FERC report shows investment in natural gas

This week the Federal Energy Regulatory Commission issued its monthly energy infrastructure update covering May 2013.  The report details highlights in expansions of energy assets, ranging from natural gas pipelines to electric generation and transmission facilities.  It provides a monthly snapshot of recent activity, and can be used to spot trends in domestic energy development.  The current report illustrates increased investment in natural gas-related infrastructure, ranging from proposed new liquefied natural gas export terminals to newly installed natural gas-fired power plants.

The iconic U.S Capitol dome, where policies are made that shape energy investment.

Natural gas exports poised for growth.  Last month two facilities to liquefy natural gas for export advanced through the FERC regulatory process:

• Jordan Cove Energy requested authorization to construct and operate four liquefaction trains and storage facilities at a proposed export terminal in Coos Bay, Oregon.  If authorized and built, the project could export up to 900 MMcf per day of liquefied natural gas (LNG).  This gas would likely be destined for Asian markets.
• Golden Pass Products proposed a larger project in Texas.  Along with Golden Pass Pipeline, Golden Pass Products commenced the FERC prefiling process to construct and operate a 2,100 MMcf per day liquefaction facility for export at an existing import terminal located in Sabine Pass, Texas.  The Golden Pass project also includes proposed modification of an existing pipeline system to enable 2,500 MMcf per day of bidirectional capacity to the proposed export terminal.

These projects demonstrate increased interest in exporting natural gas to overseas markets.  The boom in domestic shale gas production has led to low natural gas prices in the U.S.  Domestic pricing is roughly one-third of the price that exporters can get by sending LNG to Europe or Asia.  Whether and to what extent the U.S. will allow exports remains to be seen, but in the interim, developers are scrambling to secure permits for export. 

New electric generation, mostly fueled by natural gas.  Last month a total of 33 new electric generation units came online.  Nearly three-quarters of the newly installed capacity is fueled by natural gas, adding 2,529 MW of new natural gas-fired electric generating capacity.  The new gas projects vary widely in scope:

• The largest, Mitsubishi Corporation’s 850 MW CPV Sentinel Energy Expansion in Riverside County, consists of eight 106.25 MW units.  Mitsubishi’s generation is sold to Southern California Edison under a long-term contract.
• In the middle, Procter & Gamble Company developed a 64 MW natural gas fired project to produce power for its paper products manufacturing facility in Wyoming County, Pennsylvania.
• At the opposite end of the scale, two landfill gas-fired projects came online in New York.  Wehran Energy Corp.’s 4.5 MW Brookhaven facility consists of three 1.5 MW Caterpillar Inc. generators.  The Brookhaven project was also joined by a 1.6 MW expansion of Waste Management Inc.’s Oneida-Herkimer project.

These projects illustrate the diversity of new natural gas fired projects being developed this spring.  The abundance of low-cost natural gas drives interest in the utility scale gas projects, while a desire to capture landfill-produced methane and put it to use as biogas supports the smaller projects.  As a result, natural gas’s share of total installed operating generating capacity grew slightly to 42.56%.  Despite a resurgence of coal as a fuel for electric generation, coal remains in second place in the installed capacity race, representing 28.9% of total U.S. installed capacity.

While each monthly energy infrastructure update represents only one data point, in the aggregate, they paint a picture of the direction of U.S. energy infrastructure development.  Natural gas is squarely in the center of this picture.  Based on consensus projections that natural gaswill remain the most cost effective fuel for decades to come, increased expansion of natural related infrastructure is likely to continue for some time.

Maine may streamline tidal power permitting

The Maine legislature is considering a proposal to streamline the permitting process for some tidal energy projects. The bill, "An Act To Streamline the General Permit Process for Tidal Power", would relieve a perceived conflict between state and federal law over the permitting process.

Tidal energy has been harvested along the Maine coast for hundreds of years. While tide mills' heyday predated modern regulation of energy projects and their environmental impacts, anyone developing a modern tidal power project must navigate multiple layers of rules and requirements. The recent resurgence of interest in tidal energy has led to an often overlapping patchwork of regulations.

These rules can be hard to interpret, and occasionally lead to chicken-or-the-egg conundrums. For example, a 2009 Maine law created an expedited general permit process for certain small tidal power projects. Under that process, projects capable of generating up to 5 megawatts of power can qualify for an easier permitting path if their primary purpose is demonstrating or testing tidal technology. (By way of comparison, 5 megawatts is roughly equivalent to 6,705 horsepower - imagine what a tide miller could have done with that!)

Prior to filing a permit application with the Maine Department of Environmental Protection under the 2009 law, an applicant must first obtain a finding from the Federal Energy Regulatory Commission that the project will have no significant adverse impact on environmental quality. Unfortunately, before issuing that finding federal regulators want applicants to show that they are already seeking state approval. This regulatory conflict makes it hard for people who want to develop or redevelop a tidal resource to move forward.

To fix this problem, the DEP, Senator Mike Thibodeau of Waldo County, and Representative Joyce Maker of Calais proposed an amendment to Maine law. Their bill, known as LD 437, would enable the DEP to start processing an application without needing to wait for the federal environmental assessment. After a public hearing earlier this month, the legislature's Joint Standing Committee on Environment and Natural Resources voted to recommend that the bill ought to pass as amended.

Next steps for the tidal streamlining bill include consideration by the full Senate and House. Given the committee's vote, the bill seems likely to find further support in the two chambers. While its enactment may not launch a tide of new tidal power developments in Maine, relieving this piece of the regulatory tangle should help people test and demonstrate tidal power technologies old and new.

Connecticut coal-fired power plant air permit issued

The U.S. Environmental Protection Agency has approved a five-year permit for the last coal-fired power plant operating in Connecticut.  The plant, PSEG Power LLC's Bridgeport Harbor Generating Station, can generate 529 megawatts of energy by combusting coal and oil.

While the plant has operated since 1961, its permit renewal was questioned for economic and environmental reasons.  Across the nation, operators of coal plants have announced plans to close or convert plants to other fuels such as natural gas and biomass.  Between the low cost of natural gas - projected to stay low for the foreseeable future - and tighter environmental regulations affecting the electric utility sector, many older and smaller coal-fired power plants are no longer economic to operate.  Additionally, environmental activists have targeted coal-burning plants as polluters, and had argued against the Bridgeport Harbor plant's new permit.

Under the federal Clean Air Act, existing major stationary sources (i.e. those capable of emitting 100 tons per year or more of any criteria air pollutant) must obtain a so-called Title V permit every five years.  Generally, Title V permits are issued by the state or local air pollution control agency, but EPA has 45 days to review any proposed permit and request changes.  In September, Connecticut recommended that EPA renew Bridgeport Harbor's permit.  After the 45-day review process, EPA approved the permit's issuance.

What does the Bridgeport Harbor air permit mean?  Most directly, it means PSEG may continue to operate its plant for another five years -- if it wants to. According to the Connecticut Post, by mid-summer the plant had only operated 24 days this year.  The Bridgeport Harbor plant can provide both baseload power and peaking power needed to satisfy peak consumer demand, but generally the fewer days an asset operates, the harder it is to recover the cost of ownership and operations.

Moreover, coal-fired power plants are declining in the U.S.  This is particularly true in New England, a region far from coal mining.  Will PSEG hold onto the Bridgeport Harbor station and seek another Title V permit in 2017?  For how long will the plant continue to burn coal?  Will PSEG or another owner seek to repurpose the plant to burn other fuels?

Utilities switching from coal to gas

Utilities around the country are closing or converting older coal-fired power plants, and increasing the use of natural gas.  Pressure to make this shift comes from several factors, including tighter regulation of air emissions and the low price of natural gas compared to recent history.

The stacks of the Salem Harbor Power Station rise above Cat Cove in Salem, Massachusetts.  Dominion announced last year that it would close this plant, which it then sold to Footprint Power.

One electric generation plant that may illustrate this trend is Dominion Virginia Power's Bremo Power Station on the James River in central Virginia.  Originally built by the Virginia Electric & Power Company in 1931, the plant can now produce 227 megawatts of electricity by burning coal to boil water; the resulting steam spins turbines attached to electric generators.  According to Dominion, the Bremo plant consumes an average of 2,500 tons of coal per day.

This week Dominion announced plans to convert the Bremo plant from coal to natural gas.  In a filing with the Virginia State Corporation Commission, the regulatory body responsible for electric utilities, Dominion asked for approval to convert the plant over the next year at an estimated cost of $53.4 million.  If the SCC approves the conversion, the utility anticipates stopping coal consumption at the plant by the fall of 2013.

Dominion had previously agreed to convert the Bremo Power Station by spring 2014 as part of the air permit it received for the 585-megawatt Virginia City Hybrid Energy Center.  That plant entered commercial operations in July of this year, burning a mix of coal and biomass.

Dominion describes the Bremo conversion as being the ninth company-owned, coal-fired power station with units recently announced to be closed or converted to alternative fuels.  The utility points to the uneconomic nature of operating smaller, older coal-fired stations given the spread of cheaper natural gas and new environmental regulations requiring operators to retrofit plants with upgraded emission control equipment.  According to Dominion, the Bremo conversion would allow consumers to save about $155 million when compared to continued operation on coal.

Other utilities are making similar conversions or are considering closing some existing coal-fired plants. Natural gas consumption is on the rise, particularly in the electric generation sector.  At the same time, many utilities continue to rely on coal as part of their generation portfolio, as evidenced by Dominion's construction of the the primarily coal-fired Virginia City plant.  The trend appears to be one of closing or converting older or smaller coal-fired plants, consolidating coal consumption in larger, newer plants and increasing the use of natural gas to produce power.

Maine tidal project wins pilot license

Federal regulators have issued a pilot project license to a tidal energy project proposed in Maine's Cobscook Bay.  Yesterday, the Federal Energy Regulatory Commission issued an order granting Ocean Renewable Power Company Maine, LLC an 8-year pilot project license to construct, operate, and maintain its proposed Cobscook Bay Tidal Energy Project.  As licensed, the 300 kilowatt project will be located in Cobscook Bay north and east of Seaward Neck and west of Shackford Head State Park in Eastport, Maine.

ORPC Maine applied for its pilot license in September 2011.  Last month, FERC issued its Environmental Assessment of the Cobscook project, finding generally that licensing the hydrokinetic project with appropriate environmental protective measures would not constitute a major federal action that would significantly affect the quality of the human environment.

FERC granted the pilot project license just 179 days after the license application was filed, a relatively quick timeline for hydropower permitting made possible by FERC's hydrokinetic pilot project licensing process.  As envisioned by FERC staff, the ideal pilot project should be (1) small, (2) short term, (3) located in non-sensitive areas based on the Commission’s review of the record, (4) removable and able to be shut down on short notice, (5) removed, with the site restored, before the end of the license term (unless a new license is granted), and (6) initiated by a draft application in a form sufficient to support environmental analysis.  In ORPC Maine's case, FERC staff agreed that the Cobscook project was a good fit for pilot project licensing process after reviewing the developer's application.

FERC's order approving the license includes an analysis of the economic benefits of project power. As licensed, FERC found that the levelized annual cost of operating the project would be about $1,419,600, or $1.13/kWh. Based on an estimated average generation of 1,250,000 kWh as licensed, the annual value of alternative grid-based power would be $90,400, or 7.2 cents/kWh.  Therefore, in the first year of operation the project power would cost $1,329,200, or $1.06/kWh, more than the cost of alternative power.

As FERC found, "The project has relatively high capital and operation and maintenance costs with respect to the amount of power produced. Although our analysis shows that the project as licensed herein would cost more to operate than our estimated cost of alternative power, it is the applicant who must decide whether to accept this license and any financial risk that entails. This project’s value, however, lies in its successful testing and demonstration of ORPC Maine’s turbine technology, and the project’s ability to raise the profile of, and advance, the emergent tidal energy industry."

September 9, 2010 - Lightship Nantucket; FERC signs Colorado MOU on small hydro

The Lightship Nantucket WLV61, in port on Martha's Vineyard in summer 2010.  Until 1983, lightships such as this were used to mark shoals; they have since been functionally replaced (if not aesthetically so) by automated buoys.

The Federal Energy Regulatory Commission (FERC) is working with states to promote the development (or redevelopment) of small hydropower projects across the country.  FERC has recently signed Memoranda of Understanding (MOUs) with four states on the development of hydrokinetic projects: California, Washington, Maine, and Oregon.  Now FERC has signed an MOU with Colorado to streamline the procedures for developing small-scale hydropower projects in Colorado.  According to a recent federal survey, Colorado could be host to several hundred potential small (5 MW or smaller) hydropower projects.  Altogether, these small projects could add up to a combined capacity of more than 1,400 MW.

The MOU focuses on the development by Colorado of a pilot program to test procedural options for simplifying the processes for developers to obtain conduit exemptions and small (5MW or less) project exemptions.

The MOU opens the door for developers of small projects in Colorado to participate in the pilot program.  Colorado and FERC are both expected to take input from project developers about the kind of obstacles they face in permitting and exempting small projects - and about what can be done to help more projects be developed.

As we've seen in Maine, developing or redeveloping small hydro projects can run into siting and permitting challenges at the federal, state, and local levels.  For example, the Scribner's Mill dam reconstruction and repowering project on the Crooked River in Maine faces opposition on water quality, environmental and fisheries concerns.  While an MOU like that between FERC and Colorado might not eliminate these challenges, stakeholders are hopeful that a resolution will be reached that allows environmentally responsible projects to move forward.

June 7, 2010 - update: Fort Halifax dam removal and erosion

A Morning Sentinel article today describes how the Maine Department of Environmental Protection is requiring FPL Energy Maine Hydro, the company that removed its Fort Halifax dam in July 2008, to stabilize the riverbank beneath the Fort Hill cemetery.

After years of legal battles, FPL removed the Fort Halifax dam from the mouth of the Sebasticook River in Winslow, Maine. As a condition of its dam removal permit, FPL was required to "closely monitor the slope adjacent to the cemetery and promptly remediate any slumping or erosion" in order "to protect the Fort Hill Cemetery from irreparable harm." Back in April, the riverbank suffered after another major landslides. FPL commissioned a study by Findlay Engineering Inc. of Yarmouth, which concluded that heavy rains and a small earthquake 41 miles away were contributing factors, but largely absolved FPL of responsibility.

Today, the news breaks that the Maine DEP is challenging FPL's study. DEP points to soil loss during the dewatering process, and a resulting lack of work by FPL to re-stabilize the slope after drawdown.