Oregon coal export plans stopped

The United States is one of the world’s top coal producers and exporters, but recent plans to add coal export capacity in the Pacific Northwest have not been fulfilled, as several proposed export terminals have been withdrawn.  Plans for yet another terminal have been scrapped, as yesterday Kinder Morgan Energy Partners LP canceled its proposed Clatskanie, Oregon project.  What does this mean for U.S. coal exports and for domestic pricing?

Kinder Morgan Energy Partners is a publicly traded master-limited partnership,or MLP, focused on pipeline infrastructure.  Along with fellow Kinder Morgan family companies Kinder Morgan, Inc., Kinder Morgan Management, LLC, and El Paso Pipeline Partners, Kinder Morgan claims to be the largest midstream and the third largest energy company (based on combined enterprise value) in North America.  The company owns or operates about 80,000 miles of pipelines and 180 terminals handling products like natural gas, refined petroleum products, crude oil, and carbon dioxide, as well as gasoline, jet fuel, ethanol, coal, petroleum coke and steel. It boasts of operating primarily “like a giant toll road”, and seeks to avoid commodity price risk through a fee-for-service model.

Most coal export capacity in the U.S. is located in the Midatlantic and Gulf Coast regions.  While Asia dominates the world coal import market, major markets for U.S. coal exports include Canada, Brazil, the Netherlands, and the European Union.  The principal West Coast coal export port is Los Angeles/Long Beach, with virtually no export capacity in the Pacific Northwest.  Kinder Morgan had proposed a terminal to be built at the Port Westward industrial park on the Columbia River near Clatskanie.  Yesterday project partner Port of St. Helens stated that Kinder Morgan had announced that it would not be pursuing the project.

Up to six Pacific Northwest coal export terminates have been proposed in recent years, but to date none have been built.  The Kinder Morgan proposal joins a series of other canceled Pacific Northwest coal export plans.  RailAmerica Inc. announced last year that it would not pursue a coal storage and export facility at Washington’s Port of Grays Harbor.  Earlier this year, the Oregon International Port of Coos Bay announced the end of its exclusive negotiating agreement between with Metropolitan Stevedoring Company (Metro Ports) to build a thermal coal and biomass export facility.  With the Kinder Morgan project gone, three potential terminals remain:  Australian  company Ambre Energy’s barge-loading operation at the port of Morrow and Port Westward, Millennium Bulk Terminals’ proposed $643 million dock west of Longview, and SSA Marine’s proposed $600 million coal terminal at Cherry Point.

Whether a coal export terminal will be developed in the Pacific Northwest is uncertain.  If not, it will continue to be difficult for coal produced in the western U.S. to reach the world’s largest demands for coal imports.  China, Japan, South Korea, India, and even the relatively small Chinese Taipei have led the demand for coal imports in recent years.  This opens significant economic activity. At the same time, environmentalists argue that new export projects would contribute to global pollution and greenhouse gas emissions.  Combined with the pressures of the commodity market for coal and other fuels, these dynamics may continue to block expanded West Coast export plans.  As is being argued over the issue of liquefied natural gas exports, whether coal exports are expanded could also have impacts for U.S. coal pricing.

Massachusetts solar power goal reached, expanded

Massachusetts has surpassed its goal of being home to 250 megawatts of installed solar energy capacity four years early.  Governor Deval Patrick's administration and the state legislature have adopted a series of policies favoring the development of solar energy, including a target of reaching 250 MW by 2017.  Last week the administration announced that this goal had already been reached, and established a new goal of 1,600 MW by 2020. 

Solar power in Massachusetts has grown significantly in recent years.  In 2007, the Commonwealth hosted just 3 MW of solar capacity.  Since then, Massachusetts has adopted a variety of incentives for renewable power production.  Chief among these is the Renewable Portfolio Standard (RPS) Solar Carve-Out program.  State law currently requires utilities to source up to 400 MW from in-state solar photovoltaic projects.  Utilities purchase solar renewable energy certificates, or SRECs, representing the environmental attributes of electricity produced by qualified projects.  These SRECs come in addition to the actual power produced by projects, and carry a premium value over other renewable attribute products.  State laws such as the 2008 Green Communities Act have provided additional incentives, including technical assistance and financial support for solar development.

Given current policies and market dynamics, solar power in Massachusetts will likely continue to grow.  While the bulk of newly installed capacity is likely to be in the form of distributed generation (as opposed to very large-scale utility installations as are under development in the desert Southwest), Massachusetts will continue to see projects ranging from residential rooftop-scale to close to 10 MW.  Reaching 1,600 MW within the next seven years will be a challenge, and may depend on continued policy support and market trends, but the recent rate of growth and relative enthusiasm suggest this may be possible.

Grid operator expects sufficient electricity this summer

Regional electricity grid operator ISO New England, Inc. issued its 2013 summer outlook on April 29.  In that report, New England regional transmission organization found that regional electricity supplies during the upcoming summer are expected to be sufficient to meet consumer demand under normal weather conditions.  But if any number of contingencies occur, such as a heat wave, the grid could be seriously strained.

ISO New England noted that under normal conditions, there should be enough electricity this summer.  But it identified a series of risk factors could tip the balance of supply and demand for electricity, including extreme summer weather conditions or unexpected resource outages.  These factors could create "operational challenges", meaning a hard time finding enough electricity to meet peak demand.  New England may be forced to resort to  importing emergency power from neighboring regions, and asking businesses and people to voluntarily conserve energy.

The report's base assumption is for "normal" summer weather conditions of about 90 degrees in key southern New England cities.  Under these conditions, ISO New England forecasts electricity demand could reach 26,690 megawatts (MW).   If an extended heat wave pushes temperatures to 95, demand could rise to 28,985 MW.  Last summer’s load peaked July 17 at 25,880 MW, about 3% smaller than the base amount forecast for summer 2013.  New England set its record for peak demand on August 2, 2006, when demand reached 28,130 MW.

On the supply side, ISO New England identified several risks that could lead to unexpected shortages of electricity.   First, most natural gas pipeline maintenance in the region is scheduled for the summer months.  Maintenance activities could affect natural gas supplies to some power plants. On this point, the grid operator said it was coordinating with the pipeline companies to ensure that the supply is adequate for power generation during the maintenance season.

Second, liquefied natural gas (LNG) is in high global demand.  Current LNG prices are roughly three times higher in Europe and Japan than in the United States.  This mean LNG deliveries into New England might be reduced this summer.  At times, New England electric generation relies on LNG, which could also affect power plant operations.

Overall, ISO New England reported that it expects electricity supplies to be sufficient to meet consumer demand under normal weather conditions this summer.  If shortages occur, they will likely affect both the reliability of the grid and the wholesale price of power.  The winter season is likely to be worse, as regional demand for natural gas for heating increases during the winter, placing a tighter squeeze on the amount and price of gas available for electric generation.  The grid operator's prediction will be put to the test in the coming months.

Changes in how New England generates electricity

Society can use a number of different energy resources to generate electricity.  We typically rely on a portfolio of multiple fuels to meet our needs, but the composition of this energy resource mix can affect the reliability, cost and environmental impacts of electricity generation.  Through most of the twentieth century, in most regions of the United States, coal dominated the mix.  Today, new resources like natural gas and nuclear power play major roles.  The resource mix continues to evolve, with significant changes since 2000 alone.

New England provides a prime example of these shifts.  According to regional grid operator ISO New England's 2013 Regional Energy Outlook (48-page PDF), in 2000 the largest share of power generated in the region came from nuclear power (31%).  Nuclear power continued to provide a similar share of our electricity in 2012, but it has been bypassed by natural gas-fired generation as the largest source of our power.  While natural gas contributed just 15% of regional electricity in 2000, last year it provided more than half (52%) of all electricity in New England.  The growth of natural gas comes as the result of several trends, including the availability of relatively low-cost gas as well as natural gas's favorable emissions and environmental impacts compared to oil and coal.

Indeed, the amount of power generated by burning oil and coal in New England has fallen sharply.  While oil-fired generation provided 22% of our needs in 2000, last year less than 1% of our power came from oil.  The high cost of oil, combined with the availability of extensive capacity to generate electricity from natural gas, drove this marked decrease in the electric power sector's use of oil.  Likewise, coal-fueled power has declined from 18% in 2000 to just 3% in 2012.  Tighter federal air emissions standards and pollution control requirements, combined with the age of the coal-powered fleet and the availability of low-cost natural gas, have made coal-fired power largely uneconomic in New England.

According to the numbers, natural gas's ascendancy has not come at the expense of renewable power.  The share of regional electricity produced from hydropower and other renewable energy resources held steady at 13% from 2000 to 2012.

What are the implications of this shift in New England's portfolio of energy resources?  Lower average wholesale energy prices are one result.  As electricity produced from oil and coal became more expensive, the cost of electricity produced from natural gas fell.  Combined with the shift in the resource mix, these changes have led to relatively lower prices for electricity.  This price decrease has been partially offset by increases in the cost of utility transmission and distribution service, but most consumers see lower electricity prices today than they did in 2000.

Maine funds available for anaerobic digestion

The state of Maine has announced funds available to help farmers reduce their agricultural impacts to water quality. State agencies have made up to $3 million available to enable low-interest loans to support eligible projects. These projects may include developing anaerobic digesters, as well as improved roof runoff structures, water and sediment control basins, composting facilities, and irrigation system water conservation.

Anaerobic digesters enable the conversion of organic materials such as manure and other agricultural wastes into biogas. Biogas, largely composed of methane, can be used as a fuel source comparable to natural gas. For example, it can be used to power an electric generator and thus to produce renewable electricity – all while making efficient use of manure and agricultural wastes that could otherwise harm water quality.

Two anaerobic digesters at Stonyvale Farm in Exeter, Maine.

Under the program, farmers will be able to borrow up to $450,000 at a fixed interest rate of 2 percent for up to 20 years to develop qualifying projects. The opportunity represents a partnership between the Maine Departments of Environmental Protection and Agriculture, Conservation and Forestry, the Finance Authority of Maine and the Maine Municipal Bond Bank. The initial seed money comes from the DEP-administered Clean Water State Revolving Fund. Since 1989, that fund has provided over $650 million in low-interest loans for water quality projects, primarily hosted by publicly owned wastewater treatment facilities.  For the newly-announced program, the fund will transfer up to $3 million to FAME, which will finance the loans.

For more information on the opportunity, contact either participating department, or consult a professional experienced with anaerobic digestion and state-funded incentive programs. The Preti Flaherty team advises clients on both the development of anaerobic digestion facilities and participation in government-backed loan programs. For more information, please contact Todd Griset at 207-623-5300.

Master Limited Partnerships for clean renewable energy

An organizational structure called Master Limited Partnerships has the potential to increase private-sector investment in clean energy. Master Limited Partnerships, or MLPs, benefit from a tax structure under which investors are taxed as partners but can trade their ownership stakes on securities exchanges much like corporate stock. Newly proposed federal legislation could extend this treatment to clean energy technologies.

MLPs offer their investors an attractive combination of tax advantages and liquidity. Profit from most publicly traded corporations is taxed twice, at both the corporate level and the shareholder level. By contrast, income from MLPs is taxed only at the shareholder level because it is treated as a partnership for tax purposes. Like Real Estate Investment Trusts or REITs, MLPs thus combine the tax benefits of a limited partnership with the liquidity of publicly traded securities.

Under federal law, MLP treatment is limited to enterprises generating at least 90 percent of their income from qualifying sources. These generally involve the use of natural resources, such as the production, processing or transportation of petroleum, natural gas, coal, timber, and other minerals. Since 1981, the use of the MLP structure has grown; estimates suggest that over 100 MLPs are currently being traded on major exchanges, with a total market valuation of about $445 billion.

Yesterday Congress introduced proposed bipartisan legislation that would extend this tax structure to clean energy technologies. The Master Limited Partnerships Parity Act, formally known as S.795: A bill to amend the Internal Revenue Code of 1986 to extend the publicly traded partnership ownership structure to energy power generation projects and transportation fuels, and for other purposes, is sponsored by Sen. Chris Coons, D-Del., along with co-sponsors Sens. Jerry Moran; R-Kan., Debbie Stabenow, D-Mich.; and Lisa Murkowski, R-Alaska. It has been referred to the Senate Committee on Finance.

The Master Limited Partnerships Parity Act would significantly broaden the scope of projects eligible for MLP treatment to include clean energy resources and infrastructure projects. These projects would include any energy technologies that qualify for the federal production tax credit or investment tax credit, such as wind, closed and open loop biomass, geothermal, solar, municipal solid waste, hydropower, marine and hydrokinetic, fuel cells, and combined heat and power. The bill would also open the MLP structure to advanced transportation fuels such as cellulosic, ethanol, biodiesel, and algae-based fuels, as well as energy-efficient buildings, electricity storage, carbon capture and storage, renewable chemicals, and waste-heat-to-power technologies.

Proponents hope that the act would stimulate investment in clean energy projects much as it has worked for other extractive natural resource infrastructure. At the same time, concern over the federal budget calls for serious consideration of measures that would reduce federal tax revenues. So far, the bill seems to have broad support and little outspoken opposition. If enacted, it could lead to an influx of investment capital into renewable and clean energy technologies.

Funding to reduce barriers to marine, hydrokinetic energy

The U.S. Department of Energy has announced a competitive funding opportunity designed to support the growing marine hydrokinetic energy industry.  $1.9 million is available for projects that will improve the collection and analysis of environmental monitoring and experimental data from marine hydrokinetic devices. 

Looking east from Griffith Head, Reid State Park, Maine.  Damariscove Island, a proposed offshore wind site, sits on the right horizon.

Marine hydrokinetic energy technologies capture the energy embodied in moving ocean water such as tides, currents, and waves.  While the marine hydrokinetic industry is relatively young, at least one project has been licensed by the Federal Energy Regulatory Commission and built off the Maine coast.  Research and development efforts are ongoing regarding a variety of marine hydrokinetic technologies and devices, and their environmental impacts continue to be studied.

The recently-announced federal funding aims to support that environmental evaluation.  Working with the National Oceanographic Partnership Program, the Department of Energy's Office of Energy Efficiency and Renewable Energy Wind and Water Power Technologies Office has issued a Funding Opportunity Announcement entitled “Marine and Hydrokinetic (MHK) Environmental Effects Assessment and Monitoring.”

Under that Funding Opportunity Announcement, the Department of Energy offers $1.9 million in funding to be split by up to 11 recipients.  Specific project areas include studies of fish behavior and mortality around hydrokinetic turbines, improved environmental monitoring of marine hydrokinetic projects, and predictive modeling of marine hydrokinetic projects' environmental impacts based on surrogate technologies with stressors and receptors similar to those expected from marine hydrokinetic technologies.

Under the competitive solicitation, the Department of Energy requested Letters of Intent to be submitted by 11:59 Eastern Time on April 18, 2013. Full applications, which must include specified documents, must be submitted by 5:00 PM ET on May 16, 2013.  For more information, visit the Department of Energy's official Funding Opportunity Announcement website or contact Todd Griset at Preti Flaherty.