U.S. coal production declined again in 2019

Recently released federal data shows that U.S. coal production (mining) peaked in 2008, and has declined significantly since then. 2019 U.S. total annual coal production was 706 million short tons, a 7% reduction relative to 2018. According to the U.S. Energy Information Administration, 2019's level of domestic coal production was the lowest since 1978.

Federal coal production data illustrates the recent history of this energy commodity. After modest production declines in the 1950s, total annual U.S. coal production grew steadily decade after decade from about 1963 to 2008. This overall growth curve was marked by minor deviations, such as in 1978 when most coal mining was shut down for several months due to a labor strike by coal miners, but coal's general trend was up for the latter half of the twentieth century and into the present millennium.

But since 2008, U.S. coal production has declined significantly. While some years have shown minor increases in production, most years between 2008 and 2016 were marked by significant decreases in production, and the overall trend has been sharply down.

Source: U.S. Energy Information Administration, Annual Coal Report

According to EIA, its weekly coal production estimates for 2020 suggest continued steep decreases this year, with the agency projecting output "falling to production levels comparable with those in the 1960s." These estimates are based on EIA's coal railcar loading data, which so far show a 2020 year-to-date decline of 27% relative to 2019.

EIA attributes the ongoing decline in U.S. coal production to "less demand for coal internationally and less generation from U.S. coal-fired power plants." U.S. coal exports in the first five months of 2020 were 29% below the comparable period in 2019. Meanwhile, U.S.coal-fired electricity generation declined about 16% in 2019 year-over-year to reach a 42-year low, and EIA data shows coal-fired generation has fallen another 34% through May 2020.

Coal's decline comes at the same time as significant growth in renewable resources. United States consumers used more energy from renewable sources than from coal in 2019, the first time that national renewable energy use has exceeded coal since at least 1885. Some regions, such as New England, have effectively ended coal use for electric power generation (coal provided just 0.1% of ISO New England system power in 2019).

Going forward, EIA projects U.S. coal production for the whole year will be about 29% below 2019 levels: a reduction in coal production of over one-quarter. EIA thinks coal production may rebound by 7% in 2021 "when rising natural gas prices may cause some coal-fired electric power plants to become more economical to dispatch".

Electric utility rate cases on the rise

Federal data shows an increase in the number of U.S. electric utility rate cases filed in 2018, to the largest number since 1983. Of the 89 utilities filing rate cases in 2018, 10 proposed to decrease rates, one proposed a rate freeze until next year, and the remaining 78 utilities proposed to increase their rates.

Under typical state law, public electric utility companies must obtain regulatory approvals before changing the rates they charge their customers. According to the U.S. Energy Information Administration, 89 electric utilities sought to change their rates by filing rate cases with state regulatory commissions in 2018. This represents a significant increase relative to two decades ago.

Source: U.S. Energy Information Administration

According to EIA, the frequency or number of electric utility rate cases "typically reflects changes in the costs of generating and delivering electricity." For 2018, EIA pointed to increases in spending for electric transmission and delivery (as opposed to generation) as driving most of the rate increases that were ultimately approved.

EIA notes that the last time electric utility rate case filings were this active was the early 1980s, an era of significant rate increases: electricity rates increased at an average annual rate of 12% in the decade following the 1973 oil embargo. To explain that historic period of numerous rate cases, EIA points to factors including investments in coal and nuclear plants following the oil crisis; the enactment of the federal Public Utility Regulatory Policies Act of 1978 (PURPA), which required utilities to purchase electricity from generation from small, independently-owned renewable facilities, and the 1979 Three Mile Island nuclear plant accident which placed increased focus (and expense) on the safety of nuclear plants. By contrast, during a period of time when the Federal Energy Regulatory Commission was restructuring most electric markets (between 1995 and 2000), fewer than 20 rate cases were filed in most years.

Utilities typically ask for approval of significantly higher rate increases than are ultimately approved by regulators. According to EIA, in 2018, utilities asked for an aggregate rate increase $6.8 billion, but regulators approved a total increase of just $2.8 billion.

US energy-related CO2 emissions projected to decline

Energy-related carbon dioxide emissions in the U.S. are projected to decrease by 2.2 percent in 2019 relative to the previous year, according to the latest forecast by the U.S. Energy Information Administration.

EIA tracks energy-related carbon dioxide emissions from petroleum, natural gas, and coal. Petroleum made up nearly half of energy-related CO2 emissions in 2018, at 45 percent of all energy-related carbon dioxide emissions. Transportation, heating, and electric power generation sectors consume significant amounts of petroleum. EIA projects petroleum CO2 emissions will remain relatively flat in 2019, relative to 2018. 

According to EIA, nearly all of its forecast decrease for 2019 is due to reduced emissions from coal consumption. EIA forecasts that coal-derived CO2 emissions will decrease by 169 million metric tons (MMmt) in 2019. This represents the largest year-over-year decrease in coal-derived CO2 emissions since 2015. Nearly all the coal used in the U.S. -- 92 percent -- is consumed by the electric power sector; EIA attributes the decline to forecast changes in the electricity generation mix, with coal plants retiring and relatively milder summer weather expected to lead to overall lower electricity demand.

While coal-related emissions are projected to decline, EIA projects that forecast natural gas CO2 emissions will increase by 53 MMmt, largely due to increased use of natural gas to displace coal for electric power generation. According to EIA, the decrease in coal emissions will more than outweigh the increase in natural gas emissions, because natural gas-fired electricity generation is less carbon-intensive than coal-fired electricity generation.

U.S. to export more energy by 2020 than it imports, projects EIA

Federal energy analysts project that the United States will export more energy than it imports by 2020, making the nation a net energy exporter for the first time since the 1950s. Fossil fuels represent the largest volumes of this international trade.

Source: U.S. Energy Information Administration

The United States both exports and imports energy in a variety of forms, including natural gas, coal and coke, petroleum and other liquids, and electricity. According to the U.S. Energy Information Administration, the United States has long been a net exporter of coal and coke. In 2017, the nation began exporting more natural gas than it imports, primarily in the form of liquified natural gas or LNG. EIA notes that electricity trades with neighboring Canada and Mexico represent "a relatively small part of U.S. net energy trade flows."

The EIA projects that domestic production of crude oil, natural gas, and natural gas plant liquids will continue to grow at a faster rate than U.S. energy consumption over the next decade, meaning the balance of these fuels will be exported. EIA projects that due to "evolving trade flows of liquid fuels and natural gas," increasing exports of these fuels will tip the trade balance to where the U.S. is a net exporter of energy by 2020. When this shift occurs, it will represent the first time that the United States exports more energy than it imports on an annual basis since 1953.

Exactly how large the nation's net exports might be -- and how long the net-exporter status might last -- depend on a variety of assumptions about matters including oil and gas prices, resource extraction technologies, and possible changes to law. Under EIA's reference case which reflects current laws and regulations, the U.S. begins exporting more energy than it imports on an annual basis in 2020 and maintains that status through 2050. In other cases featuring lower prices or extraction rates for oil and gas, EIA projects that U.S. will return to net-importer status by the mid- to late-2030s.

Source: U.S. Energy Information Administration

Changes to laws and regulations could also affect the trade balance for energy products.

Feds predict US coal consumption falling to 1979 levels

U.S. coal consumption in 2018 will reach its lowest level since 1979, according to a prediction by the U.S. Energy Information Administration. Reduced coal use for electricity generation is the largest contributor to the decline, driven by factors including economics and environmental regulations.

The EIA tracks total U.S. coal consumption. According to its latest forecast, EIA expects total U.S. coal consumption in 2018 to fall to 691 million short tons. This represents a 4% decline from 2017, and would bring coal use in line with 1979 levels.

Source: U.S. Energy Information Administration

EIA cites reductions in the use of coal to generate electricity as the largest contributor to this decline. Between 2007 and 2018, 93% of total U.S. coal consumption was for electricity generation. But shifts in how the country generates power -- including retirements of over 66 gigawatts of coal-fired power plants since 2007, plus decreases in the utilization or capacity factor of most remaining coal-fired generators -- have reduced the nation's consumption of coal.

Part of the shift away from coal-fired power production can be explained by economics. Natural gas prices have generally remained relatively low compared to coal prices over the past decade, and fuel-free renewable power projects are on the rise.

Environmental regulations such as the Mercury and Air Toxics Standards (which took effect in 2015) have also contributed to the shift, both directly (for example, restricting carbon emissions) and indirectly (by affecting the economics of coal-fired power generation and prompting further plant retirements instead of investments in environmental controls).

EIA predicts that the trend away from coal will continue in the short term, projecting power sector coal consumption to fall by a further 8% in 2019.

FERC Order 842 requires primary frequency response by generators

U.S. energy regulators have issued an order amending standard interconnection agreements to require new generators to install, maintain and operate a functioning governor or equivalent controls capable of primary frequency response as a precondition of interconnection. The Federal Energy Regulatory Commission's Order No. 842 also amended the pro forma interconnection agreements to include certain operating requirements including maximum droop and deadband parameters, and sustained response provisions.

As described by the Commission, reliable operation of an alternating current grid requires maintaining system frequency within predetermined boundaries above and below 60 Hertz. Frequency response describes an interconnected grid’s ability to arrest and stabilize deviations from this predetermined range of frequencies after a sudden loss of generation or load.

Historically, the U.S. grid's primary frequency response capability came from baseload synchronous generators such as coal-fired power plants. But many such plants have retired in recent years, with further retirements expected. In 2016, the Commission noted that shifts in the portfolio of U.S. electric generators meant fewer resources could likely provide primary frequency response, especially if new variable energy resources such as wind and solar did not provide this service. In response, it opened an inquiry into what primary frequency response reforms it should make.

On February 15, 2018, the Commission issued its Order No. 842 revising its regulations to require newly interconnecting large and small generating facilities, both synchronous and non-synchronous, to install, maintain, and operate equipment capable of providing primary frequency response as a condition of interconnection. The final rule also amends the Commission's pro forma interconnection agreements to include certain operating requirements including maximum droop and deadband parameters, and sustained response provisions. It provides exemptions for nuclear power plants and some combined heat-and-power plants.

These requirements will apply to most newly interconnecting generation facilities that execute, or request the unexecuted filing of, an LGIA or SGIA on or after the rule’s effective date, as well as to existing large and small generating facilities that take any action that requires the submission of a new interconnection request that results in the filing of an executed or unexecuted interconnection agreement on or after the effective date.

In a press release, the Commission said its action was intended to address "the increasing impact of the evolving generation resource mix." Commissioner LaFleur made a separate statement in which she noted that while decreases in the nation's portfolio percentage of synchronous generation have contributed to declining frequency response performance, "recent technological advancements have enabled new non-synchronous generating facilities, such as wind and solar, to cost-effectively include primary frequency response capabilities in their facilities." Improved inverters and battery storage are among these innovations.

The Commission has also recently noted the potential of electric storage resources to provide frequency response and other services. Its Order No. 841 is designed to remove barriers to the participation of electric storage resources in wholesale markets operated by regional transmission organization and independent system operators, including markets for frequency response.

Energy policy in the 2018 State of the Union

U.S. President Donald Trump delivered the 2018 edition of the State of the Union speech on January 30, 2018. Unlike many previous such addresses, this one barely covered energy policy, focusing instead on a variety of other matters. But the speech offers insight into the Trump administration's view of the national situation, as well as into its priorities.

Energy policy and resources have often featured prominently in previous State of the Union addresses, and in remarks in 2017 President Trump advocated for a national strategy of "energy dominance." By contrast, President Trump's 2018 State of the Union speech mentioned U.S. regulation, production, and trade in energy only briefly, emphasizing his deregulatory agenda and pro-export philosophy.

The Trump administration posted an online version of his 2018 remarks as prepared for delivery. In that version, only two sentences use the word "energy":

We have ended the war on American Energy — and we have ended the war on clean coal.  We are now an exporter of energy to the world.

A transcript released by the U.K. media source The Independent suggests President Trump stuck close to his script on this (and other points):

We have ended the war on American energy, and we have ended the war on beautiful clean coal. We are now very proudly an exporter of energy to the world. 

These statements appear to relate to announcements made over the last year. Back in March 2017, President Trump signed an executive order which he described as "putting an end to the war on coal. We’re going to have clean coal — really clean coal." The U.S. does export a significant amount of energy -- and last year the Energy Information Administration projected that the U.S. would likely become a net exporter of energy within several years "as petroleum liquid imports fall and natural gas exports rise." Subsequent developments over the last year have lent preliminary support to this prediction.

President Trump's 2018 State of the Union speech did not otherwise directly address energy policy. That said, he did emphasize policy goals and achievements with respect to economic factors, such as tax cuts, job creation in manufacturing and other sectors, and improved small business confidence, as well as matters like national defense and immigration.

It can be tempting to infer administrative priorities from what is or isn't covered in a speech like this. At the same time, any leader has limited time to cover a host of important topics. With respect to energy matters, the speech emphasizes the Trump administration's focus on reducing regulations and increasing exports of America-produced energy resources.

New England's electric grid and winter 2017-18

New England's electricity grid is ready for reliable operations this winter, says the region's grid operator -- but special operating procedures might be required in the case of unexpected outages or fuel delivery constraints.

According to ISO New England Inc., the independent, not-for-profit regional transmission organization responsible for almost all of New England, supplies of electricity should be sufficient to meet regional consumer demand this winter. The grid operator projects a peak demand of 21,197 megawatts under normal winter temperatures (about 7 degrees Fahrenheit), or 21,895 megawatts of peak demand if extreme weather occurs (2 degrees F).

These projections are higher than last winter's actual peak demand (19,647 MW on December 15, 2016, during the hour from 5 to 6 p.m.), but lower than the region's all-time winter peak (22,818 MW, on January 15, 2004) or the record peak (28,180 MW on August 2, 2006). ISO-NE notes that total energy consumption and regional peak demand have remained flat in recent years "as a result of increased use of energy-efficiency measures and behind-the-meter solar photovoltaic (PV) systems."

The grid operator projects that it has commitments from enough power plants and demand-side resources to meet the forecast peak demand under both normal and extreme weather conditions. ISO-NE also points to its fifth seasonal Winter Reliability Program provides incentives for generators to stock up on oil or contract for liquefied natural gas, and also for demand-side resources committing to be available. As noted by the grid operator, the availability of generators with fuel has been a key reliability factor during recent cold winters, thanks in part to the past winter reliability programs. ISO-NE says its new capacity market performance incentive rules which take effect June 1, 2018 should eliminate the need for future special programs.

At the same time, the grid operator warns of its "continuing concern" over the availability of fuel for those power plants to generate electricity when needed. In a press release, ISO-NE noted, "The region’s natural gas delivery infrastructure has expanded only incrementally, while reliance on natural gas as the predominant fuel for both power generation and heating continues to grow." It observed that over 4,000 megawatts of natural-gas-fired generating capacity is at risk of not being able to get fuel when needed, due to natural gas pipeline constraints.

The grid operator also cites changes to the regional portfolio of generating resources, such as the May 2017 retirement of a 1,500 MW coal- and oil-fired power plant. According to ISO-NE, the Brayton Point power plant's closure "removed a facility with stored fuel that helped meet demand when natural gas plants were unavailable." The reliability benefits of stockpiled fuel and baseload power and related proposals are currently under examination by the Federal Energy Regulatory Commission.

The grid operator listed challenges that could affect power system operations such as "if demand is higher than projected, if the region loses a large generator, electricity imports are affected, or when natural gas pipeline constraints limit the fuel available to natural-gas-fired power plants," as well as the special operating procedures it would invoke in those circumstances.

Trump executive order on domestic energy policy

U.S. President Donald Trump has signed an executive order affecting domestic energy policy.  His March 28, 2017 Presidential Executive Order on Promoting Energy Independence and Economic Growth includes a variety of directives, generally aimed at reducing federal regulations affecting domestic energy production.  Here's a look at his Executive Order targeting Obama-administration climate regulations and other agency actions that potentially burden the development or use of domestically produced energy resources.

The Executive Order includes 8 operative sections.  One provides policy statements; six call for regulatory reviews that could lead to rule changes or revocations, or directly revoke and rescind Obama-era actions.  The final section includes general provisions.

Section 1 includes five policy statements, such as that "is in the national interest to promote clean and safe development of our Nation's vast energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production, constrain economic growth, and prevent job creation."  It also sets a federal policy "that executive departments and agencies (agencies) immediately review existing regulations that potentially burden the development or use of domestically produced energy resources and appropriately suspend, revise, or rescind those that unduly burden the development of domestic energy resources beyond the degree necessary to protect the public interest or otherwise comply with the law."

Section 2 calls for an immediate review of all agency actions that potentially burden the safe, efficient development of domestic energy resources, "with particular attention to oil, natural gas, coal, and nuclear energy resources."  It directs agency heads to submit a memorandum to the Office of Management and Budget detailing such potentially burdensome actions, and including "specific recommendations that, to the extent permitted by law, could alleviate or eliminate aspects of agency actions that burden domestic energy production."  With respect to actions targeted with specific recommendations in a final report, agency heads are directed to "as soon as practicable, suspend, revise, or rescind, or publish for notice and comment proposed rules suspending, revising, or rescinding, those actions, as appropriate and consistent with law."

Section 3 rescinds or revokes a variety of Presidential actions and reports, including several of President Obama's executive orders regarding climate change, the President's 2013 Climate Action Plan, and the Council on Environmental Quality's 2016 final guidance for federal agencies on consideration of greenhouse gas and climate issues in performing reviews of agency actions under the National Environmental Policy Act.

Section 4 calls for the Administrator of the Environmental Protection Agency to "immediately take all steps necessary to review" the Clean Power Plan governing electricity-sector emissions and related rules "for consistency with the policy set forth in section 1 of this order and, if appropriate, shall, as soon as practicable, suspend, revise, or rescind the guidance, or publish for notice and comment proposed rules suspending, revising, or rescinding those rules."

Section 5 disbands a working group on the social cost of greenhouse gas emissions, and restricts the ways agencies may account for the monetary value of changes in greenhouse gas emissions resulting from regulations.

Section 6 calls for the Secretary of Interior to lift moratoria on federal land coal leasing activities imposed under a 2015 order, and to commence federal coal leasing activities.

Section 7 calls for review of federal regulations affecting emissions from the oil and gas sector, including 2016 emissions standards for new, reconstructed and modified sources, and a 2015 rule governing hydraulic fracturing on federal and Indian lands, among others.

Section 8 includes general provisions, generally similar to those found in other executive orders.

ISO-NE winter electricity supply 2016-2017

New England should have sufficient electricity supplies to meet consumer demand this winter, according to regional power grid operator ISO New England, Inc.  But because natural gas pipeline constraints could limit electricity production, the grid operator has implemented a Winter Reliability Program to help ensure supply meets demand.

ISO-NE is the regional transmission organization responsible for most of New England's electric grid.  In that role, it forecasts electricity demand, and operates markets to match up generation with demand.

On December 5, 2016, ISO-NE released a statement addressing winter 2016-2017 with respect to electricity reliability.  The grid operator projects that at normal winter temperatures of about 7 degrees Fahrenheit, peak demand will reach 21,340 MW, or 22,028 MW if extreme winter weather of 2 degrees F occurs.  This would be above the 2015-2016 winter peak demand of 19,545 MW (February 14, 2016, from the hour from 6 to 7 p.m.), and below the all-time regional winter peak of 22,818 MW (a cold snap on January 15, 2004).

According to the grid operator, electricity supplies should be sufficient to meet consumer demand this winter -- but natural gas pipeline constraints and other factors create risks that could affect reliability.  Natural gas generated 49% of the region's electricity in 2015, and natural gas-fired power plants represent about 44% (or 14,850 megawatts) of the region's total generating capacity. But ISO-NE views about 3,450 MW of natural gas-fired generating capacity as "at risk" this winter due to the insufficiency of the region's natural gas infrastructure.  Despite some new pipeline projects and the present availability of liquified natural gas (LNG), the region faces the loss of 1,500 MW of coal- and oil-fired generation this spring with the closure of the Brayton Point Power Station in Massachusetts.

ISO-NE touts its 2016-2017 Winter Reliability Program as designed to address these "multiple risks" of pipeline constraints and non-gas unit retirement. As previously approved by the Federal Energy Regulatory Commission, the program will run from December 1, 2016 to February 28, 2017, and includes an oil inventory component, an LNG component, and a demand response component.

In light of this planning, and barring "unexpected resource outages or fuel delivery constraints," ISO-NE projects New England's electricity supplies should be sufficient this winter to meet consumer demand.

Adding micro-hydro to licensed hydropower project

What happens when a FERC hydropower licensee applies for a preliminary permit to study the feasibility of developing a micro-hydro project, where the new project will be sited at an existing project's dam?  In a recent case involving the city of Aspen, Colorado, Commission staff dismissed the preliminary permit application, instead suggesting that the licensee apply to amend its existing license to include the proposed new capacity and facilities.  Because many other existing dams may be candidates for the installation of new hydropower facilities, the Aspen Micro Hydro Project case illustrates important dynamics of hydropower licensing under the Federal Power Act.

The case centers on a March 4, 2015 application by the City of Aspen for a preliminary permit, pursuant to section 4(f) of the Federal Power Act, to study the feasibility of developing the Aspen Micro Hydro Project.  Most grid-connected hydropower in the U.S. is regulated under the Federal Power Act, and requires approvals by the Federal Energy Regulatory Commission.  As described in Commission documents, the proposed Aspen project would include an existing concrete diversion dam and intake structure, plus proposed new equipment including a draft tube, 10- to 20-kilowatt turbine-generator unit, and associated facilities interconnected to an existing utility transmission line.  The application describes project values including energy production, protection of the city's water rights, and instream flow protection for environmental benefit.  As noted in the application, "Renewable projects such as the Aspen Micro Hydro Project will permit the City of Aspen to reduce its reliance on coal-fired energy and comports with the City’s goal of reducing its energy-related greenhouse gas emissions. A local facility also will provide tangible evidence to residents and visitors of Aspen’s commitment to renewable energy."

Crucially, as noted by the Commission, the dam proposed for use in the Aspen micro-hydro project is currently licensed as part of another hydropower project: the City of Aspen's Maroon Creek Project.   Commission staff have noted that "for licensed projects, such as the Maroon Creek Project, section 6 of the [Federal Power Act] prohibits the alteration of licensed project works without the mutual consent of the licensee and the Commission."  On April 16, 2015, Commission staff sent the city a letter explaining that because the proposed micro-hydro project would be sited within the existing project boundary of the city’s Maroon Creek Project, any application for a permit or license within the project boundary would be denied.  For this reason, Commission staff concluded that "a preliminary permit for the Aspen Project would serve no purpose."  Instead, Commission staff informed the city "that it could instead file an application to amend its existing license to add the Aspen Project’s proposed capacity and related facilities to the Maroon Creek Project." 

Over a year later, the city filed a status report describing its intention to "enter into a business relationship with T-Lazy Seven Ranch (T-Lazy), a Colorado ranching company, for joint development of the Aspen Project."  The status report describes plans to form a new limited liability company, and ultimately to amend the permit application to replace the city as applicant with the new company.

In a November 15, 2016 Order Dismissing Preliminary Permit Application, Commission staff noted that the purpose of a preliminary permit is "to encourage hydroelectric development by affording its holder priority of application (i.e., guaranteed first-to-file status) with respect to the filing of development applications for the affected site."  The order also notes that the prohibition in section 6 of the Federal Power Act against the alteration of licensed project works without the mutual consent of the licensee and the Commission applies, no matter whether it is the existing licensee or the new entity who seeks to pursue additional development within the project boundary of the Maroon Creek Project.  The Commission's consent to alter licensed project works would presumably come in the form of an order amending the Maroon Creek Project's license -- a consent not formally requested int the Aspen Project's docket.

Continuing to find that a preliminary permit for the Aspen Project would serve no purpose for these reasons, the order dismissed the city's permit application.  The order leaves the door open for the licensee to seek to amend the Maroon Creek Project's license, potentially in concert with an application to transfer the licensee to a new licensee or co-licensee.

Beyond the City of Aspen's interests in hydropower, the case has regulatory implications for other proposals to develop micro-hydro or new generating capacity at dams or other structures already part of FERC-licensed projects.  A Department of Energy report released earlier this year found significant national potential to increase hydropower capacity, including by adding power at existing dams and canals.  Where the existing assets are part of a FERC-licensed project, developers will be wise to be mindful of how the Commission interprets the Federal Power Act.

FERC Summer 2016 energy market and reliability report

Federal energy regulatory staff have presented their 2016 Summer Seasonal Assessment to the Federal Energy Regulatory Commission.  The "Summer 2016 Energy Market and Reliability Assessment" presents an summer outlook by FERC's Office of Electric Reliability and Office of Enforcement on electricity and natural gas markets and reliability issues.

Highlights include:

• "low natural gas prices that have resulted from robust production and near record levels of natural gas in storage"
• electric system reserve margins are expected to be adequate this summer, though tighter in Texas
• total U.S. load forecast, when weather-adjusted, is essentially unchanged in recent years, largely due to little to no load growth in commercial and residential sectors
• the total generating capacity in the U.S. has decreased by approximately 2 percent since last summer, primarily due to coal retirements. According to the report, "The factors that prompted these closures include increased competition from natural gas, environmental regulations and an average fleet age that exceeded 50 years old."
• Over 18 gigawatts of new generating capacity will be installed nationwide through the summer, with a majority of these capacity additions coming from renewables such as wind and solar, plus the first new U.S. nuclear unit in over 20 years.
• Organized markets are attempting to manage the growing impacts of renewable generation.
• FERC staff expects natural gas fired generation to remain robust; natural gas fired generation has surpassed coal plant output since July 2015. Meanwhile coal stockpiles are growing due to a decrease in coal generation.
• Natural gas future prices have fallen since last year, though the Boston region's price drop is not significant.  Basis swaps -- financial instruments that represent the natural gas price differential between a specific point and the Henry Hub -- for Boston are priced higher than last summer, "suggesting expectations for greater congestion due to above-normal temperatures and a reduction in capacity along the Algonquin pipeline because of planned maintenance to tie in the Algonquin Incremental Market (AIM) expansion project this summer."

Stanford declines to divest fossil fuels

Should university endowments be invested in fossil fuel companies?  Or should they divest such holdings? Universities across the U.S. are considering these questions.  In the latest development, Stanford University's Board of Trustees has released a statement on climate change, describing the university's initiatives to battle climate change, but declining to divest Stanford's roughly $22 billion endowment from the fossil fuel industry.

In the April 25 statement, the Board describes climate change as "among the most serious challenges of our time."  The statement lists various elements of Stanford's strategic approach to combating climate change, including a $500 million transformative campus energy system, commitments to invest in solar, other renewable energy, wastewater recovery, green transportation, and energy efficiency in campus buildings.  The statement also announces the creation of a new climate task force to be composed of undergraduates, graduate students, faculty and staff, to solicit ideas for further action.

Much of the statement is structured as a response to a proposal by student organization Fossil Free Stanford that the university divest its endowment from the fossil fuel industry.  The trustees cite the university's Statement on Investment Responsibility as outlining a specific set of criteria by which the trustees may evaluate whether a company is inflicting social injury in a manner that warrants consideration of divestment.  The statement notes the establishment of an Advisory Panel on Investment Responsibility and Licensing, which studied the issues and made a recommendation to the Board’s Special Committee on Investment Responsibility, which in turn made a recommendation to the trustees.

According to the statement, the advisory panel "recommended divestment of companies whose primary business is oil sands extraction, a method that studies have found requires more water, and releases more carbon into the atmosphere, than other forms of fossil fuel extraction."  It cites Stanford Management Company as saying that the Stanford endowment has no direct exposure to companies whose primary business is oil sands extraction, so the trustees had no action to take on this point.

On the broader fossil fuel industry, the panel "concluded that it could not evaluate whether the social injury caused by the fossil fuel industry outweighs the social benefit it provides, and therefore did not recommend divestment."  The trustees agreed that the criteria were not met, and declined to divest.

That said, the statement expressed the trustees' belief "that the global community must develop effective alternatives to fossil fuels at sufficient scale, so that fossil fuels will not continue to be extracted and used at the present rate... the long-term solution is for all of us to reduce our consumption of fossil fuel resources and develop effective alternatives."

But despite investment and progress in research, including by Stanford, the trustees note that "at the present moment oil and gas remain integral components of the global economy, essential to the daily lives of billions of people in both developed and emerging economies."  The statement also notes the efforts of some oil and gas companies to explore alternatives.  The statement notes that "the trustees do not believe that a credible case can be made for divesting from the fossil fuel industry until there are competitive and readily available alternatives."

The statement also notes that the university's investment program does take climate change into consideration when evaluating the economic attractiveness of various investments.  In the trustees' words, "Prudent investors acknowledge that the world is beginning a transition away from carbon-based energy sources and that pricing for fossil fuels will reflect this transition."  The statement also notes the efforts of the endowment managers to "identify and support industry best practices that, in addition to positively impacting investment results, may pay significant environmental dividends."

This is not the first time Stanford has considered divesting from fossil fuels.  In 2014, after pressure from Fossil Free Stanford, the trustees announced a decision that Stanford would not make direct investments in coal mining companies, in recognition of "the availability of alternate energy sources with lower greenhouse gas emissions than coal."

ISO New England Regional Electricity Outlook 2016

The New England regional power system is in a state of major transformation, according to regional grid operator ISO New England, Inc.'s 2016 Regional Electric Outlook.

ISO New England is the private, non-profit entity that serves as the regional transmission organization for New England.  In this role, the ISO plans and operates the New England bulk power system, administers New England’s organized wholesale electricity market, and has some responsibility over system reliability.

The 2016 Regional Electric Outlook report is the latest annual installment of the grid operator's update on the state of the grid and the ISO’s efforts to ensure reliable electricity and to improve services and performance.  This year's report describes the New England grid administrator as "in the vanguard of a major transformation in how electricity is produced and delivered in the US."

Three waves of change -- natural gas, renewable energy and demand resources, and distributed generation -- are affecting New England's fleet of power resources, according to the report:

Natural-gas-fired generation has displaced older coal, oil, and nuclear plants. Weather-dependent renewable power resources and energy-efficiency measures are multiplying. On the horizon comes a “hybrid grid”—a combination of large power resources supplying the regional system while smaller ones directly supply consumer sites.

According to the report, coal, oil, and nuclear resources are retiring; it noted that resources representing about 30% of regional capacity have committed to cease operation or are at risk of retirement by 2020.  Most power plants planned to replace them will rely in part or in whole on natural gas or renewable generation.  The report notes:

Our region's natural-gas-fired power resources are among the newest, most efficient, and lowest-emitting plants in the country. When their access to low-priced gas from the Marcellus shale is unrestricted, New England has reliable, low-priced electricity.

The report also states that "wintertime access to natural gas has grown tight over recent years because the regional fuel transportation network has not kept up with demand from both generation and heating sectors."  As a result of pipeline constraints, the ISO notes "grid reliability challenges, emission increases during winter, and spikes in wholesale electricity prices."

The report also describes the ISO's tactics for managing the reliability risks associated with these shifts in the region's energy mix, including stronger "pay for performance" financial incentives for power resources to perform as required.  It cites various ISO studies indicating "that, ultimately improving the natural-gas-delivery infrastructure in New England" will best address reliability concerns, price spikes, and unnecessary emission impacts from oil and coal units during winter.

The report, along with previous years' reports, are available on the ISO's website.

FERC considers Primary Frequency Response reforms

U.S. energy regulators are considering whether reforms are needed to regulations for the provision and compensation of primary frequency response, a function essential to the electric grid's operation.

In general, the U.S. bulk power system operates on an alternating current.  For reliability and interoperability, that current must maintain its frequency within predetermined boundaries above and below 60 Hertz.  An interconnected grid’s ability to arrest and stabilize frequency deviations within those boundaries after a sudden loss of generation or load is called "frequency response." A grid's frequency response characteristics are affected by factors including inertial response (as spinning generators speed up or slow down when load changes), primary frequency response, and secondary frequency response.  Historically, most primary frequency response has been provided by baseload synchronous generators as an ancillary service.

But the U.S. electric grid's energy mix is changing.  In a Notice of Inquiry released on February 18, 2016, the Federal Energy Regulatory Commission notes that changes to the U.S. electric supply portfolio likely mean that fewer resources are now primary frequency response.  In particular, the U.S. has seen broad retirement of coal-fired baseload synchronous generators, some of which provide primary frequency response, while some have been replaced with variable energy resources such as wind and solar which do not typically have primary frequency response capabilities.

In response, FERC solicited public input on whether and what action is needed, including whether to:

• Amend the pro forma Large Generator and Small Generator interconnection agreements to require that all new generation resources have frequency response capabilities as a precondition of interconnection;


• Implement primary frequency response requirements for existing generation resources; and


• Establish procurement and compensation mechanisms for primary frequency response.

FERC has docketed the matter as RM16-6-000, Essential Reliability Services and the Evolving Bulk-Power System — Primary Frequency Response.  Comments on the Notice of Inquiry are due 60 days after publication in the Federal Register.

US Supreme Court stays Clean Power Plan

The Supreme Court of the United States has issued an order staying the U.S. Environmental Protection Agency's Clean Power Plan regulations limiting carbon emissions from electric power plants.  As a result, the rule's effect is frozen until legal challenges to the rule are resolved in federal court.

The Supreme Court of the United States.

EPA's final Clean Power Plan rule establishes emission guidelines for states to follow in developing plans to reduce greenhouse gas emissions from existing fossil fuel-fired electric generating units.  Developed by EPA pursuant to Clean Air Act Section 111(d), the regulation prescribes carbon reductions for states.

While state-level emissions reductions are federally prescribed, the rule places states in the role of developing their own compliance plans for how to reach the required emissions reductions.  The rule was published in the Federal Register on October 23, 2015, as Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units, 80 Fed. Reg. 64,662.  It gave states until September 6, 2016 to file a final plan, or an initial plan with a request for an extension, for EPA review.

If implemented, the EPA says the Clean Power Plan will reduce carbon emissions from power plants by 32% below 2005 levels, or about 870 million short tons.  EPA estimates the regulation could yield public health and climate benefits worth $54 billion in 2030 alone.  As states cut back on using carbon-intensive fuels such as coal and oil, EPA projects that renewable energy will grow, with utility-scale wind and solar expected to double by 2030 under the Clean Power Plan compared to 2013 levels.

But numerous lawsuits have been filed challenging the rule, along with petitions to stay or freeze its effectiveness pending judicial review.  Last month, the D.C. Circuit Court of Appeals denied petitions for stay from parties including states, utilities and trade groups such as the American Coalition for Clean Coal Electricity.

Parties then filed petitions for stay to the U.S. Supreme Court.  Under a 2012 Supreme Court precedent, Maryland v. King, a party seeking a stay must demonstrate (1) a "reasonable probability" that the Supreme Court will grant certiorari or agree to hear the case, (2) a "fair prospect" that the Court will reverse the decision below, and (3) a "likelihood that irreparable harm [will] result from the denial of a stay."  This is a relatively high burden.

Today a majority of the U.S. Supreme Court agreed to stay the Clean Power Plan rule, by order entered in the West Virginia, et al. v. EPA, et al. case and others consolidated into the West Virginia case.  In the Court's words:

The Environmental Protection Agency’s "Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units," 80 Fed. Reg. 64,662 (October 23, 2015), is stayed pending disposition of the applicant’s petition for review in the United States Court of Appeals for the District of Columbia Circuit and disposition of the applicant’s petition for a writ of certiorari, if such writ is sought. If a writ of certiorari is sought and the Court denies the petition, this order shall terminate automatically. If the Court grants the petition for a writ of certiorari, this order shall terminate when the Court enters its judgment.

The order notes that Justice Ginsburg, Justice Breyer, Justice Sotomayor, and Justice Kagan would deny the request to freeze the rule's effect.  This note reveals a 5-4 decision to issue the stay, with Chief Justice Roberts, Justice Scalia, Justice Kennedy, Justice Thomas and Justice Alito in the majority as supporting the stay.

With the Clean Power Plan's effect stayed, litigation over the rule will now proceed in the U.S. Court of Appeals for the District of Columbia Circuit.  The 27 states participating in challenges to the rule are likely cheering.  Those include Alabama, Arizona, Arkansas, Colorado, Florida, Georgia, Indiana, Kansas, Kentucky, Louisiana, Michigan, Mississippi, Missouri, Montana, Nebraska, New Jersey, North Carolina, North Dakota, Ohio, Oklahoma, South Carolina, South Dakota, Texas, Utah, West Virginia, Wisconsin and Wyoming.  Meanwhile, the 18 states who filed in support of the EPA, along with those states who have started preparing compliance plans for the regulation, now find themselves on less certain footing.  So too do electric power generators, and others interested in energy markets.  If controversy persists, whatever decision the circuit court issues is likely to be appealed to the Supreme Court.

NERC suggests Clean Power Plan reliability considerations

The electric reliability organization for North America has issued an assessment of reliability considerations it thinks state electricity and environmental regulators should take into account in crafting state plans to comply with the Clean Power Plan.

The North American Electric Reliability Corporation (NERC) is a not‐for‐profit regulatory authority whose mission is to assure the reliability of North America's bulk power system.

Last year, the U.S. Environmental Protection Agency (EPA) issued its Clean Power Plan, a final rule limiting carbon dioxide emissions for existing electric generation facilities.  States are expected to prepare individual or collaborative plans to comply with the regulation.  Because reducing the carbon intensity of electric power generation is the goal, EPA expects that some plans will include a shift from coal-fired power plants to less carbon-intensive sources.  As NERC wrote in its assessment:

The BPS is already undergoing a broad transformation with retirements of coal units and some nuclear units, and additions of resources fueled by natural gas, wind, and solar. Distributed generation, energy efficiency, and demand response are also changing the way in which system planners must account for resources. The CPP has the potential to hasten the transformation of the electric system started by market and political factors such as natural gas supply and pricing and federal and state policy decisions with respect to renewables and energy efficiency and other environmental regulations.

But reliability is a key issue at stake in any shift in the portfolio of generating resources.  The Clean Power Plan rule explicitly requires that states consider reliability as part of their plans.

NERC's assessment, Reliability Considerations for Clean Power Plan Development, presents its view of "aspects of plan design that need to be considered to reliably accommodate this broad transformation."  NERC's ten key reliability considerations are:

• State coordination with system planning entities - planners and coordinators working together
• Essential reliability services - "In order to maintain an adequate level of reliability through this transition, generation resources need to provide sufficient voltage control, frequency support, and ramping capability — essential components to the reliable operation of the BPS. It is necessary for policy makers to recognize the need for these services by ensuring that interconnection requirements, market mechanisms, or other reliability requirements provide sufficient means of adapting the system to accommodate large amounts of variable and/or distributed energy resources (DERs)."
• Timing considerations for energy infrastructure development - "Retirements can happen quickly, but adequate replacement facilities must be in service prior to retirement. As natural gas‐fired generation replaces coal‐fired generation the requisite timeline for natural gas pipeline infrastructure becomes even more relevant."
• Electricity imports and exports - "If a state intends to use resources from nearby states as part of a compliance strategy, it is important to determine if the necessary transmission capability is available to reliably transport electricity from those resources."
• Change in generator cycling and operations - coal plants may serve more seasonal peak demands, so "states should take account of changes in maintenance requirements likely due to cycling and the risk of increased forced outages of these coal‐fired plants. Additionally, increased and sufficient coordination between gas and electric system operators becomes much more critical to ensure adequate amounts of fuel are available."
• Reserve margin assessment - "As more variable and energy ‐ limited resources are added, the system will likely require additional reserve capacity to maintain a similar level of reliability compared to a system with all conventional generation."
• Energy efficiency - "Given that EE can be used as a potential CPP compliance tool, it is important that states evaluate the realistic potential for EE to displace load and the likely duration of those impacts. Shorter term EE measures may serve as a potential bridge to meet CPP requirements."
• Emissions trading - "In general, emissions trading promotes additional reliability compliance options by effectively broadening the compliance region as well as the availability of allowances and credits. However, some resource options that might be assumed available through emissions trading may not be, due to another state’s plan. Because trading is optional, states should coordinate to ensure the most beneficial approach of trading is considered."
• Reliability safety valve - "States must understand how the Reliability Safety Valve works and its limits, recognizing that it cannot be used as a planning tool to meet CPP requirements."
• North American and European precedents - states should review carbon market precedents like RGGI and shifts in Canada and Europe toward renewable and distributed resources as case studies for potential strategies, lessons learned in implementation, and insights as they develop their plans.

Some states are already developing Clean Power Plan compliance plans.  Meanwhile, judicial challenges have been filed.  Initial plans are due to the EPA later this year.

Climate and energy in 2016 State of the Union

President Obama delivered his final State of the Union address on January 12, 2016.  The White House has posted his remarks as prepared for delivery to Congress.  Climate change, and related energy and environmental issues, formed a prominent theme in this year's speech.

The White House.

Climate change first surfaced in the 2016 State of the Union as part of one of four "big questions" President Obama posed for the nation.

Second, how do we make technology work for us, and not against us -- especially when it comes to solving urgent challenges like climate change?

After announcing a "moonshot" medical research effort to cure cancer to be led by Vice President Joe Biden, President Obama said, "We need the same level of commitment when it comes to developing clean energy sources."

He then spent several minutes addressing climate change directly.  First, he noted effective consensus that climate change is a topic worth tackling:

Look, if anybody still wants to dispute the science around climate change, have at it. You will be pretty lonely, because you’ll be debating our military, most of America’s business leaders, the majority of the American people, almost the entire scientific community, and 200 nations around the world who agree it’s a problem and intend to solve it.

He then touted the economic and environmental effects of investment in renewable and distributed generation and energy storage:

But even if -- even if the planet wasn’t at stake, even if 2014 wasn’t the warmest year on record -- until 2015 turned out to be even hotter -- why would we want to pass up the chance for American businesses to produce and sell the energy of the future?

Listen, seven years ago, we made the single biggest investment in clean energy in our history. Here are the results. In fields from Iowa to Texas, wind power is now cheaper than dirtier, conventional power. On rooftops from Arizona to New York, solar is saving Americans tens of millions of dollars a year on their energy bills, and employs more Americans than coal -- in jobs that pay better than average. We’re taking steps to give homeowners the freedom to generate and store their own energy -- something, by the way, that environmentalists and Tea Partiers have teamed up to support. And meanwhile, we’ve cut our imports of foreign oil by nearly 60 percent, and cut carbon pollution more than any other country on Earth.

Gas under two bucks a gallon ain’t bad, either.

President Obama then called for changes to transition to clean energy sources:

Now we’ve got to accelerate the transition away from old, dirtier energy sources. Rather than subsidize the past, we should invest in the future -- especially in communities that rely on fossil fuels. We do them no favor when we don't show them where the trends are going. That’s why I’m going to push to change the way we manage our oil and coal resources, so that they better reflect the costs they impose on taxpayers and our planet. And that way, we put money back into those communities, and put tens of thousands of Americans to work building a 21st century transportation system.

Now, none of this is going to happen overnight. And, yes, there are plenty of entrenched interests who want to protect the status quo. But the jobs we’ll create, the money we’ll save, the planet we’ll preserve -- that is the kind of future our kids and our grandkids deserve. And it's within our grasp.

Climate change is just one of many issues where our security is linked to the rest of the world.

His final reference to climate change came while discussing international engagement, and "seeing our foreign assistance as a part of our national security":

When we lead nearly 200 nations to the most ambitious agreement in history to fight climate change, yes, that helps vulnerable countries, but it also protects our kids.

Climate, energy, and environmental issues thus featured prominently in the 2016 State of the Union speech.  Over the coming year, these themes -- domestic and international action on climate change, investment in renewable energy and distributed generation, transition away from oil and coal -- will likely continue to play out at the federal level.

US Clean Power Plan adopted

President Obama will formally unveil the Clean Power Plan today, a set of regulations by the U.S. Environmental Protection Agency (EPA) to reduce carbon emissions associated with the electric power industry.  A blog post by EPA Administrator Gina McCarthy emphasizes the Clean Power Plan's protection of health and the environment, states' rights to choose their own implementation paths, reduction of future energy costs, and leadership on climate issues.  But some politicians, utilities and states have expressed concern about the regulations' impact, and could launch legal challenges -- or states might refuse to comply.  What's in store for the Clean Power Plan?

It has been just over a year since EPA first released its draft Clean Power Plan in June 2014.  These regulations under Section 111(d) of the Clean Air Act are designed to reduce the carbon intensity of the U.S. electric power sector -- essentially, how many pounds of carbon are emitted per megawatt-hour of electric energy produced.  Under the draft Clean Power Plan, EPA sets carbon intensity limits for each state, collectively designed to reduce carbon emissions by 30% below 2005 levels.  Each state then designs its own compliance plan using any combination of "building blocks": types of measures like improving the efficiency of fossil fuel power plants, switching out coal- and oil-fired power plants in favor of natural gas, and increasing low- and zero-carbon generation.

While the final Clean Power Plan's basic structure remains much the same, EPA has made some modifications in reaction to concerns about the greenhouse gas regulations' costs and impacts to grid reliability.

Changes from the 2014 draft include:

• Two extra years (until 2022) for states to meet their targets, and greater flexibility for states to form regional pacts to facilitate emissions-cutting projects across state lines, such as the Regional Greenhouse Gas Initiative.
• A new “safety valve” feature, to let states appeal for extensions and other relief if complying with the regulations causes disruptions to power supply.
• Increased social justice incentives for utilities to construct renewable energy projects in poorer neighborhoods, reducing pollution-related illness and eventually lowering electricity rates.
• Energy efficiency is still encouraged, but has been eliminated as one of the rule’s "building blocks” for states to use in building their own carbon-reduction plans.

How will the Clean Power Plan story continue to play out?  Will it be challenged in court?  Will states comply?  What impacts will it have on the U.S. electric power industry?

Coal power plants retiring in 2015

The U.S. portfolio of electric power plants will continue to shift in 2015, according to a federal assessment projecting that nearly 16 gigawatts (GW) of generating capacity will retire in 2015.  Most of the capacity to be retired this year is coal-fired generation.  This continues a multi-year trend away from coal, and toward natural gas and renewable resources.

According to the U.S. Energy Information Administration, nearly 16 GW of generating capacity is expected to retire in 2015.  Of this, 81% (12.9 GW) is coal-fired generation.  Generator retirements are heavily composed of coal-fired generation, split between bituminous coal (10.2 GW) and subbituminous coal (2.8 GW).  Most of this retiring coal capacity is found in the Appalachian region, with slightly more than 8 GW combined in Ohio, West Virginia, Kentucky, Virginia, and Indiana.

New environmental regulations and struggles to remain cost-competitive explain most of these retirements.  This year, the Environmental Protection Agency's Mercury and Air Toxics Standards (MATS) take effect.  MATS requires existing large coal- and oil-fired electric generators to meet stricter emissions standards by retrofitting the units with new emissions control technologies.  While some units have been granted extensions to operate through April 2016, some power plant operators are choosing to retire units instead of making cost-prohibitive investments in pollution control.

Most of the coal-fired units slated for retirement are smaller and operate at a lower capacity factor than average coal-fired units in the United States.  According to EIA, the to-be-retired units have an average summer nameplate capacity of 158 MW, just 60% as big as the 261 MW average for other coal-fired units.  In 2014, the average capacity factor for all coal units was 61%, but the subset of coal units retiring in 2015 had an average capacity factor of just 36%.  The relatively small size and low capacity factor of these power plants make it harder for them to compete economically against other generation sources.  This competition is especially difficult if sufficient natural gas-fired generating capacity is available, as the cost of natural gas has fallen to levels not seen since 2012.

The coal capacity retiring in 2015 accounted for 1.6% of total U.S. generation during 2014.  At the same time, electric generating companies expect to add more than 20 GW of utility-scale generating capacity to the power grid.  This new capacity is dominated by wind (9.8 GW), natural gas (6.3 GW), and solar (2.2 GW), which together compose 91% of expected new capacity in 2015.