FERC approves Maryland LNG project

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

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

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

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

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

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?