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RENEWABLE AND GAS PROJECTS DOMINATE NEW BUILD PLANS FOR THE NEXT FIVE YEARS; COAL SPENDING FOCUSES ON IN-PLANT CAPITAL AND MAINTENANCE
The U.S. power industry continued its forced march to a lower-carbon future in 2014, prodded by federal court rulings and environmental regulations that caused heartaches in coal country, but happiness for developers of renewable and natural gas-fired generation. Industrial Info Resources believes that trend will continue for the next few years as regulations and economics combine to accelerate the turnover of the generating fleet.
Among the key federal developments during 2014 on the legal and regulatory fronts:
• The U.S. Supreme Court in May upheld the Environmental Protection Agency’s Cross-State Air Pollution Rule (CSAPR). This ruling dealt a blow to coalfired generation. But it also created some clarity for utilities, as well as business opportunities for companies making or installing pollution-control equipment. The industry is awaiting the EPA’s final implementation details and an updated compliance timeline.
• The EPA finalized in May its rule on thermal plant water-intake systems under Section 316(b) of the Clean Water Act. Affected asset owners will be required to conduct studies over the next few years. We do not expect to see any 316(b)-related construction spending to take place until about 2018.
• In June, the agency released its draft Clean Power Plan regulating emissions from existing fossil-fueled generation. The EPA will be taking public comments on that draft until mid-2015. Once it is finalized, and if it survives legal challenges, states will need to file compliance plans with the agency.
• Environmental regulators spent the year mulling comments on its draft of New Source Performance Standard (NSPS) for carbon dioxide (CO2) emissions from future power plants. It is not yet clear when that rule may be finalized.
Meanwhile, utilities, EPC firms and power developers are keeping their eyes on year-end 2015, the effective date for compliance with the Mercury and Air Toxics Standards (MATS). In terms of transforming the U.S. generating fleet, MATS is the Big Kahuna: by 2020, industry insiders expect it to force retirement-or-retrofit decisions for hundreds of coal-fired power plants with a total generating capacity of 60 gigawatts (GW).
Industrial Info is tracking 1,338 proposed power projects totaling about 165 GW where construction is scheduled to begin between 2015 and 2019 (Figure 1). The total investment value (TIV) of these projects is approximately $429 billion. Our project data covers new-build generation of all types, unit additions, in-plant capital and maintenance, pollution-control and industrial energy projects.
We do not expect all of those projects to begin on schedule. In fact, based on historical construction-starts data for the power industry, we believe somewhat less than half of these new-build projects will actually begin turning dirt as planned over the next five years.
Broken out by fuel, new-build generation plans over the next five years include: • 96 GW of renewable energy
• 64 GW of gas-fired projects
• 2.6 GW of coal-fired power
• 1.8 GW of nuclear power
As can be seen above, a significant portion of new electric generating capacity is being developed to replace units that have been, or will be, retired due to tighter environmental regulations.
As in prior years, renewable energy and gas-fired generation are projected to account for the lion’s share of U.S. new-build power project activity. On a national basis over the 2015-to-2019 period, renewable energy projects amounting to 58% of all new-build generation on a GW basis are scheduled to begin construction. Gas-fired plants are projected to account for 39% of power-plant construction activity during that time.
At about 165 GW, the portfolio of power projects scheduled to begin construction over the next five years is down noticeably from earlier years (Figure 2). Meanwhile, U.S. electric demand growth is projected at less than 1% for the next few years.
The industry received good news earlier this year when the EPA finalized its new rule for cooling water intake systems under Section 316(b) of the Clean Water Act. That regulation applies to all thermal generators: coal, gas, oil and nuclear. The rule, finalized in May, has more flexibility than expected. Rather than a “command and control” edict to build cooling towers for all thermal plants, the EPA gave operators several options to reduce the impact their operations would have on fish and aquatic life.
As a result, power plant owners are expected to spend the next two-to-three years conducting studies on various ways to protect aquatic life at their power plants then submit their proposals to the EPA for review. Realistically, we are several years away from the start of any Section 316(b) construction activities at thermal power plants.
New-build coal-fired generation has had a dim outlook for several years, and that did not improve in 2014. An arduous permitting process, high capital costs, flat demand growth for electricity and impending regulation of CO2 emissions have combined to offset coal’s traditional advantages as a plentiful domestic resource with a history of price stability.
Ten years ago, coal was scheduled to account for about 24% of all new-build power plants. But by 2010, that number had fallen to 7%. Now, as we look out over the 2015-to-2019 period, new-build coal is projected to account for slightly less than 2% of all new generation, about 2.6 GW.
Coal power has been under intense fire for the last few years. But economic forces also have contributed to the current plight. The shale revolution has dramatically expanded the nation’s supply of natural gas, which has helped to keep gas prices relatively low.
For the next few years, analysts and investors expect gas production will outstrip demand, keeping gas at the wellhead priced at between $4 and $5 per thousand cubic feet (Mcf), according to futures prices on the New York Mercantile Exchange. The EPA’s NSPS for future coal-fired generation did nothing to brighten the outlook for new-build coal generation. The draft rule, published in the Federal Register this past January, after being announced in September 2013, drew more than 2 million comments.
The EPA expects to finalize that rule in 2015. As drafted, the NSPS rule for new generation would limit new coal generation to an emission rate of no more than 1,100 pounds of CO2 per megawatt-hour (MWh) of electricity produced — effectively the emissions rate of new high-efficiency, gasfired, combined cycle units.
An emissions cap of 1,100 pounds per MWh is about half the emission rate of most coal-fired generators, meaning any new coal plants would need either carbon capture & sequestration (CCS) technology or integrated gasification combined cycle (IGCC) technology. Neither option appears particularly attractive at present.
One of the few coal-power projects still under construction is the 582-MW Kemper County IGCC plant, expected to begin operating in early 2015. That project reportedly is running well over its original price tag of $2.8 billion, and owner Southern Company has absorbed at least $1.5 billion of these cost overruns.
Duke Energy’s 618-MW Edwardsport IGCC project began commercial operation in mid-2013, but its performance since then has been disappointing. The $3.5 billion project had a relatively high capacity factor in its first months of operation, but capacity factors fell to the single digits during early 2014 as the polar vortex froze some equipment.
Edwardsport’s original costs were estimated at about $1.9 billion. Cost overruns caused Indiana regulators to cap at $2.6 billion, the amount Duke could recover from customers in rates. Duke ate about $900 million of cost overruns there.
Across North America, dozens of IGCC projects worth nearly $100 billion have been cancelled or placed on hold in recent years, victims of huge capital costs, permitting problems, technology challenges, abundant supplies of natural gas, and low gas prices. IGCC is called the “bleeding edge” for a reason. The industry’s experience at Edwardsport and Kemper County will do nothing to encourage new forays into that technology.
By year-end 2014, construction was scheduled to begin on the $1.65 billion FutureGen 2.0 power plant in Meredosia, Illinois. FutureGen 2.0 is a first-of-its-kind, near-zero emissions, coal-fueled power plant. Project owners plan to install pre-combustion oxycombustion technology on a shuttered power plant in Meredosia, Illinois.
That technology will eliminate most of the CO2 emissions before the generator burns coal, but the project also will install technology to capture and sequester an estimated 97% of the CO2 emissions that are produced in the combustion process. The captured carbon dioxide would then be transported and stored underground at a nearby storage site. The U.S. Department of Energy is funding about $1 billion of the $1.65 billion project. If all goes well, the plant should be operating by year-end 2017.
A handful of coal generators are in the planning or engineering phases. Under certain conditions, some or all of these projects could be grandfathered under the EPA’s draft NSPS providing construction starts within 12 months after the rule is finalized. The rule is expected to be finalized in 2015, but we doubt if more than a small handful of those proposed projects will begin construction in the 12 months after that rule becomes final. This past summer, Sunflower Power Cooperative also received a permit to add an 895-MW unit to its Holcomb Power Station, located near Holcomb, Kansas.
Meanwhile, the drumbeat of coal-plant closures and repowerings continues. Plants that are smaller (less than 450 MW) and older (more than 50 years old) are most frequently mentioned as targets for closure. Plant closings and repowerings were announced throughout 2014, and we expect the pace of closures and repowerings to speed up in 2015, as the effective date of MATS compliance nears.
Figure 3 contains a summary of U.S. coal plant retirements, by year of shutdown, tracked by Industrial Info. Data for 2010 to 2014 reflects actual plant closures, while data for 2015 to 2017 shows the date of planned closures.
Like many utilities, the Tennessee Valley Authority (TVA) has been wrestling with the future of its coal fleet. Prior to 2014, the agency spent heavily to install pollution control equipment at some coal-fired units. But the TVA also has been closing coal-fired units and building new gas-fired generation to replace that shuttered capacity.
For its Allen Fossil Plant near Memphis, the agency had to choose between spending $450 million to $650 million to install scrubbers on the 741-MW, 55-year-old plant, or shutter the plant and build a new natural-gas combined-cycle (NGCC) plant in its place. In late August, TVA decided to close the Allen plant and spend up to $975 million to build a 1,000-MW NGCC.
The prospect of CO2 emissions regulation is forcing the hands of coal-oriented utilities across the country. As it stands today, there is no costeffective, commercially proven CO2 reduction technology for coal-fired power plants.
However, in late August, NRG Energy kicked off construction of its Petra Nova Carbon Capture project, designed to capture about 90% of the carbon dioxide from a 240- MW slipstream of flue gas from Unit 8 of the W.A. Parish Power Station near Houston. This post-combustion, commercial-scale project is expected to be operational in 2016. The power and coal industries will closely monitor progress of the Petra Nova project, as it did an earlier CCS project at AEP’s Mountaineer Power Station.
Several billion dollars of pollution control projects began construction in 2014 at coal-fired power plants across the U.S. We expect that spending trend will grow over the next few years, driven largely by MATS compliance projects.
Depending on the technology deployed, MATS compliance could cost $40 million or less for an activated carbon injection (ACI) system, but there are more elaborate mercury- control technologies that are several times more expensive.
Going forward, another driver for pollution- control spending will be installation of equipment to reduce sulfur dioxide (SO2) and oxides of nitrogen (NOx). Over the next five years, we expect construction to begin on about $10 billion of power plant pollution- control projects.
Despite the dearth of new-build coalfired generation, we do see a healthy level of spending for the coal segment over the next five years. Spending on in-plant capital and maintenance projects is expected to trend upward as asset owners invest in efficiency upgrades, modernizations and scheduled maintenance to ensure those assets continue to operate in a safe, efficient and competitive manner. Though its share of the electricity mix is projected to continue trending downward, most analysts still expect King Coal to generate between 33% and 40% of the nation’s electricity for the coming years.
Coal’s pain has been natural gas’ gain. In 2013, construction began on about $8.8 billion of gas-fired generation. Across the U.S., the gas-power project pipeline is full, with about 89 GW of gas-fired power projects under development. Power plant developers plan to kick off construction on about 64 GW of new gas-fired generation between 2015 and 2019, representing nearly $60 billion in total investment value.
On a GW basis, the Northeast, Southwest, Great Lakes and West Coast regions are expected to build the most gas-fired generation over the next five years. The states with the most gas power projects under development include Texas, Pennsylvania, California, New York and Florida.
As with all fuels, we do not expect all scheduled gas power projects to start turning dirt according to their respective timetables. But historically, gas plants have had a higher percentage of on-time starts and completions when compared with other fuels. Roughly 50% of new-build gas plants are started and completed according to schedule. That is another reason why we see natural gas winning nearly 40% of the new-build market over the next five years.
As a case in point, power plant developers plan to begin construction of 64 gas-fired power projects totaling 14.4 GW and valued at about $15 billion in 2014. We estimate construction willl begin on between 6 and 7 GW of gas-fired power plant projects in 2014, valued at about $10 billion. We see a similar level of construction starts in 2015 and 2016. So on a GW basis, we expect around half of scheduled new-build projects to begin construction as planned.
Billion dollar projects Several billion-dollar natural gas generating stations are scheduled to kick off construction in 2015 and 2016, including:
• St. Joseph Energy Center, a $1.6 billion project in Indiana
• Cricket Valley Energy Station, a $1.4 billion project scheduled to be built in New York
• Pondera King Energy Center, a $1.4 billion project slated for Texas
• Mattawoman Generating Station, a $1.2 billion project scheduled to be built in Maryland
• Lebanon Valley Power Station, a $1.1 billion project slated for Pennsylvania
• Westmoreland County Generating Station, another $1.1 project in Pennsylvania
• Lauderdale Combined-Cycle Station, a $1 billion project scheduled to be built in Florida
• Bowline Point Generating Station, a $1 billion project slated for New York
• Jessup Energy Center, a $1 billion project Pennsylvania
Several factors are driving industry’s dash to gas. Compared to other forms of generation, gas plants are relatively easier and faster to permit, site and build than other forms of generation, and they can ramp up and down quickly to match shifts in load. Gas plants also take up a smaller footprint than traditional coal or nuclear plants, and are much less expensive to build than either coal or nuclear generators.
Additionally, low-priced natural gas makes repowering coal units with gas an attractive option for some utilities. One final element bears mention: gas-fired generation is the backup generation of choice for intermittent resources, such as wind and solar, which have grown rapidly in recent years.
Tightening reserve margins in Texas, Florida and the Northeastern U.S. are yet another factor accelerating the dash to gas. Industrial revitalization in certain regions, notably the Gulf Coast, is also driving the gas-power construction trend. And many NGCCs are being built to replace coal-fired capacity that is being shuttered.
Gas also has become more price-competitive with coal in recent years thanks to the shale revolution. Horizontal drilling and hydraulic fracturing have dramatically boosted reserves and production in recent years, keeping gas prices low.
Continued expansion of the gas resource base is widely expected for the next several years. The planned export of gas in the form of LNG is expected to push gas prices upward over the next five years, but how far and how fast depends on the number of LNG export terminals constructed.
Expanding gas production and reserves should ease executives’ concerns about gas prices, which historically have been volatile (Figure 4)). For a brief period in mid-2008, electricity generators paid about $12 per Mcf of gas, according to the U.S. Energy Information Administration. But the cost of gas for electric generation has fallen more than 50% since then, boosting gas’ attractiveness as a fuel for electric generation.
Utility executives, developers and regulators all express support for the idea of fuel diversity in a generating fleet. But in their decisions, regulators are giving greater weight to consumers’ electric costs than generator fuel diversity. That is one reason why a growing number of utilities, including Kansas City Power & Light, Louisville Gas & Electric and Kentucky Utilities are sharply increasing their conservation and efficiency programs — even as they build new gas generation.
While each case is different, some utilities — prodded by regulators — are finding the cheapest kilowatt-hour of electricity is the kilowatt-hour they do not generate. The expansion of conservation and efficiency programs has lowered electric demand growth, cutting into power plant construction across all fuels. The EPA’s Clean Power Plan is widely expected to further accelerate the nation’s reliance on gas for its electric generation, as gas is the only fossil fuel that would comply with the proposed CO2 emissions standard.
The industry’s prospects could always be upended by a low-probability but highimpact “black swan” event, such as the Fukushima Dai’ichi accident in 2011, which instantly transformed the global prospects of nuclear power. For developers of gas-fired power plants, a black swan event could be a federal finding that hydraulic fracturing poses significant environmental risks to groundwater, triggering new federal regulation of hydraulic fracturing.
Such a finding could chill drilling plans, raise gas prices and reduce new-build gasfired power plants. Overnight, gas’ virtuous cycle could become a vicious downward spiral. But aside from a strategic bombshell like that, it is difficult to see how the dash to gas in power plant development will slow down any time soon.
Construction of renewable energy projects has boomed in recent years. In 2013, construction began on about $17 billion of new wind projects and $8 billion of new solar projects. For 2014, wind developers have scheduled $19 billion of projects to begin construction.
We expect about $16 billion of projects will actually kick off as planned. And solar developers propose to begin construction on about $10 billion of new-build generation in 2014, nearly all of which we expect will kick off as scheduled.
Between 2015 and 2019, renewable developers plan to begin construction on about 96 GW of renewable generation. The regions with the greatest amount of renew- able construction planned are the West Coast, Rocky Mountains, Southwest, Midwest and Great Lakes.
Developers and construction firms were busy in 2014, and will remain busy in 2015, building wind projects to qualify for federal Production Tax Credits (PTCs). Those credits expired at the end of 2013, but wind projects that began construction by that date are eligible for PTCs.
We expect that about 67% of renewable generation additions over the next five years will be wind power. Falling equipment costs and rising efficiencies have combined to reduce the cost to generate electricity from wind to between $25 and $38 per megawatt-hour.
Thousands of wind turbines have been built in the U.S. in the last five years. That means, over the next five years, utilities and wind power asset owners will be spending billions of dollars in the after-market for equipment maintenance, replacement and repair, as OEM warrantees expire and mandated maintenance milestones are hit.
On the solar side, the existence of federal Investment Tax Credits (ITCs) through the end of 2016 will boost construction activity in this sector. Solar projects that begin operating by the end of 2016 are eligible for ITCs equal to 30% of the cost of construction. After that, the ITCs fall to 10% of a project’s value. Barring an extension of the ITCs or technological breakthroughs, we expect solar construction will decline sharply after 2016.
Aside from federal tax policy, the pace of renewable development depends on two factors: state renewable portfolio standards (RPS) and the ability to site transmission lines.
Industrial Info is tracking a total of 134 GW of renewable energy that is under development in the U.S. The states with the most renewable energy being developed include:
• California (23.3 GW under development)
• Texas (17.2 GW under development)
• Arizona (6.8 GW under development)
• Nevada (6.4 GW under development)
• Oregon (6 GW under development)
In 2014 and looking forward, developers planned to begin construction on 335 renewable energy projects totaling 39 GW and valued at $94 billion. Industrial Info projects much fewer projects will actually kick off as planned. For the period 2014 and 2016, we see between 10 GW and 16 GW of renewable energy projects actually beginning construction.
Construction of renewable energy could be chilled in the coming years if other states follow Ohio’s example and modify or repeal policies supporting renewable energy. In mid-2014, Ohio froze the state’s renewableenergy and energy-efficiency standards for two years, arguing they unduly drove up electric costs.
Five years ago, nuclear power was poised to account for 13% of all new U.S. power construction. But as cost estimates to build new reactors increased, projects were shelved indefinitely or abandoned altogether. That trend was evident before the March 2011 Fukushima Dai’ichi disaster.
Cost escalation and Fukushima combined to cull the ranks of new-build prospects for nuclear power. Low gas prices, new safety regulations from the Nuclear Regulatory Commission and the still-unresolved issue of a permanent nuclear waste site pose further challenges to new-build nuclear power. Between 2015 and 2019, we project construction will begin on about 1.8 GW of nuclear generation, about 1% of the new-build market.
Extended power uprates (EPUs) continued to slow in 2014, and their outlook appears weak going into the 2015-2019 period. Rising cost estimates and slow demand growth have undermined the economics of many uprate projects. Regulators’ preference for low-cost, incremental resources such as conservation and energy efficiency, create additional headwinds for nuclear power.
While the EPA’s draft rules on CO2 emissions limits for new and existing generators could be seen as a lifeline for the industry, the agency drafted those rules with an emphasis on cost-effective measures. Hence, those hoping for a regulatory mandate for nuclear power likely were disappointed: nuclear does not meet the costeffectiveness test.
The costs to repair damaged units at Crystal River in Florida and San Onofre in California caused operators to close both plants in 2013. No operating generators have been closed so far in 2014, but the 2013 closure of Kewaunee in Wisconsin and Vermont Yankee in Vermont illustrated the difficult economic environment in which nuclear power exists. Low gas prices and an absence of payments for capacity (as opposed to energy) make nuclear’s prospects that much more difficult.
Four new-build nuclear unit additions are under construction. Units 3 and 4 at the Vogtle Generating Station in Georgia have experienced delays and cost overruns. Those projects are scheduled to begin operating in 2017 and 2018. Units 2 and 3 at the Summer Power Station in South Carolina also have experienced cost overruns. Unit 2 is scheduled to be substantially complete in late 2017, and Unit 3 is expected to be substantially complete a year later. All four units will use Westinghouse’s AP1000 advanced passive reactor design.
Aside from those four units, newbuild projects are scheduled to kick off in Pennsylvania in 2018 and Missouri in 2019. Projects proposed for Virginia and New Jersey have been pushed back into the 2020s.
In 2013, Duke Energy cancelled plans to build the Levy County plant in Florida. That same year, Duke pushed back the start of construction activities at the Shearon Harris unit additions in North Carolina and the grassroot William States Lee III Nuclear Power Station in South Carolina.
Dramatic price increases in the price and availability of natural gas could be the kind of black swan event that might revive nuclear’s prospects. Absent that, the nuclear industry’s futures may lie more in building small modular reactors (SMRs) for export rather than constructing large, central-station projects in the U.S.
The U.S. power business continues to be highly dynamic, particularly in light of the EPA’s decision to regulate CO2 emissions from power plants. That rule, if it survives court challenges, is expected to act as another accelerant to the retirement of older, smaller, coal-fired power plants. Utilities and their consultants have spent months assessing exactly how that rule could reshape the fuel mix for electric generation. Doubtless more analysis and many late nights lie ahead.
Britt Burt is vice president of Global Power Industry Research for Industrial Info Resources (IIR), headquartered in Sugar Land, Texas, with three offices in North America and 10 international offices. S
hane Mullins is vice president of Power Industry Product Development for IIR, which provides global market intelligence for companies in the power, heavy manufacturing, and industrial process businesses.
Brock Ramey is IIR’s manager of North American Power Industry Research. IIR’s databases, forecasts, and analytics are used by EPC firms, power developers, utilities, financial services firms, equipment manufacturers and professional services firms. For more information: www.industrialinfo.com or firstname.lastname@example.org