Texas small hydro project loses exemption

Wednesday, March 25, 2015

What happens to a proposed hydroelectric project takes longer than anticipated to be built, due to difficulties with project financing and severe flooding?  As the developer of a proposed project in Texas recently found out, federal regulators can be lenient up to a point -- but under some circumstances the developer can lose its federal authorization to develop and operate the project.

The A.H. Smith Dam on the San Marcos River in Martindale, Texas was originally constructed in about 1894 to provide mechanical power a cotton gin; later, electric generation was installed, but power production ceased in the 1940s when low wholesale energy prices made operation uneconomic.  Modern hydropower facilities rated at 150 kilowatts were installed in 1984, but were ultimately abandoned.

In 2005, developer Hydraco Power, Inc. applied to the Federal Energy Regulatory Commission for an exemption from the licensing requirements of Part I of the Federal Power Act for its proposed A.H. Smith Dam Project.  Hydraco's project included refurbishing and restoring the operation of the existing turbine located at the dam's powerhouse, installing a new buried transmission line and a water surface elevation gate in the headpond.

On June 2, 2006, the Commission granted Hydraco an exemption for the project.  As a standard condition of exemptions, the Commission retained the right to revoke the exemption if any term or condition was violated.  Among the terms was a requirement that Hydraco file within 120 days a
plan and schedule to install the new transmission line and restore the powerhouse, turbine, and trash racks to operating condition, as well as notice that the Commission could terminate the exemption if actual construction of any proposed or required facility had not begun within two years or had not been completed within four years of the date of issuance of the exemption.

Over the next 8 years, Hydraco filed a series of construction plans and schedules, but never completed the project despite obtaining repeated extensions of key deadlines.  After multiple prompts by Commission staff to file a revised plan and schedule for restoring project operation or an application to surrender the exemption, the Commission noted that Hydraco either failed to respond or responded by stating that it could not estimate a schedule for restoring project operation because project construction, including major component repairs, was on hold due to lack of funds.

After the Commission issued a public notice in August 2014 stating its intent to terminate the project exemption "due to Hydraco’s longstanding violation of exemption Article 10 and its failure to provide a timeframe for restoring project generation", on November 20, 2014, the Commission issued an Order Terminating Exemption. That order found that "Hydraco has only performed minimal work at the project since obtaining its exemption in 2006 and that it lacks the funding to proceed with the necessary component repairs, including construction of the powerhouse interior and generating unit."

Hydraco filed a request for rehearing of the Order Terminating Exemption.  On rehearing, Hydraco asserted that it had reached a financing agreement with a new investor and, consequently, it is ready to perform the work needed to comply with its exemption. Hydraco also objected to the findings that project construction was at a standstill and that Hydraco intended to abandon the project, noting that the Commission should excuse construction delays caused by severe flooding.

Last week, the Commission issued an Order Denying Rehearing in the case.  It first noted that Hydraco had not demonstrated that it now has the money needed to bring the project on line.  Not only did Hydraco not show evidence of a final financing agreement, but the documents showed a source of only half of the funding needed for project restoration.  Second, the Commission noted that Hydraco's recent activities -- regularly inspecting the dam and removing debris from its spillway, trashracks, and grates, securing the site against vandalism and installing lighting, and repairing damage caused by a flood -- are "either maintenance or repair, not project development."  Finally, the Commission articulated its "doctrine of implied surrender", which it applies where the entity responsible for the project has, by action or inaction, clearly indicated its intent to abandon the project, but has not filed a surrender application.

With the exemption terminated and Hydraco's request for rehearing denied, the A.H. Smith Dam project faces an uncertain future.  On the one hand, the site presumably still offers many of the same values that Hydraco hoped to capture -- use an existing dam, with existing generation facilities, to generate renewable electricity.  However, the loss of the FERC exemption means that Hydraco (or any other developer) will have to start the federal hydropower process over if it hopes to redevelop the dam as a hydroelectric generating site.

The case of the A.H. Smith Dam project illustrates a number of themes: interest in restoring existing hydropower infrastructure to generate renewable energy with relatively less environmental impact than newly-built dams, the challenge of securing financing for small hydropower projects -- and perhaps most importantly the value of compliance with FERC hydropower rules.

FERC 2014 State of the Markets report

Monday, March 23, 2015

U.S. energy markets overseen by the Federal Energy Regulatory Commission in 2014 were impacted by extreme weather and changes in the mix of electric generation resources, according to a report by Commission staff.

The 2014 State of the Markets report issued on March 19 by FERC's Office of Enforcement’s Division of Energy Market Oversight presents Commission's staff’s assessment of recent developments in natural gas, electric, and other energy markets.

Extreme cold temperatures in the first quarter of 2014 affected natural gas infrastructure and power markets across the country.  The price of natural gas in the U.S. reached record high levels, driving corresponding spikes in the price of electricity.  For example, the price of natural gas at the Transco Zone 6 Non-NY pricing point hit $123/MMBtu in January -- about 33 times higher than the average 2013 U.S. price.  Largely due to these price spikes, the spot natural gas price at the Henry Hub pricing point averaged $4.32/MMBtu in 2014, a 16% increase over 2013.

Meanwhile, natural gas and renewable resources continued to displace coal as a fuel for electric power generation.  Total U.S. generating capacity increased 10.8 GW in 2014, with natural gas and renewable projects representing the bulk of new capacity.  At the same time, utilities retired coal-fired power plants, continuing a trend that started in 2012.  Commission staff projects continued coal retirements in 2015, particularly after the April effective date of additional air emissions regulations imposed by the Environmental Protection Agency's Mercury and Air Toxics Standards.

FERC's 2014 State of the Markets report also provides a quick look at 2015 year-to-date market performance.  Wholesale electricity prices rose again this winter, although not as sharply as in the first quarter of 2014.  FERC staff's report suggests factors helping to moderate winter prices included better cold-weather preparation of assets, programs like ISO New England's Winter Reliability Program, better coordination between operators of electric transmission and natural gas pipelines, record high levels of natural gas production, the development of new pipeline infrastructure, and low oil prices.

More solar faster, predicts New England grid operator

Tuesday, March 17, 2015

New England will likely see even more solar photovoltaic energy projects over the next decade than was previously projected, according to the latest draft forecast by the operator of New England's electric grid.

Solar photovoltaic panels on the roof of a Massachusetts home.

To help plan for future needs, grid operator ISO New England, Inc. is developing an updated forecast of solar photovoltaic project development in New England.  In 2014, ISO New England developed its first multistate forecast of PV capacity growth.  It based its 2014 PV forecast heavily on development goals articulated as policies in the six New England states.

ISO New England is now updating that forecast for 2015.  Its draft 2015 Solar PV Forecast, released on February 27, notes that PV development is happening more rapidly than was previously projected.  Using updated historical data, it acknowledges that through 2014, 40% more solar capacity was developed in the region than it previously estimated.  As a result of this faster-than-expected growth, the draft now predicts a higher level of cumulative photovoltaic project development through 2023.

Perhaps more significantly for the solar boom, ISO-NE's draft 2015 forecast also frontloads more new project capacity into 2015 and 2016, while decreasing the amount predicted to be newly developed in later years.  While last year's forecast also predicts more incremental solar capacity will be developed in each of the next three years than in later years, the frontloading is more prominent in the draft 2015 forecast.

The draft 2015 forecast projects that 2,138.8 megawatts of solar photovoltaic projects will be developed in New England by 2024.  This capacity is stated as an alternating current nameplate rating, even though photovoltaic cells essentially generate direct current electricity.  The study derates direct current capacity to alternating current with an 83% array-to-inverter ratio, so this implies an even higher number of megawatts if stated as direct current capacity, as most solar projects are described.

The draft 2015 forecast projects that these solar photovoltaic projects will give rise to a summer seasonal claimed capability of 748.6 megawatts.

ISO New England did not include in its draft 2015 PV forecast any update to its forecast of how much energy these projects would produce.  Instead it suggests that it must first finalize its forecast of installed photovoltaic capacity, and can then estimate the energy production associated with the forecast.  The report does repeat 2014's forecast of energy as illustrative, keeping in mind that actual amounts of energy generated from solar photovoltaic capacity in New England will likely be higher if capacity forecasts are revised upward as is proposed in this draft.

The 2015 draft PV report is now under review by ISO New England's Distributed Generation Forecast Working Group.  That group next meets on April 14, where the final draft forecast will be presented.

Controversy over renewable energy claims

Thursday, March 5, 2015

If an electric utility generates power from renewable resources and sells renewable energy certificates representing the renewable attributes of that energy, can it still call the underlying power "renewable"? No, according to the U.S. Federal Trade Commission.

Solar panels in the Utah desert.

While this question may seem metaphysical, it arises from the structure of most U.S. renewable energy markets.  Most states have adopted renewable portfolio standards, which require utilities and competitive electricity suppliers to source some of their power from renewable resources.  In most cases, utilities and suppliers can satisfy this requirement by using renewable energy certificates or credits known as RECs.  While each state's program differs, these RECs typically represent the renewable attributes of electric energy -- the right to claim that energy is renewable -- but are distinct from that underlying energy.  As a result, a renewable generator can sell RECs to one buyer and the underlying energy to another.

Vermont utility Green Mountain Power Corporation recently found itself at the center of controversy over its claims regarding renewable energy.  The utility owns and is involved with a variety of renewable energy generation projects in Vermont, including wind and solar projects.  It sells energy produced from these projects to Vermont customers, while simultaneously selling some of the RECs generated by these sources to out of state utilities.

In 2014, concerns over "double counting" of renewable energy attributes led Connecticut to ban the use of RECs from renewable generation that also is counted toward another state’s renewable goals for meeting Connecticut's requirements, and REC marketer NextEra Energy to notify New England market participants that it would no longer buy Vermont RECs.

On September 15, 2014, a group of petitioners asked the Federal Trade Commission to investigate Vermont utility Green Mountain Power Corporation's claims that it is providing its customers with electricity from renewable sources such as commercial wind and solar projects, given its separate sale of the RECs to out of state utilities.  The Federal Trade Commission regulates claims about the environmental impacts of commerce under Section 5 of the Federal Trade Commission Act, including claims regarding the production, sale, and use of renewable energy.  In their complaint, the petitioners claimed that "Vermont customers are being misled into thinking that they are buying 'renewable energy,' when in fact what they are getting is 'null' electricity consisting of a mix of fossil fuel, nuclear, gas and other 'brown' sources of electricity from the regional grid."

The FTC responded to this petition in February 2015 by issuing a letter to Green Mountain Power's counsel expressing concern that the utility might have created confusion for its customers about the renewable attributes of the power they purchased by not “clearly and consistently communicating” that it sells RECs for most of its renewable energy-generating facilities to entities outside Vermont.  In the letter, the FTC said that it had not found that any Green Mountain Power statements violated the Federal Trade Commission Act.  However, the Commission urged Green Mountain Power in the future to prevent any confusion by clearly communicating the implications of its REC sales for Vermont customers and REC purchasers.

The FTC letter represents the latest salvo in efforts to regulate claims regarding the production, sale, and use of renewable energy.  To help marketers avoid making deceptive environmental claims, for over 20 years the FTC has issued "Green Guides" providing its administrative interpretation of the law. The Green Guides outline general principles that apply to all environmental marketing claims and provide guidance regarding many specific environmental benefit claims, including renewable energy claims.  The Green Guides, as well as the recent FTC letter, illustrate the importance of caution in making claims about renewable energy in business activities.

North Carolina offshore wind environmental assessment

Tuesday, February 17, 2015

The U.S. Department of the Interior's Bureau of Ocean Energy Management has released an environmental assessment of the impacts of leasing sites off the North Carolina coast for offshore wind projects.  This milestone supports the Obama administration's plan to offer site leases on the outer continental shelf for renewable energy projects.

Since 2012, BOEM has solicited public comment on the prospect of leasing about 307,590 acres off North Carolina for potential offshore wind development.  BOEM has identified three Wind Energy Areas offshore North Carolina:
  • the Kitty Hawk Wind Energy Area (about 122,405 acres), beginning about 24 nautical miles (nm) from shore and extends approximately 25.7 nm in a general southeast direction;
  • the Wilmington West Wind Energy Area (about 51,595 acres), beginning about 10 nm from shore and extends approximately 12.3 nm in an east-west direction at its widest point; and
  • the Wilmington East Wind Energy Area (about 133,590 acres), beginning about 15 nm from Bald Head Island at its closest point and extends approximately 18 nm in the southeast direction at its widest point.

BOEM's map of North Carolina Wind Energy Areas.
On January 22, 2015, BOEM announced the availability of an environmental assessment for public review and comment.  Under the National Environmental Policy Act or NEPA, an environmental assessment or EA considers the potential impacts of proposed federal action and analyzes reasonable alternatives to the proposed action.  In this case, the action proposed is BOEM's issuance of commercial wind leases and allowing of site characterization and assessment activities on the Atlantic Outer Continental Shelf offshore North Carolina.

BOEM's environmental assessment for North Carolina offshore wind leasing provides the framework for potential federal lease auctions for North Carolina offshore wind sites.  The environmental assessment is available for public comment through February 23, 2015. 

Apple makes California solar deal

Thursday, February 12, 2015

Electronics manufacturer Apple has announced an $848 million deal to buy electricity from a solar energy project to be developed in California. Project developer First Solar has described the power purchase agreement as "the largest agreement in the industry to provide clean energy to a commercial end user."

Solar photovoltaic panels in the Utah desert.

Earlier this week, Apple announced the deal with First Solar, Inc., to buy power from First Solar's California Flats Solar Project in Monterey County, California.  Under a 25-year power purchase agreement or PPA, Apple will buy the equivalent of 130 megawatts of the solar project's output. 

First Solar is a vertically-integrated solar company, manufacturing solar photovoltaic panels, developing utility-scale photovoltaic power plants, and providing solar project support services.  First Solar boasts involvement with over 10 gigawatts of installed solar photovoltaic capacity worldwide.  Its resume includes the 550-megawatt Topaz Solar project in California and the 290-megawatt Agua Caliente project, which was once the world's largest operating solar energy project.

First Solar's California Flats Solar Project will occupy a 2,900-acre site on the Jack Ranch in Cholame, California.  Owned by Hearst Corporation, the project site was formerly a dryland farm, and occupies about 3% of the Jack Ranch property.  First Solar expects to begin construction later this year, and to complete the project by the end of 2016.

With a total project capacity of 280 megawatts, Apple's 130-megawatt commitment covers about 46% of the project's output.  The project's remaining 150 megawatts will be sold to utility Pacific Gas & Electric under a separate long-term PPA.

Apple has developed other renewable energy projects, including fuel cells and solar panels at its Maiden, North Carolina data center.  Other high-tech companies have also made significant investments in renewable energy, including Google's commitment of over $1.5 billion to solar and wind projects through power purchase agreements and direct investments.

2014: natural gas, wind, solar led new projects

Friday, January 30, 2015

Natural gas, wind, and solar power projects dominated the rankings of new U.S. electric generation placed in service in 2014.

According to the Federal Energy Regulatory Commission staff's December 2014 Energy Infrastructure Update, developers placed in service 15,384 megawatts of new utility-scale electric generation capacity in 2014.  This new capacity buildout is within 4% of 2013's figure (15,886 megawatts).

Of 2014's new generating capacity, nearly half (7,485 megawatts, or 49%) is powered by natural gas.  U.S. production of natural gas has increased significantly in recent years, and natural gas prices have decreased in most regions of the country.  At the same time, new environmental regulations have made historically dominant coal relatively more expensive as a fuel source, while relatively low carbon emissions have made natural gas more attractive.  2014 thus continued the trends of coal-fired power plant retirement and the construction of new natural gas-fired generating capacity.

Wind represents the next largest category of new U.S. electric generating capacity placed in service in 2014.  Nearly 27% of 2014's new capacity, or 4,080 megawatts, is powered by wind.  As President Obama noted in his 2015 State of the Union address, the U.S. has more wind energy supplying its electrical grid than any other country.

Solar energy represents the third largest category of new generation placed in service last year.  Over 20% of new 2014 capacity, or 3,139 megawatts, is powered by solar energy.  The rapid growth of solar energy in the U.S. was also featured in President Obama's 2015 State of the Union speech, in which he noted, "Every three weeks, we bring online as much solar power as we did in all of 2008."

Combined, these three energy sources (natural gas, wind, and solar) account for over 95% of all new utility-scale generation capacity placed in service in 2014. Of the remaining capacity, biomass took the largest share (1.6% of total new capacity), with a diverse mix of other sources including water power, coal, and nuclear rounding out the list.  Notably, renewable sources including wind, solar, biomass, and hydropower account for nearly half of all new capacity placed in service in 2014.

What will 2015 bring?

Federal offshore wind auction held for sites off Massachusetts

Thursday, January 29, 2015

Federal ocean energy managers have concluded an auction to lease over 350,000 acres off the Massachusetts coast to prepare for offshore wind development.  Of the four parcels up for bid in today's auction, one was provisionally awarded to RES America Developments, Inc. and another to Offshore MW LLC.  Two other parcels failed to attract any bids.

Onshore wind turbines near the Massachusetts coast.
In today's auction conducted by the Interior Department’s Bureau of Ocean Energy Management (BOEM), RES America Developments, Inc. provisionally won the rights to Lease OCS-A 0500 (187,523 acres) after two rounds of bidding, with a winning bid of $281,285.  Offshore MW LLC provisionally won the rights to Lease OCS-A 0501 (166,886 acres) after two rounds of bidding, with a winning bid of $166,886.  These winning bids are significantly below those that were required to win previous federal competitive lease sales for offshore wind sites.

While today's lease awards are a step forward for U.S. offshore wind, neither lease awarded today grants the right to construct or operate an offshore wind project.  Rather, these leases have a preliminary term of one year, to allow the lessee time to prepare a Site Assessment Plan describing the installation of meteorological towers and buoys and other activities the lessee plans to perform to assess local wind resources and ocean conditions.  Site Assessment Plans must be submitted to BOEM for review and approval.

Once BOEM approves a Site Assessment Plan, the lessee will then have up to five years in which to prepare and submit to BOEM a Construction and Operations Plan (COP) providing detailed information for the construction and operation of a wind energy project on the lease.  After BOEM receives a Construction and Operations Plan from a lessee, BOEM will conduct an environmental review of and public comment period for the proposed project.  If BOEM approves a Construction and Operations Plan, the lessee will have an operations term of 25 years.

Lease OCS-A 0502 (248,015 acres) and Lease OCS-A 0503 (140,554 acres) did not receive bids in today's auction.  As shown on a BOEM nautical chart of the Massachusetts Wind Energy Area, these lease areas are generally farther from the Massachusetts coast than the areas awarded through today's auction.

BOEM touts its offshore wind leasing program as part of President Obama’s Climate Action Plan.  The auction held today by BOEM represents the nation’s fourth competitive lease sale for renewable energy sites in federal waters.  Including this auction, competitive lease sales have generated more than $14.5 million in high bids for more than 700,000 acres in federal waters.  Previous auctions covered sites off Rhode Island and Massachusetts, Virginia, and Maryland.  BOEM expects to hold another competitive lease sale offshore the New Jersey coast in 2015.  

FERC and EPA's Clean Power Plan

Wednesday, January 28, 2015

Following the U.S. Environmental Protection Agency's 2014 proposal to regulate carbon emissions from electric power plants and other major sources, federal energy regulators have scheduled a series of public technical conferences on how the Clean Power Plan may affect electric reliability, wholesale electric markets and operations, and energy infrastructure.

On June 2, 2014, the U.S. Environmental Protection Agency announced the Clean Power Plan, its proposed rule under Section 111(d) of the Clean Air Act to reduce carbon emissions from the nation's power plants.  Designed to reduce carbon emissions 30 percent below 2005 levels by 2030, EPA's proposal would impose limits on each state's rate of carbon emissions per megawatt-hour of electric energy generated.

The Federal Energy Regulatory Commission regulates the transmission and wholesale sales of electricity in interstate commerce, monitors energy markets, and protects the reliability of the high voltage interstate transmission system.  Acting out of concern over the possible impacts of the EPA Clean Power Plan on its regulated sector, on December 9, 2014, the Commission scheduled a series of technical conferences to develop public comment on these issues.

First, the Commission will hold a National Overview technical conference on February 19, 2015, at its Washington, DC headquarters.  Earlier this month, the Commission issued a supplemental notice describing the agenda for the National Overview.  After an introduction by EPA, the Commission expects to discuss:
  • Electric reliability considerations: How will the Clean Power Plan affect electric reliability?  How can the U.S. sustain reliability as states and regions develop their plans to comply with the proposed carbon rule?  How could state, regional, and federal plans for compliance affect grid operations?  What tools are available to identify potential reliability impacts?  How can reliability planning processes and compliance planning efforts  coordinated to address potential issues?  What is the Commission's role in this area?
  • Identifying and addressing infrastructure needs: What potential infrastructure needs may arise from various state or regional compliance approaches?  How can any infrastructure needs met in a timely manner in order to ensure system reliability?  How can relevant planning entities, industry, and states coordinate reliability and infrastructure planning and siting processes with state and/or regional environmental compliance efforts to ensure the adequate and timely development of new infrastructure?  Are additional mechanisms needed to ensure timely development of new infrastructure? Are adaptations to current Commission policies needed to facilitate the infrastructure needed for compliance with the proposed Clean Power Plan?
  • Potential implications for Commission-jurisdictional markets:  How could potential compliance approaches to the proposed Clean Power Plan impact Commission-jurisdictional electric and natural gas markets?  What aspects, if any, of the wholesale and interstate markets would facilitate implementation of state or regional compliance plans?  What tools are available to address market issues as they arise?  What opportunities are available to coordinate compliance approaches with Commission-jurisdictional markets to meet the requirements of the proposed Clean Power Plan rule?
Following the National Overview, the Commission has scheduled three regional conferences in February and March 2015.

Natural Gas Pipeline Permitting Reform Act

Monday, January 26, 2015

Last week, the U.S. House of Representatives voted to pass a bill to expedite federal review of some spects of proposed natural gas pipelines.  Known as H.R. 161, the Natural Gas Pipeline Permitting Reform Act is officially summarized as providing for the "timely consideration of all licenses, permits, and approvals required under Federal law with respect to the siting, construction, expansion, or operation of any natural gas pipeline projects."  If enacted into law, what would H.R. 161 do?

Congress debates proposed reforms to the natural gas pipeline permitting process.
Relatively brief for federal legislation, the printed draft of H.R. 161 comes in at just 3 pages.  Overall, it defines and accelerates the timelines for federal approvals of some proposed natural gas pipelines.  If enacted, the bill would give the Federal Energy Regulatory Commission one year to decide whether or not to issue a pipeline permit, following which other federal agencies would have 90 days to issue any ancillary permits.

The pipelines that would benefit from this bill are those that have applied to the Federal Energy Regulatory Commission under Section 7 of the Natural Gas Act (15 U.S.C. 717f) for a certificate of public convenience and necessity, and have used the Commission's "prefiling" process.

First, H.R. 161 amends Section 7 of the Natural Gas Act to require the Federal Energy Regulatory Commission to approve or deny an application for a certificate of public convenience and necessity for a prefiled project not later than 12 months after receiving a complete application that is ready to be processed.

Second, H.R. 161 requires any agency responsible for issuing any license, permit, or approval required under Federal law in connection with a prefiled project for which a certificate of public convenience and necessity is sought under the Natural Gas Act to approve or deny the issuance of the license, permit, or approval not later than 90 days after the Commission issues its final environmental document relating to the project.  Generally speaking, if such as agency cannot complete its review process within this timeline, it is compelled to deny the license, permit, or approval, but H.R. 161 would allow the Commission to extend the 90 day deadline by an additional 30 days.  H.R. 161 also changes federal law to provide that in the case of agency inaction within the 90 day time period or extra 30 day period, the requested license, permit, or approval shall take effect upon the expiration of 30 days after the end of such period.

On January 22, the House voted 253-169 in favor of the bill.  It now goes before the Senate.  But on January 20, the Executive Office of the President issued a statement of administrative policy stating, "If the President were presented with H.R. 161, his senior advisors would recommend that he veto the bill."  In that administrative policy statement, the administration acknowledged the need for additional energy infrastructure and supports the timely consideration of project applications, but notes risks from that H.R. 161.  These risks include effective limits on public participation in pipeline review processes, and that agencies may be forced to make decisions based on incomplete information or information that may not be available.  The executive branch's statement also cites a FERC report that since Fiscal Year 2009, FERC has completed action on 91 percent (512 out of 563) of all pipeline applications that it has received within one year of receipt, with the remaining decisions involving complex proposals that merit additional review and consideration.

Will the Natural Gas Pipeline Permitting Reform Act be enacted into law?  How will its enactment -- or non-enactment -- affect proposed new natural gas pipelines, and the customers they would serve?

FERC issues EIS for Algonquin Incremental Market gas project

Friday, January 23, 2015

Staff of the Federal Energy Regulatory Commission have issued a final Environmental Impact Statement for a proposed natural gas transmission project connecting New York and New England.  In that report, Commission staff found that Algonquin Gas Transmission, LLC's Algonquin Incremental Market Project would result in some adverse environmental impacts, but that most of these impacts could be mitigated and reduced to less-than-significant levels.

A marker for the Williams Northwest Pipeline in Arches National Park, Utah.
 Algonquin Gas Transmission, LLC -- a subsidiary of Spectra Energy Partners, LP -- already owns a natural gas pipeline and transmission network running from the Texas Eastern Transmission system in New Jersey to the Maritimes & Northeast system near Boston.

In 2014, Algonquin proposed the Algonquin Incremental Market project.  The AIM project's would provide firm transportation service of 342,000 dekatherms per day of natural gas to local distribution companies and municipal utilities in Connecticut, Rhode Island, and Massachusetts.  Algonquin’s stated objectives for the Project are:
  • to provide the pipeline capacity necessary to transport additional natural gas supplies to meet the immediate and future load growth demands of local gas utilities in southern New England;
  • eliminate capacity constraints on existing pipeline systems in New York State and southern New England;
  • provide access to growing natural gas supply areas in the Northeast region to increase competition and reduce volatility in natural gas pricing in southern New England;
  • improve existing compressor station emissions through the replacement of existing compressor units with new, efficient units; and
  • provide the additional service by November 2016.

As envisioned by Algonquin, the project will include the construction and operation of about 37.4 miles of natural gas pipeline in New York, Connecticut, and Massachusetts.  The project entails replacing some segments of existing pipeline, extending an existing loop pipeline to increase the system's capacity to ship gas, and installing some new pipeline.  It also includes modifications to six existing compressor stations, modifying existing meter and regulating stations, and the construction of 3 new meter and regulation stations.

Under federal law, Algonquin needs authorization from the Federal Energy Regulatory Commission to construct and operate the AIM project.  Algonquin filed its application to the FERC on February 28, 2014.  As part of the FERC's review process, the National Environmental Policy Act requires the agency to analyze and document the environmental effects of proposed federal actions such as granting Algonquin's application.

In Algonquin's case, that documentation took the form of a Final Environmental Impact Statement issued by the FERC staff today. In the final EIS, FERC's environmental analysts conclude that construction and operation of the AIM project would result in some adverse environmental impacts. However, FERC staff found that most of these impacts would be reduced to less-than-significant levels with the implementation of mitigation measures and plans proposed by Algonquin, along with additional measures recommended by the FERC staff.  Staff pointed to factors including the degree to which proposed AIM project pipeline facilities would be within or adjacent to existing rights-of-way, the planned use of the horizontal directional drill method to cross the Hudson and Still Rivers, which would avoid any direct impacts on these resources, as well as plans to minimize impacts on natural and cultural resources during construction and operation of the Project.

With the final Environmental Impact Statement issued, the FERC Commissioners will consider its staff's recommendations in making a final a decision on the AIM project.  Multiple studies have highlighted the need for up to 2 billion cubic feet per day (Bcf/d) of new pipeline capacity into New England and neighboring markets to improve reliability and reduce the cost to consumers of electricity and natural gas.  At a planned size of 342,000 dekatherms (or 0.342 Bcf) per day, the AIM project is relatively small in capacity compared to other proposed projects such as Tennessee Gas Pipeline Company, L.L.P.'s proposed Northeast Energy Direct Project, which is designed to be scalable up to 1.2 to 2.2 billion cubic feet per day of natural gas capacity.  Which pipelines end up being approved and built will shape the New England energy landscape in the coming years.

Energy and State of the Union 2015

Thursday, January 22, 2015

President Obama delivered his 2015 State of the Union address on January 20, 2015.  In his remarks as prepared for delivery, he addressed energy-related themes including the growth of U.S. energy resource production and climate change.

As in his 2013 and 2014 addresses, increased domestic production of energy resources featured prominently in the 2015 State of the Union speech, for its economic, political, and national security benefits:
At this moment – with a growing economy, shrinking deficits, bustling industry, and booming energy production – we have risen from recession freer to write our own future than any other nation on Earth.  It’s now up to us to choose who we want to be over the next fifteen years, and for decades to come...
We believed we could reduce our dependence on foreign oil and protect our planet.  And today, America is number one in oil and gas.  America is number one in wind power.  Every three weeks, we bring online as much solar power as we did in all of 2008.  And thanks to lower gas prices and higher fuel standards, the typical family this year should save $750 at the pump.
During the past several years, U.S. production of oil and natural gas has increased significantly.  According to the U.S. Energy Information Administration, total U.S. crude oil production averaged an estimated 9.2 million barrels per day (bbl/d) in December 2014, and forecasts for oil productino continue to grow.  EIA predicts that projected crude oil production will reach 9.5 million bbl/d in 2016, constituting the second-highest annual average level of production in U.S. history (after 9.6 million bbl/d in 1970.)

EIA also predicts continued growth in the use of renewable energy resources to produce electricity and heat. In 2014, 6.4% of electric generation came from hydropower and 6.7% from nonhydropower renewables. EIA projects continued growth of nonhydropower renewables, reaching an electricity generation share of 7.9% by 2016.  Wind is the largest source of nonhydropower renewable generation, and it is projected to contribute 5.3% of total electricity generation in 2016.

President Obama also addressed climate change in this year's State of the Union address, and his administration's efforts to combat and mitigate its effects:
2014 was the planet’s warmest year on record.  Now, one year doesn’t make a trend, but this does – 14 of the 15 warmest years on record have all fallen in the first 15 years of this century. 
I’ve heard some folks try to dodge the evidence by saying they’re not scientists; that we don’t have enough information to act.  Well, I’m not a scientist, either.  But you know what – I know a lot of really good scientists at NASA, and NOAA, and at our major universities.  The best scientists in the world are all telling us that our activities are changing the climate, and if we do not act forcefully, we’ll continue to see rising oceans, longer, hotter heat waves, dangerous droughts and floods, and massive disruptions that can trigger greater migration, conflict, and hunger around the globe.  The Pentagon says that climate change poses immediate risks to our national security.  We should act like it.
That’s why, over the past six years, we’ve done more than ever before to combat climate change, from the way we produce energy, to the way we use it.  That’s why we’ve set aside more public lands and waters than any administration in history.  And that’s why I will not let this Congress endanger the health of our children by turning back the clock on our efforts.  I am determined to make sure American leadership drives international action.  In Beijing, we made an historic announcement – the United States will double the pace at which we cut carbon pollution, and China committed, for the first time, to limiting their emissions.  And because the world’s two largest economies came together, other nations are now stepping up, and offering hope that, this year, the world will finally reach an agreement to protect the one planet we’ve got.
His 2015 remarks on climate change reflect a belief or fear that Congress will not act on the issue, or will act to frustrate the Obama administration's efforts on climate change.  In 2013, President Obama asked Congress to develop a market-based solution to climate change, but said he would take executive action if Congress failed to act.  In 2014, he noted Congress's apparent unwillingness to act, and highlighted his administration's proposed new standards on power plant emissions of carbon.  This year's remarks continue the trend of featuring executive-branch solutions, and downplaying the likelihood of near-term legislative support.

Will U.S. production of energy continue to grow?  What economic, political, and national security impacts will flow from the shifts in and growth of the U.S. energy sector?  Will the U.S. continue to act -- or take more serious action -- on climate change?  The remainder of 2015 -- and of President Obama's term in office, which runs into January 2017 -- will show how these themes evolve.

Topaz Solar becomes largest solar power project

Tuesday, January 6, 2015

A recent expansion has made a California solar energy project the world’s largest solar facility. Built in three phases, MidAmerican Renewables LLC’s Topaz Solar project in San Luis Obispo County now sports 550 MW total generating capacity.

A small distributed solar photovoltaic installation in Arches National Park, Utah -- much smaller than the Topaz Solar project.

Iowa-based MidAmerican Renewables LLC is a subsidiary of Berkshire Hathaway Energy formed to handle its expansion into the unregulated renewables market.  Its subsidiaries MidAmerican Solar, MidAmerican Wind, MidAmerican Geothermal and MidAmerican Hydro each focus on particular types of renewable energy generating technology.  In all, MidAmerican controls over 3,000 MW of renewable generating capacity in the U.S.

MidAmerican acquired the Topaz Solar project from First Solar in January 2012, after First Solar had acquired previous project developer OptiSolar, Inc.  Project construction began in November 2011, and proceeded in three phases.  Earlier phases came online in February 2013 and in January 2014, for a total of 300 MW of capacity.  With the recent expansion, the 550-megawatt project includes over 8 million photovoltaic modules, installed on 4,700 acres of the Carrizo Plain in the southern California desert.

The power produced by the project is sold to utility Pacific Gas and Electric Company under a 25-year power purchase agreement.  Topaz Solar won the long-term contract rights through its response to a 2007 solicitation by PG&E for renewable power.

According to the Federal Energy Regulatory Commission, the Topaz Solar project is now the world's largest solar energy plant.

FERC rules tribes exempt from some energy regulation

Tuesday, December 16, 2014

When a Native American tribe acquires a hydroelectric power plant licensed by the Federal Energy Regulatory Commission, does the project become exempt from some federal regulations?

Yes, according to a FERC order recently issued to the Confederated Salish and Kootenai Tribes of the Flathead Reservation.

The tribes are poised to become the first American Indian tribe to own and operate a Commission-licensed hydroelectric power plant, the Kerr Hydroelectric Project.  Docketed by FERC as Project No. 5, the Kerr Project consists of a reservoir, dam, penstocks, 196-megawatt power plant, and related assets located on Flathead Lake and Flathead River, mostly within the Tribes’ treaty-reserved Flathead Reservation.

The Commission issued the Kerr Project's current license on July 17, 1985, with a 50-year term.  Under the terms of a settlement between Montana Power Company and the Tribes as competing applicants for the license, the utility and the Tribes were joint licensees, and after a term of thirty years, the license allows the project to be transferred to full ownership by the Tribes.  While Montana Power Company's interests were sold to PPL Montana, LLC and ultimately transferred to Northwestern Corporation, the Tribes are slated to take over the project on September 5, 2015. On this date of conveyance, the Tribes will be the sole owner and operator of the Kerr Project, through and until the license expires on September 4, 2035.

In anticipation of that conveyance, the Tribes and their wholly owned operating company known as Energy Keepers, Inc. or EKI petitioned the Commission for a declaratory order finding that they are exempt public utilities under section 201(f) of the Federal Power Act and that they are not required to maintain or make available their books and records to the Commission under the Public Utility Holding Company Act of 2005 and related regulations.

Section 201(f) of the FPA provides exemptions from the Commission’s authority under most provisions of Part II of the FPA for “the United States, a State or any political subdivision of a state, or any agency, authority or instrumentality of any one or more of the foregoing, or any corporation which is wholly owned, directly or indirectly, by any one or more of the foregoing.”  This exemption is generally viewed as applicable to "governmental entities."  The Public Utility Holding Company Act of 2005, or PUHCA 2005, requires holding companies to provide the Commission access to their books and records. 

Based on the facts as presented in the Petition, the Commission determined that the Tribes and EKI are exempt public utilities as defined in section 201(f) of the Federal Power Act.   The Commission found that the Tribes are an “agency, authority or instrumentality” of the “United States, a State or any political subdivision of a state,” and that their wholly owned subsidiary EKI assists the Tribes in performing their inherent government functions.

The Commission also concludes that PUHCA 2005 and relevant Commission regulations do not apply to the Tribes and EKI.  The Commission found that EKI will operate the Kerr Project for the generation, transmission, or distribution of electric energy for sale and is thus an electric utility company, and thus a public utility company under PUHCA 2005 -- and therefore the Tribes are a holding company under PUHCA 2005.  However, because the Tribes are an exempt governmental entity, they are exempt from its books and records requirement.

The Commission thus determined that the Confederated Salish and Kootenai Tribes will be exempt from many parts of Part II of the Federal Power Act and the books and records requirement of PUHCA 2005.  While the Tribes are not scheduled to take over the Kerr Project until September 2015, they want to be able to secure contracts to sell the project's power well in advance.  The Commission's declaratory order reduces regulatory uncertainty, facilitating the Tribes' efforts to sell the project's future power into the Pacific Northwest electricity market.

Developer applies to VT for Clean Power Link transmission line

Friday, December 12, 2014

A proposed electric transmission line from Quebec into New England took a step forward this week, as the developer of the New England Clean Power Link applied to Vermont regulators for key project approvals.

Transmission Developers Inc. subsidiary TDI New England has proposed the New England Clean Power Link to bring Canadian hydropower and other electricity to the renewable-hungry New England market.  With an estimated project cost of $1.2 billion, the 1000-megawatt high-voltage direct-current transmission line would run under Lake Champlain and underground to a converter station in Ludlow, Vermont, near where it would connect to the existing electric grid owned by Vermont Electric Power Company (VELCO).

Under Vermont law, the state Public Service Board regulates many aspects of the electric grid.  Section 248 of Title 30 of Vermont's statutes requires companies to obtain approval from the Board before beginning site preparation or construction of electric transmission facilities, electric generation facilities and certain gas pipelines within Vermont.  For facilities like the proposed transmission line, that Board approval comes in the form of a Certificate of Public Good. 

On December 8, 2014, TDI subsidiary Champlain VT, LLC d/b/a TDI New England applied to the Board for a Certificate of Public Good for the project.  TDI's petition notes that the project "would contribute to meeting State and regional energy and sustainability goals and result in millions of tons/year in reduced greenhouse gas emissions by replacing electricity generated by fossil fuels," and that running cables under the lake and underground avoids adverse impacts from above-ground installations.  Other benefits touted by TDI include economic development (with about $1.5 billion in claimed economic benefits to Vermont and the entire region over the project's 40-year life), improved electric reliability and fuel diversity, and help in mitigating the impacts of the anticipated loss of the Vermont Yankee nuclear station and other major power plants.

TDI's proposal includes components specifically designed to yield local community benefits and thus to cultivate local support for the project.  These components include creating $122 million in funds to improve Lake Champlain's water quality, habitat, and recreational values, plus another $40 million for Vermont's Clean Energy Development Fund.

TDI's project now comes before the Vermont Public Service Board for review.  The project also needs a presidential permit issued by the U.S. Department of Energy to cross the international boundary, as well as a U.S. Army Corps of Engineers permit for impacts to water resources.

At the same time, another transmission line has been proposed under Lake Champlain, namely the $2.2 billion Champlain Hudson Power Express meant to connect Quebec to New York City.

FERC plans conferences on EPA carbon rule impacts

Thursday, December 11, 2014

If the U.S. Environmental Protection Agency's proposed carbon regulations for power plants are adopted, how will state and regional efforts to comply with the rule impact the electric power grid?  If states need new infrastructure like electric transmission lines or natural gas pipelines to comply with the EPA rule, what can be done to reduce regulatory barriers to new infrastructure development?

A fossil fuel-fired power plant near New York, NY.
The EPA's proposed Clean Power Plan rule would require states to meet customized standards for how much carbon dioxide their electric power sector emits per unit of useful energy.  As envisioned by EPA, each state can choose its own path to meeting these standards by combining elements from a menu of four "building blocks": better coal plant efficiency, increased utilization of natural gas plants, increased renewable energy, and increased energy efficiency.

The implications of different approaches to complying with the proposed rule will be the focus of an upcoming series of technical conferences to be held by the Federal Energy Regulatory Commission.  According to the Commission's public notice, state, regional and/or federal plans for compliance with the proposed Clean Power Plan may impact Commission-jurisdictional markets, grid operations, and infrastructure.  The series of technical conferences is designed to provide forums for identifying issues and solutions.  The Commission also plans to provide an opportunity to discuss how compliance scenarios may impact existing infrastructure and drive the need for additional infrastructure, especially new electric transmission and natural gas pipeline facilities, and whether there are regulatory barriers that need to be addressed, and by whom, to ensure the timely development of those facilities.

The conferences will begin with a Commission-led National Overview session at FERC headquarters on February 19, 2015.  The National Overview will address whether regulators and industry have the appropriate tools to identify any reliability or market issues that may arise, potential strategies for compliance with the EPA regulations and coordination with FERC-jurisdictional wholesale and interstate markets, and how to coordinate reliability and infrastructure planning processes with state and/or regional environmental compliance efforts to ensure the adequate development of new infrastructure and to manage any potential reliability and operational impacts of proposed compliance plans. The Commission will offer a live webcast of the National Overview, which will be archived for three months.

Following the National Overview technical conference, the Commission will hold three regional technical conferences, on dates to be announced, in Washington, DC, St. Louis, MO, and Denver, CO.  Each regional event will include discussion of the specific potential impacts to regional reliability, power system operations and generator dispatch, and needed infrastructure upgrades.

Will the EPA's Clean Power Plan be finalized and take effect?  If so, when -- and in what form?  Federal carbon emission limits are as yet untested in the U.S., and other innovative regulatory efforts have met with years or even decades of delay before taking effect.  At the same time, the prospect of federal carbon rules affecting the electric power sector spurs energy regulators to take a serious look at potential impacts of the carbon rules, and to begin planning for their possible future effectiveness.

Salem power plant wins market deferral

Wednesday, December 10, 2014

Federal regulators have granted a request by the developer of a power plant in Salem, Massachusetts, to defer its commitment to provide power to the New England market.  The process reflects challenges inherent to developing power plants in the Boston area, as well as methods to mitigate the impacts of those challenges.

Stacks of the former Salem Harbor Power Station, before its decommissioning.

Footprint Power Salem Harbor Development LP is in the process of redeveloping the site of a defunct coal-powered generation plant.  The former Salem Harbor Power Station could produce up to 745 megawatts of power, fueled by coal and oil.  In 2010, Footprint identified the site as a potential facility for redevelopment and, on August 3, 2012, it acquired the plant from Dominion Energy Salem Harbor, LLC.  Footprint now plans to build what the Federal Energy Regulatory Commission has described as two state-of-the art, efficient, low-emission, quick-start natural gas turbine generators; two steam-turbine generators; and two heat-recovery steam generators, including pollution control equipment, with aggregate generating capacity of 674 megawatts.

The New England electricity market compensates generators and other resources for two main products: energy and capacity.  Energy represents the volume of power sold by a market participant (measured in megawatt-hours), while capacity represents the intended full-load sustained output of a facility (measured in megawatts).  Regional grid operator ISO New England, Inc. operates a forward capacity market, under which generators can lock in the payments for capacity several years in advance of actually operating.  This structure is designed to ensure that the region has sufficient generating capacity to meet future needs, as well as to help new generation projects secure financing and be built despite long permitting and construction lead times.

Footprint bid its proposed natural gas power plant into New England's seventh Forward Capacity Auction, also known as FCA7.  That auction was held in February 2013, and gave Footprint a future capacity market revenue stream in exchange for the obligation to provide capacity over a one-year capacity commitment period starting on June 1, 2016.  According to Footprint, it then had 39 months to obtain all necessary permits, secure financing arrangements and complete construction of the plant, a process that had never been tested for a new plant not subsidized or sponsored by a state.

While Footprint secured many of the necessary permits promptly, one permit in particular -- a federal Prevention of Significant Deterioration (PSD) permit under the Clean Air Act -- took longer than expected.  Obtaining a PSD permit from the Massachusetts Department of Environmental Protection, acting under federally delegated authority, involves a five-phase process: (1) pre-application; (2) application; (3) draft permit preparation; (4) public participation; and (5) final decision to issue or deny a PSD permit.  While Footprint finally obtained its PSD permit -- and survived a last-minute appeal of that permit's issuance -- Footprint says the delay and revenue uncertainty the resulting uncertainty of revenues impaired its ability to finance the project. While Footprint had exercised an option to lock in its capacity rates for five years, without the deferral one full year of stable revenue would be lost, making potential lenders and equity providers unwilling to provide financing.

Under ISO-NE's tariff, a market participant may seek a deferral of its capacity supply obligation if three criteria are met.  First, the resource must first request and receive from ISO-NE a written reliability determination indicating that the absence of the resource's capacity would result in a transmission system reliability issue in both the associated Capacity Commitment Period and the next Capacity Commitment Period.  If ISO-NE makes such a determination, then the resource may file with the Federal Energy Regulatory Commission for a one-year deferral of its Capacity Supply Obligation. The resource must include in its filing to the Commission (1) the reliability determination from ISO-NE; (2) a demonstration that the project's development delay is due to factors beyond the control of the resource; and (3) a demonstration that the deferral is critical to the resource's ability to achieve commercial operation.

Footprint applied to the Commission for such a deferral on October 7, 2014.  On December 5, the Commission granted Footprint's request.  The Commission noted that ISO-NE had issued a reliability determination finding that the Footprint facility is needed for reliability in the 2016-2017 Capacity Commitment Period and the subsequent 2017-2018 period, that Footprint had demonstrated that it has failed to achieve commercial operation on time due to factors beyond its control, and that Footprint has demonstrated that the deferral is critical to the Facility’s ability to achieve commercial operation.

Footprint's experience highlights several key dynamics affecting New England power plant development.  The story is framed by the retirement of an aging coal plant and its replacement with natural gas-fired generation, a trend occurring across the U.S.  It features the challenges of securing necessary environmental permits and surviving appeals by project opponents.  Footprint's experience also highlights the features of the New England forward capacity market, and how it affects developers of new power plants.

US Presidential Permits for cross-border infrastructure

Monday, December 8, 2014

As the U.S.'s international trade in energy grows, so too has interest in the process for securing a federally required approval known as a Presidential Permit.

A marker shows the route of a natural gas pipeline in Utah.

The construction, operation, and maintenance of infrastructure that crosses the U.S.'s border with Mexico or Canada -- think pipelines, transmission lines, and bridges -- generally requires prior authorization by the federal government in the form of a Presidential Permit.  How you obtain a Presidential Permit depends on the type of facilities in question, as permits may be issued by several federal agencies under different legal authorities.

Presidential permits for oil, petroleum products, and other liquids pipelines have been issued by the U.S. State Department since since the promulgation of Executive Order 11423 in 1968.  Executive Order 11423 provided that, except with respect to cross-border permits for electric energy facilities, natural gas facilities, and submarine facilities:
The Secretary of State is hereby designated and empowered to receive all applications for permits for the construction, connection, operation, or maintenance, at the borders of the United States, of: (i) pipelines, conveyor belts, and similar facilities for the exportation or importation of petroleum, petroleum products, coal, minerals, or other products to or from a foreign country; (ii) facilities for the exportation or importation of water or sewage to or from a foreign country; (iii) monorails, aerial cable cars, aerial tramways and similar facilities for the transportation of persons or things, or both, to or from a foreign country; and (iv) bridges, to the extent that congressional authorization is not required.
The State Department's Bureau of Energy Resources Office of Energy Diplomacy receives and processes permit applications for liquid product pipelines, including water and petroleum products.  The standard by which the Secretary of State reviews applications for presidential permits is prescribed by an executive order issued in 2004.  Executive Order 13337 directs the Secretary of State to authorize those border crossing facilities that the Secretary has determined would “serve the national interest."

By contrast, cross-border natural gas pipelines are regulated by the Federal Energy Regulatory Commission, while electric transmission infrastructure is regulated by the Department of Energy.  Section 3 of the Natural Gas Act requires any person desiring to export any natural gas from the United States to a foreign country or to import any natural gas from a foreign country to the United States to obtain an order from the Federal Power Commission authorizing it to do so.   Section 202(e) of the Federal Power Act requires any person desiring to transmit any electric energy from the United States to a foreign country to obtain an order from the Federal Power Commission authorizing it to do so.

Executive Order 10485 designated the FERC's predecessor agency, the Federal Power Commission, to receive applications for natural gas and electricity facilities.  When the Department of Energy Organization Act of 1977 eliminated the Federal Power Commission, it shifted most of the FPC's responsibilities to the FERC, but Section 402(f) of that act specifically reserved import/export permitting functions for the Department of Energy.  For facilities governed by the Department of Energy, the Presidential Permit process is governed by Part 205 of the Department's rules.  In 2006, the Department delegated its authority to issue Presidential Permits for natural gas pipeline border crossings to FERC, via DOE Delegation Order No. 00-004.00A.

Infrastructure projects subject to the Presidential Permit process range widely in type, scope, and controversy, from the proposed Keystone XL oil pipeline from Canada to the proposed Champlain Hudson Express high-voltage direct current electric transmission line.

4th California blackout FERC enforcement case settles

Friday, December 5, 2014

Federal regulators have approved a settlement with another federal agency over its role in a 2011 blackout in California, Arizona, and Mexico.

On September 8, 2011, the Southwest's electric grid was hit with a widespread power outage that left over 5 million people in California, Arizona and Baja California, Mexico, without power for up to 12 hours.  Previous investigations by the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation (NERC) found that the blackout occurred when Arizona Public Service Company's 500-kilovolt Hassayampa-N.Gila transmission line tripped out of service, overloading the remaining elements of the regional grid. 

Earlier this year, FERC approved stipulations and consent agreements among its Office of Enforcement, NERC, and three public utilities.  Arizona Public Service agreed to pay $3.25 million in civil penalties, California's Imperial Irrigation District agreed to a $12 million settlement, and  Southern California Edison Company agreed to pay a $650,000 civil penalty and undertake additional compliance actions.

FERC approved a fourth settlement on November 24, 2014, with the Western Area Power Administration – Desert Southwest Region (Western-DSW).  One of four power marketing administrations within the United States Department of Energy, the Western Area Power Administration (WAPA) markets and transmits electricity to a fifteen-state region from hydroelectric power facilities at the Hoover, Parker, and Davis dams. Western-DSW is one of four regions carrying out this mission for WAPA, serving customers in Arizona, Southern California, and Southern Nevada. It sells more than ten billion kilowatt hours of hydroelectric power to approximately seventy municipalities, cooperatives, federal and state agencies, and irrigation districts. Western-DSW also operates and maintains more than forty substations and 3,100 miles of transmission lines.

In the FERC Order Approving Stipulation and Consent Agreement, the Commission notes that Western-DSW violated four Requirements of three Reliability Standards in the Transmission Operations (TOP) and Voltage and Reactive Control (VAR) categories. These groups of standards cover the responsibilities and decision making authority for reliable operations and maintenance of Bulk Power system facilities within voltage and reactive power limits to protect equipment and ensure reliable operation of the interconnection.  In particular, FERC Enforcement staff and NERC found that Western-DSW failed to operate its portion of the transmission system within voltage system operating limits and to maintain sufficient situational awareness prior to and during the event, undermining reliable operation of the Bulk Power System.

Western-DSW stipulated to the facts in the agreement and agreed to implement compliance measures necessary to mitigate the violations and improve overall reliability, including improving its models, better coordination with neighboring entities, and improving its situational awareness by adding a real-time monitoring tool that analyzes and alerts operators to potential contingencies. Western-DSW also agreed to make semi-annual compliance reports to Enforcement staff and NERC for at least one year.  Notably, the stipulation does not require Western-DSW to pay a civil penalty.

FERC's general investigative report on the incident identified six potential targets for enforcement action.  With cases settled against Western-DSW, SoCal Edison, the Imperial Irrigation District, and Arizona Public Service, only the California Independent System Operator and the Western Electricity Coordinating Council Reliability Coordinator have not yet been parties to a stipulation and consent agreement.

US to auction Massachusetts offshore wind sites

Wednesday, December 3, 2014

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

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

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

  • Deepwater Wind New England, LLC
  • EDF Renewable Development, Inc.
  • Energy Management, Inc.
  • Fishermen’s Energy, LLC
  • Green Sail Energy, LLC
  • NRG Bluewater Wind Massachusetts, LLC
  • OffshoreMW, LLC
  • RES America Developments, Inc.
  • Sea Breeze Energy, LLC
  • US Mainstream Renewable Power (Offshore), Inc.
  • U.S. Wind, Inc.
Bidders will be ranked based on a combination of monetary factors (primarily their bids) and non-monetary factors (whether or not the bidder has a Community Benefits Agreement or Power Purchase Agreement in place).

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

FERC adopts grid physical security reliability standard

Wednesday, November 26, 2014

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

Tuesday, November 25, 2014

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

Monday, November 24, 2014

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.