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TURNOVER OF GENERATION FLEET SPEEDS UP. NATURAL GAS PROJECTS DOMINATE PLANS FOR THE NEXT FIVE EARS
Environmental regulations and low-cost natural gas accelerated the turnover of the U.S. generation fleet in 2012, and the pace may speed up even more in 2013 depending on the outcome of the November elections. But the last few years of no growth or slow growth in electricity demand has spared asset owners the need to replace retiring units on a megawatt-formegawatt basis. Instead, anemic or negative growth in electricity demand has allowed owners of electricity generators to defer or stretch out some of their capital budgets.
Financing costs are low today, as are natural gas prices, and both figure heavily in the multibillion-dollar question facing coal-fired generation: Retrofit, repower or retire? The scheduled expiration of the federal incentives for renewable energy quickened construction of those generators during 2012. But unless the federal Production Tax Credit (PTC) is extended beyond 2012, project development for renewable power likely will grind to a virtual halt next year.
In the U.S., Industrial Info Resources (IIR) is tracking 951 generation projects totaling 217 GW and valued at about $565 billion that are scheduled to kick off during the 2013-2017 period.
What is particularly notable is how many of these planned projects are for renewable energy. On amegawatt-basis, renewable energy projects — chiefly wind and hydro — account for 67%of all planned power projects over the 2013-2017 period (Figure 1). This is a one percentage point increase over last year’s data and a seven percentage point gain from late 2010. In recent years, new-build renewable energy and natural gas has grabbed market share fromcoal and nuclear.
Regardless of the fuel, experience in tracking power-plant development tells us that not all new-build power projects will start according to schedule. Some will be acceleratedwhile otherswill be delayed.The industry remains highly dynamic, perhaps more so now than at any time in the last quarter century.
New regulations from the U.S. Environmental Protection Agency (EPA) and the lowprice of natural gaswere the two most powerful forces affecting current and planned U.S. coal-fired generation in 2012 and 2013. At this point, we see both forces continuing to shape coal generation over the next few years.
The EPA’s Mercury and Air Toxics Standards (MATS) rule, which was finalized earlier this year, remains in a state of flux. This summer, the agency agreed to reconsider the part of this rule affecting new plants for a period of approximately three to four months leaving the reconsideration period to end in November 2012.
The EPA is being asked by both industry and environmental groups to reconsider other parts of the draft rule as well. Because MATS affects every coal-fired (and oil-fired) generator larger than 25MW, its impact will be felt broadly and deeply across the nation’s coal fleet. Approximately 1,400 generation unit are set to possibly be affected.
MATS full compliance is required by the end of 2015, with the possibly of a year extension on a case-by-case basis; but given the EPA’s reconsideration, and the certainty of coming litigation, we think that the effective date may be pushed back. IIR estimates that 9 to 10 GWof coal-fired generation will be closed by MATS alone. Assuming the regulation survives legal challenges, complying with MATS will require installing activated carbon injection systems, selective catalytic reduction (SCR) units or baghouses on coal units, at an estimated annual cost of $300 to $400 million.
The coal and utility industries won a partial victory this past summer when the D.C. Circuit Court of Appeals vacated the EPA’s Cross-State Air Pollution Rule (CSAPR). That 2 to 1 decision, reached in August, meant that the Clean Air Interstate Rule (CAIR)would remain in effect until CSAPR was finalized. Nearly 900 coal generating units in over two dozen states would be affected by CSAPR.When fully implemented in 2015, CSAPR (or its successor) will cost the industry an estimated $800 million per year.
Other regulations expected to move forward in the coming year,with impacts on the industry’s compliance spending tab, include the NationalAmbientAir Quality Standards (NAAQS) for sulfur dioxide (SO2), oxides of nitrogen (NOx), Coal Combustion Residuals (CCR) and updating section 316(b) of the CleanWaterAct. These new regulations will be moving to either final proposal or finalization phase in 2013, with effective dates ranging from 2017 to 2020.
These looming rules concern emissions of SO2 and NOx, handling and disposal of coal ash and improving power plant water intake systems on a national level. The CCR regulation is currently being addressed by certain electrical generation utilities on a state level. Themajor driver is the Tennessee Valley Authority (TVA) Kingston Plant ash pond breach in 2008. In their proposed form, these regulations could affect another 9 to 10 GWof generation over the next decade.
Whatever their final disposition, pending EPA regulations drove the premature retirement of thousands ofMWof coal-fired generation this year, and we expect that trend to continue in 2013 and beyond. Throughout 2012, utilities announced the retirement of their older, smaller, less-efficient coal-fired generators, typically sized at 150 to 250MW. Progress Energy, American Electric Power, FirstEnergy, Southern Company, South Carolina Electric & Gas, TVA and Alliant announced early retirements this year.
We expect new air pollution rules, along with other factors, to force the retirement of 30 to 50 GWof coal-fired power plants over the next five years. Most of these units are between 50 and 60 years old and are located in “merchant” power markets, where the sharp decline in natural gas prices has led to widespread coal-to-gas switching. For many plants, the new EPA rules have moved the inevitable retirement timeline forward.
It is not going to be economically feasible to install environmental controls on all of the boilers subject to these rulings. Some 600 smaller coal-fired units, which total 60 GW, are particularly at risk; and they have yet to address anything beyond NOx emissions. These units typically are 300 MW or less. Currently 225 units totaling 34GWhave formally announced plans to retire by late 2016.
The retirements we expect to see will take place beyond coal units as the regulations also affect Rankine cycle natural gas and heavy oil boilerswhere heat rates are too high to continue operating and meet these requirements especially in the Southwest. Some boilers in that region have heat rates in the 13,000-plus BTUs per hour kilowatt range. Some of these units will be targets for combined cycle repowering.
As utilities retire older units, they also are challenged to improve the operational performance of the remaining fleet. Typically, they plan to keep other units running by upgrading, uprating, refurbishing and installing equipment to reduce emissions of SO2, NOx, mercury and particulate matter.
Billions of dollars of environmental compliance contracts were signed in 2012, and we expect that to continue in 2013. IIR is tracking about $35 billion of capital projects to refurbish, decommission and dismantle coal-fired generators between 2013 and 2017. Project activity is expected to be highest in the Rocky Mountain and Southwest regions.
While the environmental equipment industry has commercially proven technologies to reduce emissions of SO2, NOx, mercury and particulates, there is currently no commercially viable technology to capture and control CO2 emissions. Several equipment suppliers and utilities are experimenting with different types of carbon capture and sequestration (CCS) projects, but no commercial- scale solution has yet been deployed.
Various pilot projects have validated CCS technology at a small scale. But scaling up to a 250 MW commercial-sized project has yet to be done. Engineering and financing are the main challenges. A promising commercial-scale deployment at AEP’s Mountaineer Power Station inWestVirginia halted in mid-2011 after state utility regulators did not allow AEP to begin recovering the cost of the project.
The regulators said since there were no federal or state rule mandating CO2 reductions, that project had to be considered R&D — for which customers could not be charged. In walking away from the estimated $650 million CCS project, AEP turned down up to $334million in funding fromthe U.S. Department of Energy (DoE).
Until a commercially viable means exists to significantly reduce or capture CO2 emissions froma coal generator, an ominous shadowwill continue to hang over coal companies and coal-burning utilities. Earlier this year, the EPA upped the anxiety level when it issued a New Source Performance Standard (NSPS) for CO2 emissions from new coal- or gas-fired power plants.
But in adopting an emissions standard of 1,000 pounds of CO2 emissions per million British thermal units (MMBtu) of heat input, the EPA effectively precluded the construction of new coal-fired generators. That standard can bemet by new-build, high-efficiency natural gas generators, but not coal. Although the EPA stressed that this proposed regulation would only apply to newbuild generators, industry sources expect the agency to eventually apply some CO2 emissions standard to existing generators.
Only one coal-fired generator — Prairie State Unit 1 — has come online in 2012. Another unit, Duke’s Edwardsport integrated gasification combined cycle (IGCC) plant in Indiana, is scheduled to come online by year end, but construction of that plantwas bedeviled by cost overruns and political controversies. Southern’s IGCC plant in Kemper County is about 40% complete and due to come online in 2014.High cost and regulatory uncertainty has convinced other utilities to stay away from that type of generation.
For all coal’s setbacks, we do not see coal as a dead or dying fuel. Despite its loss of some electric market share to natural gas this year, nearly 50% of U.S. electricity is generated fromcoal. The U.S. has abundant, low-cost supplies of the fuel. It is unfathomable (legally, legislatively, operationally, and financially) that the nation would completely turn its back on coal. Rather than going through an end-of-life transition, we see coal-fired generators going through a metamorphosis to a future shaped by advanced technology.
For example, the nation’s first ultrasupercritical (USC) coal-fired generator being built at the John W. Turk, Jr. plant in southwest Arkansas offers one possible path forward. Scheduled to come online by year end 2012, itwill have an efficiency of 39%to 40%, compared to 35%for a subcritical boiler. The generator will burn about 13% less coal and produce 13%less CO2, compared to a subcritical coal unit of the same size.
IIR is tracking about 7 GWof new-build coal-fired power projects, valued at about $32 billion, which are scheduled to break ground by 2017. The fate of these plantswill increasingly depend on the regulatory environment and the price of natural gas.
Natural gas briefly fell below $2 per MMBtu in early 2012, but then slowly climbed back to hover around $3 as operators, led by Chesapeake Energy, reduced production of dry gas. Even at $3 per MMBtu, natural gas was a bargain compared to its average price of $4 in 2011 and nearly $9 per MMBtu in 2008.
Dramatic gains in gas production from shale formations have significantly improved the competitiveness of gas as a fuel for power generation. Ten years ago, gas production from shale formations was virtually non-existent. Today, roughly onethird of all gas produced in the U.S. comes from shale formations. In the not too distant future, shale gas production could account for 50%.
We are tracking about 45 GWof natural gas-fired generation projects scheduled to kick off between 2013 and 2017. The total investment value of these gas-fired generation projects is $62 billion. On a MWbasis, plants fired by gas account for about 21%of the generation capacity scheduled to start construction over that five-year period.
Inexpensive gas not only influences future generation choices, it also boosts the economics of existing gas-fired generation. Jim Rogers, chief executive of Duke Energy, has spoken about howlowgas prices have shifted the dispatch order of the utility’s generators. He notes the challenge ofmanaging the growing piles of unused coal at some plants.
Across the U.S., generators burned a lot more gas during 2012 than in prior years. Gas market share gains were evident earlier this year when DoE data showed gas and coal generated almost exactly the same amount of electricity for the month ofApril; this was the first time this happened since Gerald Ford was president. As the U.S. endured another broiling summer,KingCoal recaptured some market share from gas. But it seemed clear to gas advocates that gas was winning the long-term war for market share.
Beyond its current cost advantages over coal, and EPA regulations hindering coal, several other factors sustain the “dash to gas,” including:
• The dramatic expansion of intermittent generation (likewind and solar power) drove up need for low-cost backup generation to ensure reliability and dispatch-ability
•Thewinding down of federal incentives for renewable energy were causing utilities and independent power developers to build other types of generation
• The costs and risks of new-build nuclear power were too high
• The shorter construction timeframe, and ability to site gas-fired generators on a small footprint.
Many utilities and merchant generators decided to repower coal-fired units with natural gas during 2012.We see no reason why that trend would not continue in 2013 and beyond.
Utilities and merchant generators have become reliant on natural gas as the “go to” fuel for newgeneration that some executives, including Duke’s Rogers and AEP’s Nick Akins, have warned about the dangers of building “all gas, all the time.”
Rogers said at one industry event, “. . . what strengthens the U.S. electric grid is having a diverse portfolio of generation. Today’s low gas prices make it uneconomic to burn coal. The toughest challenge we face today is to convince regulators and consumers to let us build something other than natural gas generation.”
Perhaps the only potential flies in the ointment are state and federal regulators who are under increasing pressure to rule on the environmental impacts of extracting gas from shale formations using hydraulic fracturing. The EPA and New York State have taken leading roles in trying to assess and quantify the costs and risks of this extraction process.
Some oil&gas firms paid hefty fines to settle allegations they violated environmental regulations. To a firm, these companies insist hydraulic fracturing is safe. The problem, they say, is subcontractors that take short cuts.
Moves to increase regulation of hydraulic fracturing, or limit its use, could be the win coal companies seek. Such moves could dramatically alter the price and production of natural gas from shale, fundamentally altering power economics.
New-build nuclear power got its first jolt of business earlier this year, when the U.S. Nuclear Regulatory Commission granted combined construction and operation licenses (COLs) to units of the Southern Company and SCANA. Currently, construction is underway to add two nuclear units to the Alvin W. Vogtle Nuclear Power Station in Waynesboro, Georgia. Two more units also are being built at the existing Virgil.C. Summer Nuclear Power Station in Jenkinsville, South Carolina.
Both utilities are using theWestinghouse AP1000 reactor. The four units are scheduled to begin operating between 2016 and 2019. Summer units 2 and 3 andVogtle units 3 and 4 will add about 4,434 MW at a cost of about $29 billion. That works out to an installed capacity cost of about $6.5 million per MW, nearly six times the cost of a new natural gas combined-cycle unit.
But the nuclear industry’s success has been tempered by cost overruns and missed milestones at the Vogtle site. Since the Summer site is using the same reactor design, those issues may arise there too.
Concerns over capital costs, cost overruns, long construction time, and adherence to a construction schedule have dogged the much-discussed “nuclear renaissance” of new-build nuclear for years. These factors have caused many utilities to shy away from building new nuclear generators. Last year, NRG Energy abandoned plans to build two new nuclear units at its South Texas Project Nuclear Generating Station. More recently, Exelon cancelled plans to build a two-unit nuclear plant inVictoria, Texas.
Another proposed nuclear unit, EDF’s Calvert Cliffs Unit 3, was denied a COL this past August by an NRC board, because it is 100% owned by a non-U.S. energy company, prohibited by federal law. If EDF cannot find a U.S. partner, Calvert Cliffs Unit 3 will join South Texas units 3 and 4 and Victoria units 1 and 2 on the growing pile of scrapped plans to build nuclear power plants that operate asmerchant generators,without the guaranteed revenue stream afforded by a utility’s customers. The Vogtle and Summer new units, by contrast, will operate in traditionally regulated utility markets, where the utilities have a captive base of customers.
A few years ago, TVA decided to finish construction on partially built nuclear plants, but cost overruns and construction delays reared their ugly heads. TVA said it had underestimated the cost to complete Watts Bar 2 by between $1.5 billion and $2 billion. Also, it acknowledged it had been overly optimistic about the amount of time it would take to complete construction. Now, TVA expectsWattsBar 2 to be completed by yearend 2015. It alsowants to finish construction of its BellefonteUnit 1 plant inAlabama, but construction there will not resume until Watts Bar Unit 2 is finished.
A side from theVogtle and Summer projects, IIR does not see any new-build reactor projects breaking ground until at least 2015. One of the first new-build plants that could start construction is Progress Energy’s Levy County Nuclear Power Station, but that is not expected to happen until 2015 at the earliest. Right now the utility estimates it will take $17 billion to $22 billion to build that two-unit, 2,200-MWplant.
Earlier this year, the NRC was forced to stop work on new COLs while it considered the issue of spent fuel storage. A court instructed the NRC to look more thoroughly at the potential for water leaks or fires at onsite spent fuel storage facilities. The applications most directly affected are the Levy County Nuclear Station and the William S. Lee III Nuclear Power Station — both owned by Duke Energy following itsmerger with Progress Energy.
While new-build nuclear generation remains a “bet the company” proposition, power uprates of existing nuclear generators continue to be popular. More than a dozen such projects have been completed in recent years, and another half-dozen are underway or planned.
We also see heavier spending over the 2013 to 2014 timeframe as nuclear operators work to comply with the NRC’s Tier 1 and Tier 2 safety and operational recommendations, which were proposed following the 2011 meltdown of Japan’s Fukushima nuclear station. Farther off is the NRC’s Tier 3 inspection program, which will investigate longer-term issues.
Southern California’s two-unit San Onofre Nuclear Generating Station (SONGS) has been offline for nearly all of 2012, while owner Southern California Edison (SCE) and reactor manufacturer Mitsubishi Heavy Industries try to pinpoint and remedy weakened steam generator tubes.Unit 3 is understood to bemore extensively damaged thanUnit 2. SCE announced plans to reduce SONGS staff by about onethird during the fourth quarter of 2012. “The reality is that the Unit 3 reactor will not be operating for some time," said SCE.
The past year was a busy one for renewable power development, but the 2013 to 2017 period is clouded with uncertainty. A record number of renewable energy projects began construction in 2011, and 2012 was a busy year aswell, as an estimated $65 billion in tax credits, grants and loans helped drive development and construction of a variety of renewable generation technologies. But that money has all been committed.During 2012, developers and engineering & construction firms hustled to finish projects and meet deadlines for federal incentives that remain.
Federal budget deficit concerns caused theDoE construction loan guaranty program to expire at the end of September 2011. The Treasury Department’s successful Section 1603 cash-grant program expired at the end of 2011 and was not renewed. However, IIR tracked a spike in equipment sales under that program’s “safe-harbor” clause, which allowed developers to qualify for the grant if they incurred 5% of a project’s costs by December 2011. Developers were given until September 30, 2012, to specify an exact location for projects thatwill use the alreadypurchased equipment.
The safe-harbor provision has helped the industry to continue developing projects this year, which likely means that 2012 will go down as a survivable correction year. But there are doubts about construction starts for wind power, solar, biomass, geothermal, hydro and other forms of renewable energy over the 2013 to 2017 period.
We say this in full recognition that, on a MW basis, renewable energy accounts for 67% of all power generation projects scheduled to kick off over the next five years.Only about half of all projects actually start and finish construction according to their announced schedules. But this blended average hides sharp differences between the different fuels. Only 10% to 20% of renewable energy projects announced are ever built. By contrast, six out of ten gas-fired power plants announced are built.
As well as expiring incentives, renewable power development may slow in the coming years as statesmake progress toward attaining the renewable portfolio standards (RPS) they have established. California, Colorado, Texas and New York have established the most aggressive mandates on how much electricity must be generated by renewable resources over the 2015 to 2020 timeframe. But as utilities make progress toward their goals, they have less need for signing additional power-purchase contracts with renewable developers.
At this point, IIR is tracking 145 GWof new renewable generation projects valued at $324 billion that are scheduled to kick off between 2013 and 2017. Wind power accounts for the 87 GWof planned projects valued at $188 billion.
Hydropower projects are the next-largest sectorwith 164 projects totaling 38GWslated to begin construction over 2013-2017. These are valued at about $64 billion. All other renewable energy projects scheduled to kick off over the next five years total about 20GW, with a collective value of about $71 billion.
The nation’s largest banks embraced loans and equity investments in a variety of “clean technology” industries this year. The banks committed to financially supporting renewable energy projects and a range of other “sustainable” investments:
• Bank of America pledged to lend or invest $50 billion over the next 10 years
• Goldman Sachs established a goal of investing or loaning $40 billion
•Wells Fargo committed to $30 billion in loans and investments by 2020.
These investments are badly needed. The tax equity market, a necessary element in financing renewable energy, is only about $3 billion. Additional funding sources include engineering, procurement & construction (EPC) firms, original equipmentmanufacturers (OEMs), sale-leaseback deals, and power purchase agreements (PPAs) where some funds are advanced against future production.
Despite this year’s surge of renewable project development, there was widespread dismay in the wind community about the pipeline for projects in 2013 and beyond. Congress’ inability or unwillingness to extend the PTC beyond its December 31, 2012, deadline cast a heavy pall. Developers and equipment manufacturers have reduced staff and trimmed plans.
The PTC provides a 10-year, 2.2-centper- kilowatt-hour incentive for wind as long as the unit is operating by the end of 2012. Loss of the PTC would reduce the financial viability of many projects. Since 1999, each time the PTC has expired, wind installations plummeted between 73% and 94%.
Hydropower continues to be the “Old Faithful” of renewable generation, predictably churning out millions of megawatthours day and night. Because hydro generators (particularly those with pumped storage facilities) are able to generate electricity when other renewable sources like wind and solar cannot, hydro is an especially valuable renewable resource.
Currently, there are over 700 hydro plants operating in the U.S. with total capacity exceeding 104 GW. Far from a “tapped out” resource, however, there are an additional 60 GW of hydro generating capacity that could still be developed by 2025. Included in that 60 GWestimate is about 12 GWof small hydro resources.
IIR is tracking over $2 billion of hydro project spending scheduled to begin in 2013. We expect the West Coast and Great Lakes areas will be the most active regions. This spending estimate includes grassroots projects of 40 MW and less, unit additions, maintenance and in plant upgrades.
We also see hydromaintenance spending rising next year. The Bonneville Power Administration (BPA), U.S. Army Corps of Engineers and the Bureau of Reclamation is seeking over $238 million from Congress over the next few years to keep hydro generators managed by those agencies in top working order. This past summer, the House of Representatives unanimously passed the Hydropower Regulatory Efficiency Act (H.R. 5892), which directed the Federal Energy Regulation Commission (FERC) to speed up the permitting process for smaller hydro facilities.
We expect to see biomass generation grow over the next few years: IIR is tracking about $5 billion in biomass project spending scheduled for 2013. These projects include utility-scale grassroots projects, unit conversions, and industrial applications, such as pulp & paper mills and food & beverage plants. Most of this project activity should take place in the Mid- Atlantic and Great Lakes regions.
Not all projects, however, will move ahead according to their schedules.Financing, permitting, purchase-power agreements and feedstock availability and price are the main risks that could affect development of utilityscale biomass generation.
Some biomass projects are still in early stages of development, and lack permits or financing.With an installed capacity cost of around $5 million per megawatt, biomass is far more expensive to build than natural gas generation. Biomass plants also have higher operations & maintenance (O&M) costs compared to gas generators.And with gas at a relatively low cost today, it is possible that some biomass plants will miss their 2013 scheduled start of construction, opting to start construction in 2014 or beyond.
Brock Ramey is vice president of North American Power Industry Research for Industrial Info Resources (IIR).
Shane Mullins is vice president of Powerindustry product development for IIR, a provider of global market intelligence for companies in the power, heavy manufacturing, and industrial process businesses. IIR’s 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. For more information see www.industrialinfo.com or email firstname.lastname@example.org.