An analysis of the timing, location, and mix of new capacity additions that may be needed in the future.
It is universally accepted that there is excess generating capacity in most, if not all, regions in the country. Looking forward, several obvious, and interesting, questions arise: (1) When will new capacity be needed? (2) Where will it be needed? and (3) What types of plants will be needed? As any good economist would say, it all depends. We have attempted to address these questions under a range of assumptions regarding future environmental regulations, natural gas prices, and the cost of a new generation of nuclear plants. Depending on how events unfold, the timing, location and mix of new capacity additions could be quite different. To address these questions, we start from our most recent, end of 2003, assessment of announced plans for new generating plants and modifications to existing facilities. We assume that plants reported to be under construction will enter service as scheduled. We have incorporated these plans into our company's proprietary Electric Power Market Model of the United States and Canadian electric grids that consists of 33 interconnected power markets. We projected when, where, and what types of new capacity would be needed in the U.S. and Canada in addition to those units under construction. The analysis also was based on projections of demand growth from the North American Electric Reliability Council (NERC) and future fuel prices, as well as the costs and characteristics of new generating options from the U.S. Department of Energy's Energy Information Administration (EIA), and its .
Not More Than a Gigawatt in the Beginning
So, what does this portend for the future? Simply stated: very slow growth over the next three to five years for new capacity over and above units currently under construction. Our analysis shows, for what we refer to as the Reference Case, that by 2006, less than a gigawatt of additional new capacity would be needed over and above the 81.8 GW under construction and currently expected to be in service by 2006. This additional capacity would be located in three regions: Florida Reliability Coordinating Council (FRCC), Mid-American Interconnected Network (MAIN), and Western Electricity Coordinating Council (WECC) and would consist of a mix of single-cycle combustion turbines and renewable resources. The additions by type, period, and by NERC region are summarized in Tables 1A and 1B, respectively.
After 2006, the need for new capacity picks up, but not significantly until after 2009. From 2007 through 2008, an additional 3.7 GW of new capacity would be needed, and another 10.6 GW by 2009. These needs for additional new capacity are located in all but three of the NERC regions: East Central Area Reliability Coordination Agreement (ECAR), Mid-Continent Area Power Pool (MAPP) and SPP (Southwest Power Pool).
Ater 2009, however, the need for new capacity accelerates-an additional 23.6 GWs will be needed in 2010, another 47.3 GWs by 2013, followed by another 82.6 GWs by 2018. Again, these are the requirements over and above those units currently under construction. These additions are likely to include most of those plants currently under development but not under construction.
So it is not until 2010 and later that we should expect to see significant needs for new capacity beyond what is currently under construction. We can see from Tables 1A and 1B that by 2008 or 2009 most of the capacity recently constructed will have been absorbed by demand growth and that significant amounts of new capacity will be required thereafter.
By 2013, we see a need for additional capacity in all but the MAPP region, but after 2013 additional new capacity will be needed in that region as well.
By 2018, nearly two-thirds of the additions summarized in Table 1A would be combined-cycle plants. Additions of coal-fired plants and combustion turbines would be about the same, but significantly less than the requirements for combined-cycle capacity. The remaining capacity would be a small amount of renewable resources.
Several caveats are in order. We divide the United States and Canada into 33 separate markets connected by a transmission grid. Given modeled transmission constraints, inter-market energy and capacity transactions can be made on economic grounds. Within each of these regions, we assume there are no transmission constraints like those among the 33 regions. In reality, there often are local (intra-regional) transmission constraints. Thus, in some regions, there may well be the need for capacity over and above what we are projecting because of the local constraints. In the long term, the local additions would replace regional additions that otherwise would be projected by our proprietary model.
Moreover, in some cases local, regional, or state politics will play a role in determining when, where, and what type of plants will be built, and this will not be captured in our analysis. But this is only the beginning of the story.
Environmental Regulations and Supply in the Mix
Any number of factors could affect the prognosis for when, where and what types of new capacity will be needed beyond plants currently under construction. Up to this point, we have assumed there would be no changes in environmental regulations governing power plants. But Congress is considering several proposals. Also, there is debate over the long-term price of natural gas that inevitably occurs when there is a sustained increase in gas prices. Finally, the administration and others currently are pressing for a new generation of nuclear plants. In this section, we discuss how new environmental regulations, higher long-term gas prices, and a new generation of nuclear plants would affect the timing, mix, and location of additional generating capacity.
We considered two sets of proposed environmental regulations. The first is the administration's proposed Clear Skies Act (CSA), and the second is the Carper Bill (Carper), S. 843, introduced by Sen Thomas R. Carper, R-Del. The Carper proposal would impose more stringent regulations than the CSA proposal for SO2, NOX and mercury. In addition, the Carper proposal would cap carbon emissions from power plants. Table 2 summarizes the provisions in the two proposals.
Should either of these proposals become law, the major effects on the need for new capacity would be to: (1) accelerate, modestly, the need for new capacity above what would be expected under current regulations; and (2) shift the mix of additions away from coal and single-cycle combustion turbines to combined-cycle plants. The impacts would be significantly more dramatic under Carper than under the CSA proposal, which is not surprising since the regulations under the Carper proposal would be more stringent.
Under the CSA proposal, 2.1 GW of new capacity would be required by 2008 over and above the needs under the Reference Case, which reflects current environmental regulations, and an additional 4.2 GW under the Carper proposal. Even though the provisions under the Carper proposal do not begin to take effect until 2009, the proposal would affect the timing of new additions before that date. The reason is that the added cost of bringing the 4.2 GW on-line earlier than 2009 is less than the the additional benefits achieved through operating the capacity prior to 2009.
Moreover, under the Carper proposal it would no longer be economic to build the 30 GW of coal capacity we project under the Reference Case. On the other hand, only 18 of the 30 GW of new coal capacity would be displaced under the CSA proposal. The coal capacity would be replaced by combined-cycle capacity because both proposals place a premium on new sources with low nitrogen oxides, sulfur dioxide, and mercury emissions rates. Gas-fired combined-cycle units, which have virtually no sulfur dioxide or mercury emissions and very low nitrogen oxides emission rates, become the plant type of choice among conventional alternatives. And, in the case of the Carper proposal, the relatively low carbon emissions rate of combined-cycle plants gives this technology an added advantage over other traditional resources.
Also, it should come as no surprise that under both proposals there would be more renewable resources than would occur under the Reference Case. The impacts on the timing and mix of new capacity additions is summarized in Tables 3A and 3B for the CSA proposal and in Tables 4A and 4B for the Carper proposal. In these four tables, the capacity numbers represent cumulative additional capacity over and above the capacity additions for the Reference Case shown in Tables 1A and 1B.
The driving force that creates the differences between the impacts of the CSA and Carper proposals is the cap on power plant carbon emissions under the Carper proposal. In the absence of a carbon cap, the two proposals would have very similar impacts on the timing and mix of new capacity additions. This can be seen by comparing the results for the Carper proposal without a carbon cap shown in Table 5 with the results in Table 3A.
Living With Higher Gas Prices
As we discussed at the outset, whenever natural gas prices spike or, as in the case over the past year, where there has been a sustained increase in prices, there seems to be an inevitable debate over whether the era of relatively low gas prices has ended. While we do not see the most recent increase as a definitive indication of significantly higher natural gas prices over the long term, the possibility cannot be ruled out entirely. Consequently, we have evaluated how significantly higher long-term natural gas prices would affect the timing and mix of new capacity. We have assumed gas prices would be $5 per million Btu in constant dollar terms through 2018.
Higher gas prices would have two significant impacts. First, they would dramatically accelerate the need for new capacity on an economic basis. Second, primarily coal plants, but also significant amounts of renewable resources would be substituted for combined-cycle plants and, to a lesser extent, single-cycle combustion turbines. We project that the higher gas prices could lead to 21.2 GW of renewable resources by 2006 over and above what we project under the EIA's gas price forecasts and an additional 67.4 GW of coal-fired capacity by 2008. (For the purposes of this analysis we have not factored in any institutional or infrastructure issues that could limit these dramatic changes in the mix of new capacity additions.)
It is necessary to qualify these short-term results. The experience over the 2000-2003 period tells us that substantial amounts of new capacity could be brought on line in a relatively short period of time, albeit not necessarily in the appropriate locations. Over the 2000-2003 period, an average of about 45 GW a year came on line, and about 62 GW in 2003 alone. In our view, it is unlikely that siting, permitting, and constructing 67 GW of coal-fired capacity could be achieved by 2008, and some portion of this capacity, possibly a large portion, would have to be deferred. But the key point is that there would be a significant demand for substantial amounts of new capacity in the short to medium term if generators were confident that sustained high gas prices were likely. The timing and mix of new additions is shown in Tables 6A and 6B.
Of course, those regions most dependent on gas, and where coal could be sited, would see the largest shifts to coal and renewable resources. By 2006, the largest impacts would be in the WECC, with its relatively large renewable resource base. Assuming, as we did, a four-year lead time for new coal plants, the earliest they could begin to displace gas would be 2008. Thereafter, new coal would be the main source for meeting growth in demand and for displacing gas-fired generation. Obviously, the extent of this substitution would depend on the level of gas prices.
Nukes to the Rescue?
For the preceding analysis, we have adopted the assumptions regarding the costs and characteristics of a new generation of nuclear plants, the key component of which is capital cost. The estimates the overnight costs with contingencies to be $2,141/kW expressed in 2002 dollars. Up to this point, our results reflect the estimate, and at this cost new nuclear plants do not appear to be economic.
At least one vendor of nuclear plants with an Nuclear Regulatory Commission-licensed design maintains it can construct nuclear plants at a cost significantly less the than the estimate-an overnight cost of about $1,500/kW expressed in 2002 dollars for a single-unit facility. Assuming the cost of the second unit is 15 percent less than the first, this would translate into an average cost for a two-unit facility of around $1,400/kW.
In our analysis, we assumed a new nuclear plant could be in place no earlier than 2010, reflecting a six-year lead-time. As a point of comparison, the assumes a lead time of five years for a new nuclear plant.
At the cost-estimate level, we found new nuclear plants would be economic only under the Carper proposal, in conjunction with high gas prices.
The prospects for the installation of new nuclear plants could improve dramatically if the vendor's estimate proves accurate. Single unit plants would be economic under the Carper proposal with expected gas prices. At higher gas prices, single unit plants would be economic under current regulations as well as under the CSA proposal. Two-unit nuclear plants, however, would be economic under all of the cases we have considered.
The availability of an economic nuclear option has very little effect, however, on the timing of new capacity requirements. If an economic nuclear option were available, it would displace primarily combined-cycle plants but relatively little new coal capacity. In all cases, we assumed a new generation of nuclear plants would achieve a 90 percent equivalent availability, which is consistent with recent performance by the fleet of existing nuclear plants.
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