subsidiary of Italian firm Toto SpA's Renexia group. 

While winning the auction is an important first step in leasing federal ocean sites for offshore wind projects, the process will likely continue to play out for several years.  Following the auction results, US Wind Inc. will have one year within which to submit a Site Assessment Plan to BOEM for approval.  In the Site Assessment Plan, the lessee must describe what it intends to do to assess of the wind resources and ocean conditions of its commercial lease area -- for example, installing meteorological towers and buoys.  If that plan is approved, the lessee will then have up to 4½ years in which to submit a Construction and Operations Plan providing more detailed information for the construction and operation of a wind energy project on the lease.  The filing of that plan triggers further public comment and environmental review; if approved, BOEM will then issue a lease with an operations term of 25 years.  Notably, these leases generally require the lessee to pay ongoing rents; placing the winning bid in the auction conveys the right to pay that rent, but paying that bid does not count towards the lease payment obligation.

Moreover, this entire leasing process is just one of several aspects of the project that must move forward in parallel.  At the same time, US Wind Inc. is likely considering engineering issues such as turbine selection and interconnection design as well as how to finance the project.

Will federal waters offshore Maryland soon become home to an offshore wind project?

Feds to auction North Carolina offshore wind sites

Friday, August 15, 2014

The U.S. Department of the Interior's Bureau of Ocean Energy Management has announced plans to auction the rights to lease sites off the North Carolina coast for offshore wind projects.

Under the Bureau of Ocean Energy Management's "Smart from the Start" competitive program for leasing sites on the outer continental shelf (OCS) for commercial wind energy development, BOEM conducts a series of stakeholder and environmental review processes.  Through these processes, BOEM identifies areas that are attractive for commercial offshore wind development, while also protecting important viewsheds, sensitive habitats and resources and minimizing space use conflicts with activities such as military operations, shipping and fishing.

For North Carolina, the process began in December 2012 when BOEM published in the Federal Register a Call for Information and Nominations and a Notice of Intent to Prepare an Environmental Assessment.  After considering the public comments and responses, BOEM defined three Wind Energy Areas off North Carolina:
  • The Kitty Hawk Wind Energy Area begins about 24 nautical miles (nm) from shore and extends approximately 25.7 nm in a general southeast direction at its widest point. Its seaward extent ranges from 13.5 nm in the north to .6 nm in the south. It contains approximately 21.5 OCS blocks (122,405 acres).
  • The Wilmington West Wind Energy Area begins about 10 nm from shore and extends approximately 12.3 nm in an east - west direction at its widest point. It contains just over 9 OCS blocks (approximately 51,595 acres).
  • The Wilmington East Wind Energy Area begins about 15 nm from Bald Head Island at its closest point and extends approximately 18 nm in the southeast direction at its widest point. It contains approximately 25 OCS blocks (133,590 acres). 

Map of North Carolina Wind Energy Areas, courtesy of BOEM.
The North Carolina auction will follow a series of similar auctions for East Coast offshore wind sites in federal waters over the past year, including sites off Massachusetts and Rhode Island and Virginia, and will come after the scheduled August 19 auction for sites off Maryland.  To date, BOEM has awarded five commercial wind energy leases off the Atlantic coast: two non-competitive leases (for the proposed Cape Wind project in Nantucket Sound and an area off Delaware) and three competitive leases (two offshore Massachusetts-Rhode Island and another offshore Virginia).  Altogether, the competitive lease sales have generated more than $5 million in high bids for more than 277,500 acres in federal waters.  BOEM expects to hold additional competitive auctions for wind energy areas offshore Massachusetts and New Jersey in the coming year.

When will North Carolina offshore wind sites be auctioned?  Who will bid?  Who will win -- and what will the high bid be?  Perhaps most fundamentally, will the BOEM leasing process lead to anyone developing a offshore wind project off North Carolina?

Boon Island lighthouse auction

Wednesday, August 13, 2014

The U.S. federal government is auctioning off Maine's tallest lighthouse, located on Boon Island near one of the state's designated offshore wind test sites.

Boon Island Light Station, seen from Cape Neddick.

The Boon Island Light Station auction, conducted online through the General Services Administration's website, covers a 133-foot granite tower sited on a barren outcrop of granite 14 feet above sea level.  Built in 1855 and listed on the National Register of Historic Places, the lighthouse will continue to serve as an unmanned navigational aid maintained by the United States Coast Guard.

In 2009, the Maine Legislature selected waters near Boon Island as one of three designated offshore wind test sites.  While the Monhegan offshore wind test site drew interest from the University of Maine-led Aqua Ventus consortium, to date, no project has publicly pursued plans to develop the Boon Island offshore wind test site.

Meanwhile, the federal government continues to sell or otherwise get rid of "surplus" property.  Two years ago, the federal government announced plans to give away two Maine lighthouses -- Boon Island and Halfway Rock -- to qualified entities willing to conserve the historic structures.  When no such transfer ensued, the General Services Administration placed both lighthouses on the auction block.

As of early Wednesday afternoon, 13 bidders had participated in the auction for the Boon Island light station, with a current high bid of $64,000.  The auction is scheduled to close midday on Thursday, although previous deadlines have been extended.

Feds to auction Maryland offshore wind sites

Monday, August 11, 2014

On August 19, the U.S. Department of the Interior's Bureau of Ocean Energy Management will auction off rights to lease sites off the Maryland coast for offshore wind.  Through the auction, which will represent the third auction for offshore wind sites in federal waters since July 2013, the Bureau hopes it will award leases to two areas covering approximately 80,000 acres about 10 nautical miles east of the Ocean City coastline.

Last year, the Department of the Interior held its first offshore wind site auction for sites off Massachusetts and Rhode Island; Deepwater Wind won that auction with a bid of $3.8 million.  The second auction, held for Virginia on September 4, covered approximately 112,799 acres about 23.5 nautical miles from the Virginia Beach coastline; Dominion Virginia Power won that auction with a bid of $1.6 million.

The Maryland auction later this month will follow procedures similar to those used in the previous two auctions.  Based on previous expressions of interest and qualifications, BOEM has determined that sixteen companies are eligible to bid on the Maryland sites:
  • Apex Offshore Maryland, LLC
  • Bluewater Wind Maryland LLC
  • Convalt Energy LLC
  • Dominion Wind Development, LLC
  • EDF Renewable Development, Inc.
  • Energy Management, Inc.
  • Fishermen’s Energy, LLC
  • Green Sail Energy LLC
  • IBERDROLA RENEWABLES, Inc.
  • Maryland Offshore Wind LLC
  • Orisol Energy US, Inc.
  • RES America Developments Inc.
  • SCS Maryland Energy LLC
  • Sea Breeze Energy LLC
  • Seawind Renewable Energy Corporation LLC
  • US Wind Inc.
How many of these entities actually participate in the auction remains to be seen.  8 qualified bidders (or their affiliates) also qualified to participate in the Virginia auction, but only winner Dominion and an Apex affiliate ever placed bids.  For Massachusetts and Rhode Island sites, 9 companies qualified to bid but only winner Deepwater, Sea Breeze, and US Wind participated.

Offshore wind project developers must coordinate regulatory, financial, and engineering efforts.  Securing a site for a project is a major step forward, but is only one of many important steps necessary to build an operating offshore wind project -- something the U.S. still lacks.  How much interest will the Maryland auction draw?  Who will win the right to lease the two parcels in the Maryland wind energy area, and how much will they pay?  Will the auction winners actually build offshore wind projects?  Some of these questions will be answered when the auction closes on August 19.

FERC approves second Southwest blackout penalty

Thursday, August 7, 2014

A California irrigation district has agreed to pay a $12 million penalty to settle its role in a 2011 power outage affecting over 5 million people in California, Arizona, and Mexico.

The September 8, 2011 outage 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 deprived customers of 7,835 megawatts of peak demand and over 30,000 megawatt-hours of energy.

Swiftly on the heels of the outage, the Federal Energy Regulatory Commission and electric reliability organization NERC launched an investigation into what had happened -- and whether any laws or regulations had been violated.  That investigation focused on APS and five other entities believed to have been involved: the California Independent System Operator, the Imperial Irrigation District, Southern California Edison, the Western Area Power Administration, and the Western Electricity Coordinating Council Reliability Coordinator.  Last month, the Commission approved a $3.25 million settlement with APS.

Today, the Commission issued an order approving a stipulation and consent agreement resolving  Imperial Irrigation District's role in the blackout.  Imperial Irrigation District is a not-for-profit, publicly owned, vertically integrated utility and political subdivision of the State of California.  The sixth largest utility in California, Imperial Irrigation District Electricity provides electric power to more than 145,000 customers in the Imperial Valley and parts of Riverside and San Diego counties.

Through their investigation, Commission enforcement staff and NERC found Imperial Irrigation District violated 10 requirements of four Reliability Standards on transmission operations and transmission planning, including a failure to coordinate its operations planning with neighboring systems.  The Commission noted that these violations were serious deficiencies that undermined reliable operation of the Bulk Power System.

Through that stipulation, Imperial Irrigation District agreed to pay a civil penalty of $12 million.  Of this amount, at least $1.5 million will go to the U.S. Treasury and another $1.5 million will go to NERC, and at least another $9 million will be invested in reliability enhancement measures that go beyond mitigation of the violations and the requirements of the mandatory Reliability Standards.  These reliability enhancements will include construction of one or more utility-scale battery energy storage facilities within IID’s transmission operations area, with the money spent by December 31, 2016.

Two of the six entities known to be targeted by the Commission's investigation have now settled their alleged violations by agreeing to pay penalties.  Perhaps more significantly, APS and Imperial Irrigation District represent two of the three vertically integrated utilities implicated.  Will the FERC/NERC investigation lead to further settlements soon?  What impact will the Imperial Irrigation District settlement and penalty agreement have?

FERC tests 2-year hydropower licensing process

Wednesday, August 6, 2014

Licensing some new hydropower projects in the United States -- traditionally a lengthy process -- may soon become easier, as federal regulators have approved an experimental two-year process that may soon be used to license some projects.

Water spills over a small, non-powered dam in Maine.

The Federal Energy Regulatory Commission regulates most hydropower development in the United States.  Under Part I of the Federal Power Act, the Commission considers applications for hydropower project licenses.  While the traditional licensure process has resulted in the issuance of thousands of licenses, winning a license for a project can take many years -- and some licensure proceedings have stretched toward a decade.

In response to concerns that lengthy licensing procedures stifle hydropower development, last year Congress enacted the Hydropower Regulatory Efficiency Act of 2013.  That law directed the Commission to investigate the feasibility of a two-year licensing process for certain projects, develop criteria for identifying projects that may be appropriate for the process, and develop and implement pilot projects to test the process.

In January 2014, the Commission solicited pilot projects to test a two-year process.  Two kinds of projects were eligible: hydropower development at existing non-powered dams and closed-loop pumped storage projects.  In the notice soliciting pilot projects, the Commission articulated additional criteria for eligibility including:
  • The project must cause little to no change to existing surface and groundwater flows and uses;

  • The project must not adversely affect federally listed threatened and endangered species;

  • If the project is proposed to be located at or use a federal dam, the request to use the two-year process must include a letter from the dam owner saying the plan is feasible;

  • If the project would use any public park, recreation area, or wildlife refuge, the request to use the two-year process must include a letter from the managing entity giving its approval to use the site; and

  • For a closed-loop pumped storage project, the project must not be continuously connected to a naturally flowing water feature. 
Ultimately, the Commission selected a project proposed by Free Flow Power Project 92, LLC: a 5-megawatt project at the Kentucky River Authority's existing Lock & Dam No. 11 on the Kentucky River in Estill and Madison counties, Kentucky.  Lock and Dam 11 were originally built from 1904-1906 and support a twenty mile long pool of water 201 miles above the mouth of the Ohio River, but have not previously supported a FERC-licensed hydropower project.

The Free Flow Power applicant's request to use the 2-year licensing process was filed on May 5, 2014, so the two years runs through May 5, 2016.  The Commission staff has issued a process plan and schedule with interim milestones through February 2016.  Compared to a traditional licensure process, the proposed schedule is accelerated -- but will this pilot case remain on schedule?  Will the accelerated process satisfy the various stakeholders, including the developer, regulator, neighbors, and public?

FERC testifies on EPA carbon regulations and electric reliability

Wednesday, July 30, 2014

The U.S. Environmental Protection Agency's proposed Clean Power Plan rule is projected to limit carbon dioxide emissions from power plants, improve human health and save money -- but will it jeopardize the reliability of the nation's electricity grid?

Poorly implemented carbon regulations could increase the risk of widespread power outages, but this risk can be managed, according to testimony offered by the Commissioners of the Federal Energy Regulatory Commission to the House Energy & Commerce Subcommittee on Energy & Power earlier this week.

In her written testimony, Acting Chairman Cheryl LaFleur acknowledged concerns that EPA's carbon rule may have an "adverse impact on the overall reliability of the bulk power system."  Noting that EPA's plan leaves much of the implementation to individual states, she suggested that the FERC work closely with states to consider how state implementation plans will affect the operation of the grid. 

Commissioner Philip Moeller's testimony was more critical of EPA's proposed rule, which he described as infringing upon the FERC's jurisdiction over electric system reliability.  Noting that electricity markets are interstate in nature, Commissioner Moeller warned that "the proposal’s state-by-state approach results in an enforcement regime that would be awkward at best, and potentially very inefficient and expensive."  He also expressed skepticism at the plan's inclusion of increased use of existing natural gas-fired generation as one "building block" states may use to reduce their power sector's carbon intensity.  Commissioner Moeller also pointed to EPA's Mercury and Air Toxics Standards (MATS) rule as giving him reliability concerns.  On the positive side, he urged state regulators to speed adoption of real-time pricing at the retail level, so consumers can feel price signals that could reduce the overall cost of energy.  Commissioner Moeller concluded with a plea that FERC be given a formal role in EPA's regulation of the electric power sector.

Commissioner John Norris testified that EPA's proposed rule is "an important first step that addresses climate change by appropriately seeking to reduce carbon emitted by our nation’s electric power system."  While he acknowledges that transitioning to a low-carbon economy is challenging, he expressed confidence that "we as a nation should be well positioned to meet those challenges."  Commissioner Norris cited the MATS standards as an example of our readiness: while EPA's MATS rule led to the retirement of many older, inefficient coal-fired power plants, the grid has generally responded in a way that will maintain reliability.  Commissioner Norris urged cooperation with electric reliability organization North American Electric Reliability Corporation (NERC) and states, and to be flexible in making market rule changes to enable states, regional transmission organizations and other system planners to meet resource adequacy requirements.

Commissioner Tony Clark testified that while the grid is more reliable than before, it remains vulnerable to cyberattack, physical security threats, and geomagnetic disturbances.  He also described environmental regulations as another source of risk, and warned of the "seismic" shift in EPA authority over the energy sector embodied in the rule.  Commissioner Clark described the Clean Power Plan as the most comprehensive reordering he has seen of the jurisdictional relationship between the federal government and states as it relates to the regulation of public utilities and energy development.  He painted a picture of states forced to choose between surrendering their authority over power plants willingly or losing it to federal supremacy.

Current FERC enforcement director Norman Bay also testified, noting that he was confirmed by the Senate as a Commissioner on July 15, but that he has not yet been sworn in.  His brief testimony focused on the need for cooperation between FERC, EPA, NERC, states, and regional transmission organizations to ensure reliability.

What happens next remains to be seen.  As expressed in the opening statements of Energy and Power Subcommittee Chairman Ed Whitfield and Energy and Commerce Committee Chairman Fred Upton, many remain concerned about what they perceive as an effort by EPA to assert control and new regulatory authorities over states’ electricity decision-making.  Will EPA's Clean Power Plan ultimately come into effect -- and if so, what path will it take?

Report projects modest need for electric generation capacity growth

Thursday, July 24, 2014

The U.S. Energy Information Administration has projected that 351 gigawatts of new electric generating capacity will be added to the U.S. grid between 2013 and 2040.  This projected new capacity, most of which EIA expects to be fueled by natural gas, will replace older power plants as they retire, as well as modestly increasing the country's net installed capacity.

EIA's forecast implies a growth rate well below recent annual levels observed.  Under EIA's projection, capacity additions through 2016 will average 16 GW per year.  But from 2017 through 2022, EIA expects additions of less than 9 GW per year as the existing generating fleet will be sufficient to meet expected demand growth in most regions.  From 2025 to 2040, annual additions increase to an average 14 GW per year, but remain below recent levels.

EIA expects that natural gas will be the primary fuel source for the projected added capacity, accounting for 73% of capacity additions in the reference case (or 255 GW).

Renewables will account for 24% of the new capacity (or 83 MW).  Of renewable capacity additions, 39 GW are solar photovoltaic (PV) systems (60% of which are rooftop installations).  Another 28 GW are wind, most of which will occur by 2015 to qualify for federal renewable energy production tax credits).

New nuclear capacity will total about 3% (or 10 GW), including 6 GW of plants currently under construction and 4 GW projected after 2027.

EIA also projects that 1% of capacity additions (or less than 3 GW) will come from coal, with more than 80% of that total currently under construction.  EIA notes that federal and state environmental regulations and uncertainty about future limits on greenhouse gas emissions reduce the attractiveness and economic merits of coal-fired plants.

Like any forecast, EIA's projections rest upon a series of assumptions.  Under alternative cases, we might experience actual capacity additions that differ from EIA's forecasts.  Nevertheless, the EIA Annual Energy Outlook 2014 offers a glimpse of changes to the portfolio composing our energy mix may come in the next decades.

Atlantic offshore wind energy targeted

Tuesday, July 15, 2014

A report released by the National Wildlife Foundation highlights the potential of U.S. states on the Atlantic Ocean to generate electricity from offshore wind -- and calls upon state leaders to take action to promote offshore wind development.

The 24-page report, Catching the Wind: State Actions Needed to Seize the Golden Opportunity of U.S. Offshore Wind Power, describes responsibly developed offshore wind as "a golden opportunity to meet our coastal energy needs with a clean, local resource that will spur investments in local economies."  In particular, the Atlantic coast offers a high-quality wind resource in close proximity to power-thirsty coastal cities.

Key findings in the report include:
The report highlights Massachusetts and Rhode Island as leading America's pursuit of offshore wind, followed by Maryland, Virginia, New York, New Jersey, and Delaware, with Maine, North Carolina, South Carolina, and Georgia bringing up the rear.  New Hampshire, Connecticut, and Florida are noted as "states to watch" with no offshore wind planning activities.

The report calls on state leaders to:
  • Set a bold goal for offshore wind in the state's energy plan.
  • Take action to ensure a competitive market for offshore wind power.
  • Advance power contracts for offshore wind.
  • Ensure an efficient, transparent, and environmentally responsible offshore wind leasing process that protects wildlife.
  • Invest in key research, initiatives, and infrastructure needed to spur offshore wind development.
Will Atlantic states develop their offshore wind resources? 

Arizona utility fined $3.25 million over 2011 blackout

Friday, July 11, 2014

On a hot summer afternoon in 2011, cascading power outages spread across the North American Southwest.  Over 5 million people in Southern California -- including all of San Diego -- Arizona and Mexico were left without power for up to 12 hours.  This week a federal investigation into the outage was partially resolved by a $3.25 million settlement with Arizona Public Service Company.

According to a joint report by the staffs of the Federal Energy Regulatory Commission and the North American Electric Reliability Corporation, the September 8, 2011 outage started when a 500-kilovolt transmission line owned by APS tripped.  The Hassayampa - N. Gila line serves as a major transmission corridor that transports power in an east-west direction, from generators in Arizona into the San Diego area.  The line's failure triggered significant voltage deviations and equipment overloads, causing transformers, transmission lines, and generating units to trip offline through automatic load shedding.  In all, 7,835 megawatts of customer load lost power -- over 30,000 megawatt-hours of energy -- primarily in the San Diego Gas and Electric service territory and in Baja California.

Following the outages, both the Commission's Office of Enforcement and NERC launched an investigation into the incident.  That investigation, which has been ongoing since 2011, focused on APS and five other entities believed to have been involved: the California Independent System Operator, the Imperial Irrigation District, Southern California Edison, the Western Area Power Administration, and the Western Electricity Coordinating Council Reliability Coordinator.


The investigation concluded that APS had violated NERC's mandatory Reliability Standards.  APS's role and liability was ultimately resolved this week when the Commission accepted a stipulation between APS, the Commission's Office of Enforcement and NERC.

Through that stipulation, APS agreed to pay a civil penalty of $3.25 million.  Of this amount, $1 million will go to the U.S. Treasury, $1 million will go to NERC, and $1.25 million will be invested in reliability enhancement measures that go beyond mitigation of the violations and the requirements of the mandatory Reliability Standards.  In finding the settlement to be in the public interest, the Commission cited APS's cooperation in the investigation as well as its voluntary mitigation efforts.

With APS's role in the outage settled, joint FERC/NERC investigations into other entities' roles continue.  While some targets of investigation choose to settle their cases, others insist to exercise their full legal rights.  Will the 2011 Southwest blackouts lead to further stipulations and penalties?