U.S. POWER INDUSTRY OUTLOOK 2016

THE CLEAN POWER PLAN IS A “FULL-EMPLOYMENT ACT” FOR RENEWABLE DEVELOPERS; EPA HAS MORE WORK TO DO ON THE MERCURY RULE

The outlook for the U.S. power industry became more defined in 2015 with the release of the Obama administration’s Clean Power Plan (CPP) and the U.S. Supreme Court’s decision to send the Mercury and Air Toxics Standards (MATS) back to the Environmental Protection Agency (EPA) for additional work.

Assuming the CPP survives legal challenges, those two events will make the U.S. power market cleaner, greener and gassier over the next five years. Indeed, renewable energy and gas-fired generation are virtually the only types of new generation developers plan to build between 2016 and 2020 (Figure 1).

But policymakers, regulators and judges, no matter how powerful, cannot dictate market outcomes by themselves; market forces also play a role. And the market spoke loudly in 2015: The shale revolution held natural gas prices low, and declining manufacturing costs allowed wind and solar companies to field ever-more-competitive offerings. These factors played an important role in deepening developers’ commitment to building gasfired and renewable generation.

Those trends also caused widespread heartache in Coal Country, where anger continued to be channeled into challenging the administration’s environmental regulations in court. It will be some time before the expected litigation over the CPP works its way through the federal courts. The court decision on MATS, however, was welcomed as good news by the coal industry.

But while coal is fighting separate battles against natural gas, renewables and the Obama administration, it is also waging — and losing — a battle with energy efficiency, distributed generation and other customer programs that are cutting into electric demand growth.

A growing number of businesses and homeowners are installing distributed generation and energy-efficiency upgrades, as well as taking advantage of alternate electric pricing options offered by utilities — all of which are geared to reducing future electric demand growth. In a slow-growth setting, there is less need to construct new, large and expensive central-station coal generators.

Higher efficiency standards for building envelopes, and appliances, such as refrigerators and big-screen televisions, are baking in long-term reductions in electricity use. In California, for example, any home built after 2020 has to be net zero energy. It does not have to be disconnected from the electric grid, but the amount of electricity it takes from the grid must be offset by the amount of electricity the home produces and sells back to the grid.

These demand-side initiatives are a big reason why our five-year outlook for new generation continues to fall. Over the 2016 to 2020 period, we project construction will begin on about 157 GW of generating capacity, continuing the recent trend of declining construction starts for new generation.

Overview

President Obama and EPA Administrator Gina McCarthy unveiled the Clean Power Plan (CPP) at a White House ceremony in August. The final rule followed the administration’s pledge, made in mid-2013, to significantly reduce carbon dioxide (CO2) emissions from coal-fired power plants. The August 2015 final rule came 14 months after the release of a draft rule, which drew more than 4.3 million public comments, many of them negative from the coal and electricity industries.

Weighing in at 1,560 pages, plus an additional 343 pages for a regulatory impact analysis, the CPP calls for a 32% reduction in CO2 emissions from existing coal-fired power plants by 2030 compared to a 2005 baseline. In absolute terms, the CPP aims to reduce CO2 emissions by 870 million tons by 2030. The rule sets out interim milestone reductions starting in 2022.

One compliance option open to generators is to dramatically increase reliance on renewable generation, such as wind and solar. By 2030, the plan envisions renewable generation (including hydro) comprising 28% of U.S. generating capacity. Those same resources accounted for about 15% of all generating capacity in 2012, according to the EPA.

The industry waited for two years for this particular shoe to drop, and few people doubt that the CPP will be litigated all the way up to the U.S. Supreme Court. Legal scholars are split on whether the final rule will withstand legal challenge. Ultimately, it may fall to the nine robed justices at the Supreme Court, once again, to play a significant role in setting U.S. electric and environmental policy — and with it a good chunk of the economy as well.

Those justices gave Coal Country some solace earlier this year when it sent the MATS rule back to the EPA for revision. The court criticized the agency for promulgating such a broad rule without undertaking a costbenefit analysis.

MATS was scheduled to go into effect at year end 2015. Given that rule’s tight compliance timeline, many utilities have already moved to close older, smaller and less-efficient coal-fired power plants, or made commitments to install mercuryreduction equipment at some of their coal-fired power plants.

The EPA and its litigants will head back to the D.C. Circuit Court of Appeals to wrangle over how to make the MATS rule comply with the Supreme Court’s instruction. Until the “revised final” MATS rule clears the federal courts, coal-fired power stations will continue to exist in a regulatory limbo.

Given that MATS has been under development for several years, we believe most utilities have made most of their decisions about which coal plants will be closed, which will be converted, and which will have pollution-control equipment installed. But not all of those decisions have been made public. Utilities could make some lastminute changes in their MATS compliance plans, depending on how the next round of litigation unfolds.

Coal outlook

New-build coal-fired generation has been dormant for several years, and we see nothing in the near term that will change that. Most of the coal-related spending over the next five years will go to maintenance and in-plant capital projects, such as environmental compliance projects and efficiency upgrades.

Prior to its unveiling in August, fear about the Obama administration’s determination to cut CO2 emissions from power plants was one reason developers did not move forward with coal projects. Numerous electric generators, EPC firms, state officials, equipment manufacturers and coal companies objected strongly to the draft CPP and the final rule for several reasons. Operationally, those reasons include:

• The plan’s implicit anointment of natural gas as a baseline fuel for electric generation tramples on fuel diversity, a longstanding industry practice

• Virtually the only way to preserve coal as an electric option would be to install carbon capture & sequestration (CCS) technology, which is expensive and not broadly proven at commercial scale, or to build integrated gasification combined cycle (IGCC) generators, which also are expensive. The only way to build new coal capacity is to include CCS.

Carbon capture

Various CCS technologies are being demonstrated at power plants in North America and overseas (Figure 2). The world’s first commercial- scale, post-combustion CCS project went online in late 2014 in Saskatchewan at Unit 3 of the Boundary Dam Power Station.

That unit has generating capacity of about 120 MW. The utility, SaskPower, reports that initial results are exceeding expectation. The cost of that project: about $1.5 billion, including Canadian federal government support.

The industry is keeping a close eye on the Boundary Dam CCS project. Industry officials worry that a data set consisting of one point is a slim reed on which to hang the fate of a nation’s electricity industry.

U.S. efforts to prove CCS technology at commercial scale foundered in early 2015, when the federal government withdrew financial support for the FutureGen 2.0 project in Meredosia, Illinois.

The Clean Power Plan did not mandate deployment of CCS technology. Rather, it set a power plant emission level that approximates emissions from a high-efficiency combined cycle generator burning natural gas, and laid out several options that companies could take to lower their CO2 footprint.

One of those ways would be to construct IGCC generators. Once hailed as a potential savior for coal-fired power, IGCC has turned into a headache for utilities. One project, Duke Energy’s Edwardsport plant in Indiana, cost significantly more than projected, and its initial capacity factor under-performed expectations.

Another IGCC project, the Kemper County plant in Mississippi, this year nearly plunged its owner, Mississippi Power, into bankruptcy. At the last minute, Mississippi utility regulators came through with $159 million of emergency price increases. But in a separate decision, the utility also was forced to refund money it had collected from customers as the plant was being built.

That 582 MW plant, with a total estimated price tag of about $6.1 billion, is about $2 billion over budget. The Kemper County IGCC is scheduled to begin operation in early 2016, roughly two years behind schedule.

If $6.1 billion proves to be the generator’s final price tag, it will work out to about $10.5 million per megawatt (MW) of installed capacity. That is roughly ten times the cost to construct a high-efficiency, combined cycle generator.

Owners of coal-fired power plants continued to close older, smaller and less-efficient coal plants in 2015, mostly to comply with the MATS deadline, which the EPA may modify when it revises the rule to comply with the Supreme Court’s 5-4 decision in Michigan et al. v. Environmental Protection Agency et al.

Industrial Info Resources (IIR) projects that 65,000 MW of coal-fired capacity will be prematurely closed between 2010 and 2020. We estimate 76 units totaling 15,000 MW of capacity will be closed this year. This follows several years of coal plant closures.

Looking forward, assuming the EPA’s revision to MATS survives future court challenges, we expect coal plant closures to decline for a few years but then surge in the 2020 to 2022 timeframe as the first compliance milestone of the CPP nears. The CPP could lead to the closure of an additional 49,000 MW of coal-fired generation.

Developers plan to break ground on about 2,188 MW of new coal-fired generation over the next five years, virtually the same amount as we reported last year. Those proposed projects, under development for many years and postponed several times, are expected to account for about 1.4% of all new generation construction starts between 2016 and 2020.

The projects will be located mainly in the Midwest, Southeast and Southwest. In the current regulatory climate, we think it is unlikely any of those proposed projects will break ground in the next five years. Problems securing permits, or water, or financing, likely will prove difficult if not impossible to overcome.

On the flip side of the coin, developers have cancelled or postponed the start of construction for 13 coal-fired generators valued at about $25.3 billion that were scheduled to break ground between 2016 and 2020.

In fact, virtually the only bright spot for companies supplying equipment and services to coal plants is the capital spending that will be needed to keep larger, newer, and more-efficient coal-fired generators operating. We are tracking approximately $17 billion in coal-plant capital projects that are scheduled to begin construction between 2016 and 2020. This includes:

• Pollution-control projects to reduce emissions of sulfur dioxide (SO2), nitrogen oxides (NOx), mercury (Hg) and acid gases

• Cooling water system upgrades to comply with Section 316(b) of the Clean Water Act

• Ash-handling projects

• Wastewater upgrades

• Fuel conversions to biomass or gas

• Dismantlement and demolition of existing facilities

• Control system upgrades.

This amounts to a slowdown from projected spending for previous five-year periods, but it remains a healthy book of business nonetheless. The areas expected to see the greatest investment in pollution-control equipment over the next five years are states located in the Midwest, Plains and Southeast regions.

Natural gas outlook

Natural gas-fired construction surged in 2015, and we expect it to continue for the next five years. Abundant domestic natural gas supplies have kept prices low, particularly for generators located near the major shale formations, such as the Marcellus, Eagle Ford, Haynesville, as well as the Permian Basin.

Gas continued to increase its share of the electricity mix in 2015. In April 2015, approximately 31% of all U.S. electricity was generated by natural gas, the first time gas surpassed marketshare leader coal. Coal accounted for about 30% of U.S. electricity that month, according to the Energy Information Administration’s (EIA) Electric Power Monthly (Figure 3). However the next month coal narrowly recaptured the marketshare lead with 32.6% of power coming from that fuel compared to 31.4% of electricity coming from gas that month, EIA reported.

Through mid-2015, about 34% of the nation’s electricity was generated by coal, compared to 31% for gas. Five years ago, in the early years of the shale revolution, about 44% of U.S. electricity was generated by coal, double the 22% share of the market by gas. Over the next five years, as its share of the market grows, IIR expects Florida, Texas and California to be the states with the most robust growth in gasfired power development.

Across the nation, gas has long been the leading near-term compliance fuel of choice for generators. Even if the Clean Power Plan is overturned by the courts, we expect gas to continue to be the fuel of choice for new generation. If the CPP is sustained in the courts, we expect the dash to gas to become a stampede.

Over the next five years, developers plan to break ground on more than 67,000 MW of new gas-fired generation, accounting for about 43% of all new power plant construction activity in the U.S. The total investment value of these projects is about $71 billion.

Compared to our five-year outlook last year, gas plant development has surged in the Southwest and New England regions. Developers plan to break ground on more than 23,000 MW of new gas generation in the Southwest between 2016 and 2020. Over that same time span, more than 9,000 MW of new gas generation is scheduled to begin construction in New England.

Gas power construction activity also is expected to increase in the Rocky Mountain and Southeast regions, though at a more measured pace compared to our year-ago forecast. However, planned gas-fired additions in the Northeast and Great Lakes regions have fallen significantly over the last year. In the West Coast, the market for new gas generation remains strong, though down somewhat from last year’s projection.

One trend we have noticed is that natural gas combined cycle (NGCC) plants being developed are larger and more expensive than in prior years. We are tracking a dozen plants, each with total investment value (TIV) exceeding $1 billion, that are scheduled to begin construction between 2016 and 2020. Some of these plants include:

• Hendry County Power Station in Florida

• Cricket Valley Energy Station in New York

• Greensville County Power Station in Virginia

• Mattawoman Generating Station in Maryland

• Okeechobee Clean Energy Center in Florida

• Lebanon Valley Power Station in Pennsylvania.

IIR tracks and verifies power-plant development through direct contact with developers. Not all projects that are announced will move forward according to their initial schedules. However, based on historical experience, we expect that about 50% of announced gas projects will move forward according to the original timelines laid out by developers. So while developers have announced plans to begin constructing more than 67,000 MW of new gas generation between 2016 and 2020, about half of that should move forward according to schedule.

Renewables outlook

Developers of wind, solar and other nonhydro renewable generation probably toasted their good fortune when the final CPP was announced. That rule would fundamentally reorient the U.S. electricity mix. By 2030, renewables (including hydro) are expected to account for about 28% of all U.S. generating capacity, significantly higher than the 15% of capacity that renewables comprised in 2012, according to the EPA.

We are tracking a total of about 87,000 MW of renewable generation capacity scheduled to kick off construction between 2016 and 2020. That is about 55% of all new generating capacity planned for that time. The TIV of those projects is about $182 billion. The regions experiencing the greatest surge in renewables construction between 2016 and 2020 are the Rocky Mountains, West Coast, Southwest, Midwest and Great Lakes. More muted growth is seen for the Mid-Atlantic, Northeast and Southeast regions.

Wind generation’s capacity factors have steadily increased in recent years, and equipment manufacturers are working hard to continue that trend. Still, despite engineering and materials advances, wind power cannot generate electricity when the wind does not blow, and solar power generates no electricity when the sun does not shine.

Advances in electric storage could help renewables overcome this inconvenient truth, and storage technologies are drawing a lot of interest and investment. For the next few years, however, wind and solar will require dispatchable generation to back it up. More often than not, that backup power will be fired by natural gas.

The CPP is something close to a national renewable portfolio standard (RPS), just the thing renewables developers needed at a time when the effect of state-level mandates are diminishing because utilities have come close to fulfilling their obligations. While California significantly has boosted its RPS this year — to 50% by 2030 — some other states have frozen or tried to repeal their RPSs, arguing they inflate electric costs.

Overall, as utilities attain their renewables requirements, federal tax and energy and environmental policies will be the most important drivers of that sector’s growth.

Declining costs have made some windpower installations competitive on their own, without the benefit of production tax credits (PTC). The PTC, which expired at yearend 2014, offered 30% tax incentives for up to 10 years for windpower plants that incurred 5% of their capital costs by the end of 2014, and were operating by yearend 2016. That works out to about 2.3 cents per kilowatt-hour of electricity generated.

A burst of wind power

This year saw a frenzied burst of windpower construction activity as developers and EPCs put their noses to the grindstone while keeping their eyes on the calendar. IIR estimates that, when 2015 is all said and done, a total of 60 units totaling 8,500 MW of new wind generation will be added this year.

In 2016, we expect to see the completion of 73 windpower projects totaling 8,700 MW that met the PTC capital commitment requirement at yearend 2014. After 2016, however, future development largely depends on whether the CPP is sustained by the courts.

If it is, that could drive a second buildout, but that is not expected to materialize until 2018 at the earliest. New wind generation also is being driven in regions of the country where long-term power purchase agreements are making wind competitive with natural gas-fired capacity.

We are tracking developers’ plans to begin construction of 105 utility-scale solar projects valued at about $25.7 billion between 2016 and 2020. However, because renewables projects have tended to be postponed or cancelled more frequently than gas-fired power projects, IIR does not expect construction to begin on schedule for more than about $8 billion to $10 billion of these projects over the next five years. Still, that is a good book of business.

The industry saw brisk development of solar, principally photovoltaic (PV), generation in 2015. We expect that to persist into 2016 as the Investment Tax Credit (ITC) nears its yearend 2016 expiration date. After 2016, the ITC, currently 30%, declines to 10%, but that is not expected to become a major hurdle to new PV construction.

The PV industry has made dramatic efficiency gains in recent years, and some in that industry claim PV is a proven technology that can compete without benefit of federal tax credits. We take the industry at its word, and thus see no dramatic drop-off in PV construction starts after the ITC falls to 10% at the end of 2016.

As with windpower, a second wave of solar deployments could flow from the CPP. If the CPP is sustained by the courts, solar developers likely will have a full pipeline of projects for several years to come, though a lot of that project activity will not take place until 2020 or after.

Overall, IIR is tracking development of 45 utility-scale solar projects valued at $26 billion that are scheduled to kick off between 2016 and 2020. It bears repeating that we do not expect all of these projects to begin turning dirt according to their current schedule.

As in prior years, the states expected to see the most new solar generation are California, Arizona, Nevada and New Mexico. Nearly 7,500 MW of new solar is scheduled to begin construction in California during the 2016-2020 timeframe, followed by Arizona (3,500 MW), Nevada (2,100 MW) and New Mexico (1,000 MW).

In prior years, most new solar construction was geared to utility scale of 1 MW or more. But solar flourished at a smaller scale in 2015, driven by so-called rooftop installations, as well as community solar gardens and distributed generation (DG) projects for businesses. We see that trend continuing for the next few years (Figure 4).

Regulators are increasingly leaning on utilities to find politically palatable ways to support the addition of solar panels to customers’ rooftops. Sharp regulatory battles have broken out in public utility commission (PUC) hearing rooms across the nation over net metering, basically how much customers with rooftop solar units should be charged to maintain their proportional share of the electric grid.

The development of electricity storage technologies is predicted to have a significant influence over the pace of adoption of rooftop solar power during the next five years. (Elon Musk, whose companies are marketing the Tesla electric vehicle, unveiled homeowner electric storage technology this year at a price tag reportedly exceeding $10,000 per home.)

Another factor accelerating adoption of rooftop solar is the convenient no-moneydown sales pitch. In that case, developers retain ownership of the equipment and the homeowners pay a lease fee that generally is lower than their electric bill. In the same way that leasing transformed the auto market, driving increased consumer purchasing, some see leasing as a significant factor that will accelerate the deployment of rooftop solar in the U.S.

Nuclear outlook

The nuclear power industry has been down this road before. A decade ago, the prospect of tighter federal environmental regulation of power plants (what eventually became known as the Cross-State Air Pollution Rule) heartened the nuclear industry and led to talk of a nuclear renaissance. Dozens of new nuclear projects were announced, as developers were eager to test the Nuclear Regulatory Commission’s streamlined combined construction and operating license (COL) process.

Then it became a game of “chicken.” Two dozen utilities looked at each other, wondering who would make the first commitment. Georgia Power and South Carolina Electric & Gas (SCE&G) became the first two utilities to commit to add new nuclear units to existing generator sites (Figure 5). With great fanfare, dirt was turned just about the time the shale revolution was starting to upend energy markets.

Since that time, the cost of natural gas for electric generation has fallen by over 67% as new techniques and technologies combined to extract huge volumes of gas from formations once thought to be uneconomic or mature.

Since the shale revolution began, nuclear utilities have cancelled or postponed 26 projects valued at $230 billion that were scheduled to begin construction between 2016 and 2020. Most of this work would have been grassroot projects and unit additions.

Privately, the nuclear industry is cautiously optimistic that the Clean Power Plan, if sustained by the courts, would support development of new nuclear generation. At the same time, the nuclear industry recognizes that units under construction in Georgia and South Carolina need to be finished with a minimum of further delays and cost escalation before new nuclear will ever be considered as a cost-effective source of electric generation. Further delays or cost overruns at those plants would be an added burden holding back new nuclear.

Extended power uprates have virtually disappeared from the near-term screens of nuclear generation planners. In part, that is because uprate projects that made the most economic sense already have been completed.

According to IIR’s North American Electric Power Database, U.S. nuclear utilities completed 23 uprate projects valued at about $4 billion between 2010 and 2014. But four other uprate projects, valued at about $2 billion that were supposed to begin construction between 2016 and 2020, have been cancelled or postponed.

The long-running saga over where to put spent nuclear fuel shows no sign of ending anytime soon. So equipment suppliers and EPC firms can expect some modest amount of work going forward to build onsite storage for spent nuclear fuel. But as long as Harry Reid remains a leader in the U.S. Senate, Nevada is unlikely to serve as the nation’s nuclear repository.

Looking forward

The U.S. generating fleet has undergone a transformation over the last five years, and we expect that transformation will gain speed over the next five years. President Obama, intent on crafting an environmental legacy, has directed dramatic changes in environmental regulation of the U.S. power industry.

Those changes, coupled with declining prices for natural gas and renewables, have fundamentally altered longstanding assumptions about the cheapest and most reliable ways to generate electricity.

We expect the debate over the wisdom and legality of many of those measures will continue in 2016 and even after the nation selects a new president next November. But non-electoral events will also drive the electric market.

The so-called Polar Vortex of early 2014 dramatically drove up power prices in the Northeast, causing some to question that region’s high dependence on electricity generated from natural gas. Although the U.S. has an enviably large supply of low-cost natural gas, building pipelines to transport that gas to where it is needed remains a challenge.

The march to a cleaner, greener and gassier power industry is unlikely to move in a smooth and linear fashion. The industry should expect more zigs and zags — whether from fuel markets, regulators, equipment suppliers, anti-pipeline forces, lawmakers or the weather.

Another historically cold winter that drives gas prices into the stratosphere for more than a week or so could rekindle the debate over fuel diversity in our nation’s power industry. And the dash to gas could also be reversed if a scientific consensus develops that hydraulic fracturing poses significant public health hazards.

Finally, President Obama’s environmental legacy could be wiped out if in 2016 Republicans capture the White House and keep their majorities in the Senate and House of Representatives.

Any of these events, or others, could force yet another redirection of U.S. electric and environmental policy. But at this point, before the winter heating season of 2015- 2016 begins, and a year away from national elections, we do not see anything in the data we track that would suggest power developers are betting on those “black swan” jolts. Rather, as Wall Street learned long ago, the trend is your friend. Accept the opportunities it provides, but be ready for sudden shifts in sentiment.

Authors

Britt Burt is vice president of Global Power Industry Research for Industrial Info Resources. Headquartered in Sugar Land, Texas, with five offices in North America and 10 international offices, IIR provides global market intelligence for companies in the power, heavy manufacturing and industrial process businesses.

Shane Mullins is IIR’s vice president of Power Industry Product Development. IIR databases, market forecasts, and custom analytics are used by EPC firms, power developers, utilities, financial services firms, equipment manufacturers and professional services firms to build their business. Brock Ramey is North American Power Specialist for IIR. For more information see www.industrialinfo.com or email powergroup@industrialinfo.com