1

ECONOMIC ANALYSIS ON BEHALF OF

CONSERVATION ORGANIZATIONS

Proposed Federal Implementation Plan to Address Regional Haze

Requirements for the Navajo Generating Station Units 1, 2, and 3

Submitted by David Marcus

December 31, 2013
2

I. INTRODUCTION

These comments primarily address Factors 2 (energy and non-air quality impacts) 

and 4 (remaining useful life) of EPA’s Technical Support Document (TSD), as well as 

the deferral alternative proposed in the TSD and various analyses cited in the TSD. 

Because the TSD analysis of affordability relies heavily upon a study done by Energy 

Strategies (ES) for the EPA,1as well as a study done by the National Renewable Energy 

Laboratory (NREL)2for the Department of the Interior (DOI),3these comments address 

those two studies in detail.

II. SUMMARY OF CONCLUSIONS

EPA is correct to conclude in its Factor 2 analysis that the proposed SCR retrofits 

will have energy impacts that (in the absence of other, subsequent pollution control costs) 

they will not make the Navajo Generating Station (NGS) uneconomical to retain in 

service. Even if later pollution control costs do occur or are expected by the NGS owners 

to occur, there is little chance that the expected costs of those later pollution costs would 

leave NGS cost-competitive by a margin small enough that the cost of SCR would tip the 

balance to non-competitive.

EPA is also correct to conclude in its Factor 4 analysis that the likely remaining 

life of the NGS is at least 20 years. NGS may be retired by 2019 (when various current 

leases and contracts expire), without regard to the NOX control retrofits at issue here, in 

which case EPA’s analysis is moot. But if the existing water, land and coal contracts are 

extended as currently planned, then they will allow it to run for at least 20 years after the 

time SCR is installed, and installation of SCR will not affect the remaining life.

The ES study of NGS economics contains a major error regarding depreciation, 

and a series of other errors or assumptions which lead it to generally underestimate the 

cost of replacing NGS generation if NGS is closed rather than retrofitted. Thus, the ES 

study substantially underestimates the likelihood and margin of NGS costcompetitiveness after SCR retrofits.

The NREL analysis looks at the energy economics issue from the point of view of 

the Western U.S. electrical grid as a whole, rather than the point of view of the NGS 

owners. Thus it does not actually address EPA’s Factor 2 issue as to whether NOX

retrofits would make NGS uncompetitive from the point of view of its owners. The 

analysis that NREL does do shows that NGS with NOX retrofits is preferable from a 

West-wide economic perspective to retiring NGS.

The NREL analysis of impacts on water users contains a flawed analysis of the 

impacts of sales of NGS surplus energy. In general, those who would face the greatest 

 

1

“Report: Affordability Analysis of BART Options for Navajo Generating Station,” Final Report, 1/14/13, 

prepared for E C/R Incorporated by Energy Strategies, LLC (cited below as “ES”).

2

“Navajo Generating Station and Air Visibility Regulations: Alternatives and Impacts,” National 

Renewable Energy laboratory, 1/18/12, with corrections 3/15/12 (cited below as “NREL”).

3 NREL, p. ii.
3

percentage increase in their water costs because of NGS retrofits would be the same users 

who are currently paying the least, and would continue to pay the least.

Finally, the deferral alternatives discussed in the TSD would all increase 

emissions, and thus the environmental impacts of NGS, compared to the no-deferral 

alternative. Among the deferral alternatives, the EPA-proposed deferral with NOX control 

retrofits in 2021-23 would be the best on both technical grounds and pollution control 

grounds.

III. EPA ANALYSIS IN TECHNICAL SUPPORT DOCUMENT (TSD)

A. Factor 1—Costs of Compliance4

The TSD’s Factor 1 analysis compares the costs and emissions reductions of three 

different alternatives, and computes resultant cost effectiveness (in dollars per ton of 

avoided NOX emissions) for each alternative.5 All three alternatives include LNB/SOFA, 

which has already been installed at NGS. The first alternative has no incremental controls 

added, the second adds SNCR, and the third adds selective catalytic reduction (SCR).6

The TSD concludes that SCR would cost $58.8 million per year to achieve a NOX

emissions level of 0.055 pounds per million Btu. These comments do not address the 

accuracy of the TSD’s conclusions regarding SCR annual costs, which will be addressed 

by other experts. However, the TSD figure of $58.8 million is very close to the implicit 

figure of $59.0 million in the supporting study done by Energy Strategies, LLC.7It is also 

inside the range of $57.1-$69.7 million per year calculated by the National Renewable

Energy Laboratory.8

B. Factor 2—“Energy and Non-Air Quality Environmental Impacts”9

As part of its Factor 2 analysis, the TSD includes an “affordability analysis ... as 

it relates to potential economic disruption.”10 The “affordability analysis” is based on a

 

4 Technical Support Document for NGS Proposed BART Determination, revised February 11, 2013 (cited 

below as “TSD”), p. 37, with ensuing discussion on pp. 37-55.

5 TSD, p. 5, Table ES-1.

6

Ibid.

7

See Table 1, which calculates the annual cost of SCR retrofits, in 2012 dollars, from data on pp.21-22 of 

“Report: Affordability Analysis of BART Options for Navajo Generating Station,” Final Report, January 

14, 2013, by Energy Strategies, LLC (cited below as “ES”).

8

See Table 1, which calculates the cost of SCR retrofits from data on pp. 14, 19, 47, 59, and 61 of “Navajo 

Generating Station and Air Visibility Regulations: Alternatives and Impacts,” corrected version of 

3/15/2012, by the National Renewable Energy Laboratory (cited below as “NREL”). Note that the NREL 

study calculates costs separately for the utility owners of NGS and for the Bureau of Reclamation (BOR) 

share of NGS, and those separate calculations are aggregated in the attached spreadsheet. Also, the NREL 

analysis combines high capital cost estimates from one source with high operating cost estimates from a 

different source to get its high total cost estimate, and vice versa to get its low total cost estimate. If it had 

not done so, but had combined the operating and capital cost estimates from each source, then its range of 

total costs would have been $61.9-$65 million per year.

9 TSD, p. 55, with ensuing discussion on pp. 55-82.

10 TSD, p. 62.
4

study done for EPA by Energy Strategies, LLC (ES), as a subcontractor to EPA 

contractor EC/R Incorporated.11 The ES study concludes, and the TSD accepts, that the 

net present value (NPV) of the cost of retrofitting NGS with SCR will be $648 million if 

SCR is retrofitted in 2016-18, whereas the market cost of replacing NGS generation 

would have an NPV of $673-1040 million.12 Thus, for the full range of market prices 

studied by ES, “the cost to produce power at NGS with SCR installed on all units should 

be below the market prices of wholesale power,”

13 meaning that it would not be 

economically desirable to retire NGS because of SCR-related cost increases.

The TSD’s analysis strongly suggests that SCR as BART would not make NGS 

uneconomic, and thus would not trigger the retirement of NGS. Moreover, as discussed in 

some detail below,14 the ES study which underlies the TSD’s “affordability” analysis 

contains some major errors which cause it to underestimate the cost-effectiveness of NGS. 

In particular, the ES study greatly overstates the depreciation costs associated with NGS, 

appears to understate the replacement power costs if NGS is retired, and appears to 

understate the costs associated with changes in market prices. The ES study also has a 

variety of smaller errors that generally cause it to underestimate the cost-effectiveness of 

keeping NGS in service even with SCR retrofits.

One major omission from the TSD’s analysis of energy impacts is any 

quantification of potential CO2 pricing impacts. However, the EPA was correct to not 

adjust its affordability analysis for potential future CO2 charges. Current CO2 prices –

zero for NGS owners outside of California – will have no effect on the economics of 

adding SCR to NGS. Sufficiently high CO2 prices would cause NGS to be retired 

whether SCR is required or not, or has already been added.15 Only a narrow band of 

potential future CO2 prices would cause the economics of retaining vs. retiring NGS to be 

different with and without SCR. There is no reason to believe future CO2 prices, if any, 

will be believed by NGS’s owners to fall precisely in that band. There is thus no reason to 

believe that the NGS owners will decide to retire NGS rather than install SCR because of 

their beliefs about future CO2 prices.16

The TSD also fails to address the possibility that individual owners of NGS could 

have different positions regarding the economics of installing SCR. However, this 

omission does not affect the TSD’s conclusions. The issue of possible different positions 

for different owners was addressed in the underlying ES study. The ES analysis suggests 

that IOU owners would be better off withdrawing from NGS rather than paying for 

 

11 Ibid.

12 TSD, p. 63, Table 18.

13 TSD, p. 82.

14 See section IV.A. of these comments.

15 For example, LADWP, the one NGS owner located in a state (California) that does price CO2, made its 

decision to divest its NGS share before the draft BART decision was even issued. But that decision by one 

owner has not caused NGS as a whole, or any of its units, to be retired.

16 Indeed, even if some current NGS owners expect future CO2 emissions to be priced, as they already are 

in California, that does not mean that NGS will be retired. See the example of LADWP, whose announced 

sale of its share of NGS has not led to retirement of all or part of NGS. Only if there are no utilities willing 

to collectively own NGS would it be retired.
5

SCR.

17 The reason is the income tax gross-up costs applicable to IOUs for SCR-related 

ratebase, costs which do not exist for tax-exempt non-IOU NGS owners.

If such a withdrawal occurred, then since IOUs own 33% of NGS, there might 

well be an outcome in which one unit was retired. The remaining two units under nonIOU ownership would then be able to implement SCR cost-effectively. Alternatively, if 

the divesting IOUs sold their shares in NGS to non-IOUs (either the current owners or 

new ones), then all three units of NGS would be able to implement SCR cost-effectively, 

since the new owners would not face income tax consequences associated with earning 

profits on SCR.

C. Factor 3—Existing Controls—No Issues

Factor 3 of the TSD is an analysis of the nature and effectiveness of existing 

emission controls at NGS. This analysis is non-controversial, and is not addressed here.

D. Factor 4—Remaining Useful Life

Factor 4 of the TSD analysis addresses the remaining useful life after installation 

of BART. The brief discussion in the TSD concludes that, given negotiations to extend 

the NGS land lease to 2044, a longer useful life than 20 years may be appropriate.18 2044 

would be 25 years beyond the 2019 date when SCR installation would be due (assuming 

a five-year period to comply with a BART determination that was finalized in 2014). 

Since the 2044 lease extension has not yet been approved, the EPA’s use of a 20-year 

useful life is appropriate.

Use of a shorter useful life than 20 years would not be appropriate. The operating 

costs to run NGS, including O&M costs that are avoidable only through shutdown, are 

approximately $30 per Mwh,19 below both current market prices20 and forecasted future 

market prices.21 Once SCR is installed, its capital costs will become sunk costs that no 

longer affect the decision to retire or retain NGS in service. So there is no reason to think 

that NGS, once SCR has been paid for and installed, would be retired before its land lease 

expires.

The only situation in which a useful life of less than 20 years might occur is if 

SCR were not installed until less than 20 years before the expected 2044 expiration date 

of the extended NGS land lease. The TSD contemplates such a possibility under 

Alternatives 2 and 3 (but not Alternative 1) to its BART analysis.22 However, as 

 

17 ES, p. 23, Table 5.

18 TSD, p. 86.

19 APS, 2012 FERC Form 1.

20 Table 6, line 85, showing Palo Verde prices averaging just under $32/Mwh for the last twelve months.

21 ES, p. 28, showing projected future Palo Verde market prices of $40/Mwh in 2016 and more thereafter. 

The ES price forecast is based on EIA data (ES, p. 28, fn. 19) which are expressed in real terms. In nominal 

dollar terms, the ES market price forecast would be even higher.

22 TSD, pp. 140-141.
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discussed below,23 the TSD does not propose adoption of either Alternative 2 or 

Alternative 3, and the fact that they would have prospective useful lives of under 20 years 

is just another reason to reject them.

E. Factor 5—Visibility Impacts—Not Analyzed

Factor 5 of the TSD analysis deals with the impacts on visibility of the BART 

alternatives. Factor 5 is beyond the technical scope of these comments, and is not 

addressed herein.

F. Deferral Alternative

1. Alternative 1 is not “better than BART”

Besides the five-factor analysis, the TSD also contains a discussion of an 

alternative under which BART retrofits would be delayed for some years. Under 

Alternative 1, which the TSD endorses, retrofits would be completed on one unit per year 

by 2021, 2022, and 2023.24 Alternatives 2 and 3, which are not endorsed by EPA, would 

defer BART retrofits even further, until 2023-24-25 or 2024-25-26.25

The TSD asserts that Alternative 1 would be “better than BART.”26 This claim is 

based on the fact that NOX emissions in 2009-2044 would be lower for Alternative 1 than 

for BART if (and only if) Alternative 1 is credited with an emissions reductions of 92,175 

tons due to LNB/SOFA installation in 2009-11.27 But if Alternative 1 should be credited 

for the emissions reductions due to LNB/SOFA, than so should BART itself. The TSD 

gives a credit to Alternative 1, but no credit to BART. As it result, its claim that 

Alternative 1 is “better than BART” ignores the plain fact that Alternative 1 would have 

emissions 71,930 tons greater than BART.28

The fact that BART would likely not have to be installed until 2019,29 rather than 

2018 as assumed in the TSD,30 does not change the fact that Alternative 1 will not be 

“better than BART.” In the TSD analysis, Alternative 1 allows SCR to be installed an 

average of 4 years later than with BART.31 Deferring BART until 2019, but not changing 

Alternative 1, would reduce the delay from an average of four years to an average of 

 

23 See section III.F of these comments.

24 TSD, p. 140.

25 TSD, pp. 140-141

26 TSD, p. 140.

27 Ibid.

28 Ibid., Table 47, “Total Emissions over 2009-44” line; 430,904 tons (Alternative 1) minus 358,974 tons 

(BART) equals 71,930 tons.

29 With the comment deadline deferred until October 2013, a final decision on BART is not likely until 

2014. With a 2014 decision, the five-year compliance deadline would fall in 2019.

30 TSD, p. 140, Table 47.

31 Ibid. 2018 is four years earlier than the average of 2021, 2022, and 2023.
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three years. That would still leave cumulative emissions from Alternative 1 about 54,000 

tons greater than from BART.32

2. Alternative 1 is better than Alternatives 2 and 3

If one of the deferral items were going to be adopted, EPA’s proposed deferral is 

the most reasonable of the set of deferral options identified in the TSD, from both an 

emissions point of view and an engineering point of view.

From an emissions point of view, Alternative 1 would result in emissions lower 

than either Alternative 2 or Alternative 3. Compared to Alternative 2, Alternative 1 

would have lower lifetime NOX emissions by almost 36,000 tons.33 Even if Alternative 2 

included EPA’s proposed short-term or long-term “emissions bridge” to offset an 

additional 15,179 tons of NOX emissions,34 Alternative 2 would still be worse than 

Alternative 1 by over 20,000 tons.35

Compared to Alternative 3, Alternative 1 would have lower lifetime NOX

emissions by almost 54,000 tons.36 Even if Alternative 2 included EPA’s proposed shortterm or long-term “emissions bridge” to offset an additional 33,160 tons of NOX

emissions,37 Alternative 2 would still be worse than Alternative 1 by over 20,000 tons.38

From an engineering point of view, efficiency argues for coordinating SCR 

installation with major outages,39 which occur only once per six years for each unit. EPA 

data shows the first planned post-2018 major outages are in the years 2021-22-23. These 

are the years in which SCR would be installed under Alternative 1. After those years, the 

next set of major outages would be in 2027-28-29. Thus, for Alternative 2, only one unit 

would be retrofitted with SCR during a year with a currently scheduled major outage 

(2023). For Alternative 3, none of the years of SCR retrofits (2024-25-26)40 would 

overlap with a major outage.

 

32 71,930 tons (TSD, p. 140, Table 47, “Total Emissions over 2009-44” line) for a four year delay, times 

three-fourths, equals 53,948 tons for a three-year delay.

33 TSD, pp. 140-141, Tables 47-48, “Adjusted Emissions” lines. 374,154 tons (Alternative 2) minus 

338,189 tons (Alternative 1) equals 35,965 tons.

34 TSD, p. 141, Table 48.

35 35,965 tons minus 15,179 tons equals 20,786 tons.

36 TSD, pp. 140-141, Tables 47-48, “Adjusted Emissions” lines. 392,134 tons (Alternative 3) minus 

338,189 tons (Alternative 1) equals 53,945 tons.

37 TSD, p. 141, Table 48.

38 53,945 tons minus 33,160 tons equals 20,785 tons.

39 See, e.g., ES, p. 19, fn. 14.

40 TSD, p. 141, Table 48.
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IV. MAJOR STUDIES RELIED UPON BY EPA

A. Energy Strategies (ES) Analysis

The ES analysis forms the basis for the TSD’s conclusions regarding the 

economic impacts of installing BART at NGS.41 The TSD incorporates the ES study’s 

conclusion that the cost of installing BART by 2018 will be less than the cost of closing 

NGS and replacing it with market-priced energy purchases.42 The TSD goes on to 

conclude that “although SCR will increase the cost of electricity generation, it is not 

likely to force NGS to shut down because the total cost to produce electricity at NGS, if 

retrofit with SCR on Units 1-3, should not exceed the total cost to purchase electricity on 

the wholesale market.”43

The ES analysis does indeed support the policy conclusions of the TSD, but it 

also contains both major and minor analytical errors. Correcting those errors, which are 

discussed in detail below, suggests that NGS with SCR would be less expensive than 

replacing NGS with market purchases by well over $600 million, a much larger margin 

than calculated by ES.

1. Major errors

The ES analysis contains two major errors which each cause it to underestimate 

the cost of the Market cases by about $300 million. Together, the two errors cause the 

Low Market case cost to be underestimated by at least $603 million.44 Thus, while the ES 

study says the Low Market case would cost $25 million more than an SCR case, 

correcting the ES study raises the difference between the Low Market and SCR cases to 

at least $628 million.

a. Depreciation

When a power plant such as NGS is built, its customers do not pay for the cost of 

construction as it is incurred. Rather, the cost of construction is recovered in annual 

payments from customers over a multi-year period. The annual cost associated with 

recovering the cost of construction is known as “depreciation” or “return of capital;” it is 

different from the profit, or “return on capital” which may also be recovered from 

customers.

Because depreciation expense is incurred by customers to repay already-incurred 

construction costs, it is generally not avoidable. If the powerplant in question is retired 

before all the original cost has been repaid, the outstanding unrecovered depreciation 

 

41 TSD, pp. 61-66, Factor 2 analysis, section D.2.

42 TSD, p. 63, Table 18.

43 TSD, p. 64.

44 $320 million due to omitted depreciation costs and $283+ million due to underestimated market prices 

even in the Low Market case. $320 million plus $283+ million equals $603+ million. See the discussion 

below for the quantification of the two errors.
9

does not just disappear. It still has to be recovered, either from customers or from the 

original investors (e.g., utility shareholders) in the form of a write-off.

In the particular case of NGS, ES has made two major errors with regard to 

depreciation. First, ES appears to assume that if NGS were to be retired, any 

undepreciated capital costs for NGS would simply disappear. ES writes that “the prices 

utilized in the model for all market cases are believed to be very conservative in that they 

account only for wholesale purchase costs” and “do not make any assumptions regarding 

the recovery of stranded investments – such as plant that is no longer used and 

useful ....”45

ES is all too correct; ignoring the recovery of stranded investment – meaning the 

unrecovered depreciation at the time of NGS retirement – is indeed a “very conservative” 

assumption. In reality, the investor-owned utility owners of NGS (APS, TEP, and NPC) 

would certainly seek to recover the remaining depreciation from their customers rather 

than having their shareholders have to pay it. ES admits as much, writing that “it is 

reasonable to expect that utilities will not be willing to have shareholders absorb the full 

cost of losses related to stranded cost and would therefore seek to pass costs to 

ratepayers.”46

For the publicly-owned utilities that own the bulk of NGS, there are no 

shareholders to even theoretically absorb undepreciated investment costs. The publiclyowned utilities are owned by their ratepayers, and so their ratepayers will have to pay the 

remaining undepreciated NGS capital costs if NGS is retired before it is fully depreciated.

By ignoring post-retirement recovery of undepreciated NGS capital costs, ES has 

been, as it says, very conservative. It has understated the cost of the market alternative by 

an amount equal to the remaining NGS depreciation at the time of NGS retirement under 

the market scenario.

The second major depreciation error made by NGS compounds the effect of the 

first one. ES has greatly overstated the remaining undepreciated ratebase at NGS as of 

2011, and thus has greatly overstated the net present value of the NGS depreciation costs 

that it incorrectly models as avoided if NGS is retired. Table 5 replicates the assumptions 

that are made in the ES study regarding annual depreciation costs. It shows that the ES 

starting point, $1084 million of remaining undepreciated NGS ratebase in 2011,47 is too 

high by a factor of three or more.

48 As a result, the ES study ends up assuming that the 

 

45 ES, p. 30. See also ES, p. 26, paragraph 2, where it asserts that future capital additions would increase the 

cost of the Business as Usual case with NGS in service, implying that they would not increase the cost of 

the NGS retirement case as well. This is further evidence that the ES study ignores the fact that, in the 

market scenarios, undepreciated capital costs would not simply disappear and would still have to be paid by 

someone, most likely ratepayers.

46 ES, p. 30.

47 ES, p. 26.

48 Table 5, 2011 line, column 2 versus columns 10 or 13. The data in column 13 comes from NREL, p. 17. 

The data in column 10 of Table 5 comes from Annual Reports and 10-K statements of NPC, TEP, APS, 

and SRP. LADWP’s remaining unrecovered NGS capital cost (if any) after its planned divestiture of its 
10

net present value (in 2012 dollars) of 2012-36 depreciation costs for NGS will $541 

million if NGS remains in service through 2036,49 but only $220 million if each NGS unit 

is retired rather than being retrofit with BART.50 The reality is that the NPV of remaining 

2012-36 depreciation costs is more like $159-181 million,51 and will be smaller yet by the 

time a BART decision is final, although the precise number doesn’t really matter since it 

will end up being paid by customers whether NGS is retired or retrofit and retained in 

service. The difference between the two ES estimates, with and without retirement, is the 

size of the ES depreciation error.

The combined effect of the two ES depreciation errors, assuming that early 

retirement makes depreciation costs disappear, and then overstating those costs to boot, is 

that ES attributes a $320 million net present value benefit to retiring NGS early which 

does not and will not exist.52

The reason for the ES depreciation error is not clear. The NREL study, published 

a year earlier and cited in the ES study,

53 contained owner-by-owner data on the NGS 

original cost, accumulated depreciation, net plant in service, and construction work in 

progress (which would have to be depreciated once placed in service).54 The NREL data 

clearly showed that NGS depreciation was much further advanced than ES assumed it to 

be, with a correspondingly lower amount of depreciation still to be paid by customers.

Correcting the TSD to reflect the extra $320 million (NPV) of depreciation that 

ES omitted from its market cases would make even the Low Market case cost $345 

million more than SCR,55 rather than just $25 million more as reported in the TSD.56

b. Market prices

The ES report estimates the costs of three market price scenarios, in which NGS 

units are retired rather than retrofit, and their energy output is replaced with purchased 

power at market prices. However, the ES low case is too low, due to three separate errors, 

 

share of NGS will depend on the price at which LADWP sells its share of NGS, and not the 2012 

undepreciated NGS cost. Since LADWP plans to sell its share of NGS prior to 2018, its unrecovered NGS 

capital cost (if any) will be the same whether or not the remaining NGS owners end up retiring NGS or 

retaining it.

49 Table 5, column 4.

50 Table 5, column 8.

51 Table 5, columns 12 and 15.

52 Table 5, column 9.

53 ES, p. 10.

54 NREL, p. 17, Table 1-6.

55 TSD, p. 63, Table 18, shows $648 million for SCR and $673 million for the Low Market case. The TSD 

numbers come directly from ES, pp. 7 (Table E-3) and 24 (Table 6), which shows that they are in net 

present value (NPV) dollars, based on a 7 percent discount rate (ES, p. 21). The $320 million figure in

Table 5, column 9 is also in NPV terms, and is also calculated using a 7 per cent per year discount rate to 

2012. Adding $320 million to the Low Market case increases its cost to $993 million. Compared to the 

$648 million cost for the SCR case, the Low Market case will then cost $993 million minus $648 million 

more, or $345 million more.

56 ES, p. 24, Table 6, shows $648 million for SCR and $673 million for the Low Market case. $673 million 

minus $648 million equals $25 million.
11

and their high case has prices well below those of a plausible high case. The result is that 

the near overlap that ES projects between the cost of the SCR case and the cost of the 

Low Market cost case isn’t really there. 

i. Low case forecast starting point

ES Tables E-3 and 6 shows SCR only $25 million better (in NPV terms) than an 

NGS retirement scenarios with “Low Market” replacement energy costs.

57 The ES 

analysis assumes a market price of $40.16/Mwh in 2016, in nominal dollars.58 How 

plausible is the ES low case forecast of $40.16/Mwh in 2016? Actual average Palo Verde 

prices in the year ending 8/9/13 were $31.97/Mwh.59 For the same twelve months, 

average Henry Hub natural gas prices were $3.516/MMBtu,60 for an implicit heat rate of 

9,093 Btu/kwh.61 Current Henry Hub forward prices for 2016 are $4.143/MMBtu,

62

which at the same implicit heat rate would correspond to a price of $37.672/Mwh.63 The 

ES low case expects 2016 prices that will be $8.19/Mwh above actual 2012-13 prices,64

but those 2012-13 prices coincided with the lowest gas prices for many years, prices that 

markets do not expect to recur. Thus the initial Palo Verde market prices in 2016 in ES’s 

Low Market case are reasonable.

ii. Low case escalation ignores the effect of retiring 

NGS

The ES analysis starting point may be reasonable for a world with NGS in it, but 

it fails to account for the impact on Palo Verde markets of retiring NGS. Even if Palo 

Verde prices would indeed be $40 in 2016 with NGS in service, they would not remain at 

that level if NGS were retired. NGS is the largest coal-fired plant in the U.S. Southwest, 

and removing 17 million Mwh per year of generation would move market prices at the 

closest market hub, Palo Verde. Thus the NGS participants could not expect to replace 

NGS generation at NGS-in-service market prices if they retire NGS. This impact, while 

not quantified by ES, could be quite significant, and improves the economics of SCR 

versus NGS retirement. The NREL analysis specifically modeled the impact on market 

prices of retiring NGS. NREL concluded that the increase in market prices for the area 

served by the NGS owners would be about 4 percent.65 For the expected 2016 Henry Hub 

 

57 ES, pp. 7, 24.

58 ES, pp. 27 (“the model starts with recently published Palo Verde market prices for the calendar year 

2016”) and 28, Chart 1. The exact 2016 initial figure of $40.16/Mwh comes from cells G9 and H9 of the 

“Market Power Price Tables” tab of the detailed spreadsheet that accompanied the ES report, titled 

“Model_BART_NGS_Affordability_Analysis_Model_r2-1-16-2013.xlsx” (cited below as “ES Model”).

59 Table 6, line 85.

60 Table 3, line 15.

61 $31.97/Mwh / $3.516/MMBtu = 9093 Btu/kwh.

62 Ibid., line 13.

63 $4.143/MMBtu x 9,093 Btu/kwh x 1 MMBtu/million Btu x 1000 kwh/Mwh = $37.6723/Mwh.

64 $40.16-$31.97 = $8.28/Mwh.

65 NREL, p. 40 (increases of 3.2-5.0 percent for individual owners when gas prices are at $6.90/MMBtu) 

and p. 42 (increases of 3-4% for individual owners when gas prices are $4/MMBtu, 3-5% when gas prices 

are $5/MMBtu). See also Table 2, Line 9, which uses data from NREL pp. 40 and 42 weighted by NGS 

ownership shares to show composite LMP increases of 3.7 – 4.3% due to NGS retirement.
12

gas price of $4.143/MMBtu,66 the impact on electricity market, prices would be about 

3.76%,67 which would increase ES’s $40.16/Mwh forecast by $1.51/Mwh.68

iii. ES Market case escalation ignores inflation

The ES forecast of market prices is based on price escalation data from the 

Energy Information Administration (EIA) Annual Energy Outlook publication.69 ES 

shows the resulting Palo Verde market prices that it calculated using its $40/Mwh starting 

point in 2016 and EIA escalation rates thereafter.70 But it does not explain whether the 

resulting prices are in nominal dollars for the years shown, or in unescalated 2016 

dollars.71

Table 4 replicates the ES analysis in order to determine whether the ES analysis 

includes post-2016 inflation or not. Columns 2-4 show the exact values for Palo Verde 

market prices from the ES Model, the spreadsheet that underlies the ES report. Columns 

5-7 assume that the ES numbers did not take into account inflation, and escalate the 

column 2-4 numbers by 3 percent per year, the ES inflation rate.72 Column 9 then shows 

the amount of NGS generation that would need to be replaced each year, and columns 10-

12 and 14-16 show the annual replacement energy cost using either the prices from 

columns 2-4 or those from columns 5-7. Finally, columns 13 and 17 show the result of 

taking the column 2 and 5 Low Market case prices and escalating them by 2.5%, which 

corresponds to a $1/Mwh increase in the starting price of $40/Mwh.

Line 4 of Table 4 summarizes the annual results into a 2012-36 net present value 

(NPV) cost. Comparing columns 10 and 13 shows that a 2.5% market price increase 

results in a $135.5 million NPV cost increase if the ES data is used directly, while 

comparing columns 14 and 17 shows that the effect of a 2.5% market price increase is 

$180.5 million if the annual ES prices are assumed to be real prices, and inflation is 

added to them.

In the ES report itself, the effect of both 10% and 20% market price changes have 

been quantified.73 In each case, the change in Low Market case NPV is within $0.13

million (0.1%) of the $135.5 million figure.74 Thus it is clear that Table 4 has accurately 

 

66 Table 3, line 13.

67 Table 2, line 10.

68 $40.16/Mwh x .0376 = $1.51/Mwh. Applied to the $37.672/Mwh 2016 price calculated in the previous 

section, a 3.76% increase would lead to a price of $37.672/Mwh x 1.0376 = $39.09/Mwh, which is barely 

$1/Mwh lower than the ES Market case price for 2016.

69 ES, p. 28, fn. 19.

70 ES, p. 28, Chart 1.

71 They cannot be in 2012 NPV dollars, because if they were, the starting point would be well below 

$40/Mwh.

72 ES, pp. 6, 22.

73 ES, p. 46, Table 13.

74 Ibid. In the 10% case, NPV changes from $8439 million to $7897 million, a change of $542 million. The 

corresponding change in NPV for a 2.5% price change, since 2.5% is 1⁄4 of 10%, would be $542/4 = $135.5 

million. In the 20% case, the NPV changes from $8439 million to $9522 million, a change of $1083 

million. The corresponding change in NPV for a 2.5% price change, since 2.5% is 1/8 of 20%, would be 
13

replicated the ES calculations in its columns 2-4 and 10-13, and that those calculations 

must be based on using the prices in the ES report with no adjustment for inflation.

The problem is that ES should not have ignored inflation. The EIA data that ES 

has relied upon are expressed in real dollars, with no inflation.

75 Thus the annual rates of 

increase that ES calculates from the EIA data are in real terms, and need to have inflation 

added to them to convert them to nominal dollars, which can then be discounted to get to 

the NPV dollars with which the ES results are expressed. By ignoring inflation, ES has 

effectively assumed that Low Market case market prices will remain unchanged in many 

years, including 2016-19 and 2026-29,

76 and rise less than 19% in nominal terms (to 

under $48/Mwh) over the entire 20-year period from 2016 to 2036.77 In a world with 3 

percent inflation,78 and with natural gas prices increasing over 140% in nominal terms 

from 2016 to 2035,79 it is simply wrong to expect wholesale electricity prices to rise just 

19 percent over a 20 year period. The EIA projection is for prices to rise faster than

inflation (albeit not by much), not 1/3 as fast as inflation.

iv. The ES market analysis stops in 2036

The ES “affordability model” calculates NPVs for “a 25-year period starting in 

2012 and ending in 2036.”80 By ending in 2036, it underestimates the relative costs of the 

Market and SCR cases over a full 20-year lifetime for SCR. That is because, under SCR, 

operating costs increase at just the rate of inflation,81 while capital-related costs are 

recovered using a fixed capital recovery factor and thus do not escalate at all.82 The 

composite annual cost of NGS under the SCR case thus escalates slower than inflation. 

Under all the Market cases, purchased power costs increase at more than the rate of 

inflation.83 So if the Low Market case costs more than the SCR case on an NPV basis 

(which it does even in ES’s analysis),84 then it must also cost more than SCR in the year 

 

$1083/8 = $135.375 million. Both $135.5 million and $135.375 million or within $0.125 million of the 

Table 4 figure (from line 4, difference between columns 10 and 13) of $135.5 million. 0.125/135.5 = .0009 

= 0.09%.

75 ES Model, “AEO 2011 Energy Prices” tab, cell A123. Inflation-adjusted prices are shown just below, on 

lines 128-132, but were not used by ES.

76 ES, p. 28, Chart 1; Table 4, column 2, lines 7-10 and 17-20.

77 ES Model, “Market Power Price Tables” tab, line 9, showing prices of $40.16/Mwh in 2016 and 

$47.74/Mwh in 2036, for an increase of $7.58/Mwh over the 20 years; see also Table 4, column 2, lines 7 

and 27. $7.58/$40.16 = .1887 = 18.87%.

78 ES, pp. 6, 22.

79 ES, p. 29, Chart 2, showing natural gas costs in 2009 dollars that increase (in the low case) from 

$4.45/MMBtu in 2016 to $6.25/MMBtu in 2035. Inflation at 3% per year (ES, pp. 6, 22) increases the 

$6.25 figure by a factor of 1.75, to $10.94/MMBtu. 10.94/4.45 = 2.46, corresponding to a gas price increase 

of 146 percent.

80 ES, p. 16.

81 ES, p. 22.

82 ES, p. 21.

83 See the previous section, explaining that the ES market prices (ES, p. 28) come from EIA data which is 

in real dollar terms, before adding inflation. Since real market prices rise in all three cases shown by ES, 

that means nominal market prices are rising faster than inflation.

84 ES, pp. 7 (Table E-3) and 24 (Table 6).
14

2036, and in every year after 2036.85 Thus, extending the period of analysis beyond 2036 

would increase the cost advantage of SCR over each of the Market cases. It would also 

increase the change in NPV due to a change in market price assumptions.86

The ES analysis assumes SCR retrofits are made in 2016, 2017, and 2018, 

respectively, for the three NGS units.87 Thus, a 20-year analysis should have extended to 

the year 2038 for the third unit.

v. Partially quantifying the errors in the ES forecast 

shows that the Low Market case would cost $285 

million more than ES estimates, and thus $310 

million more than the SCR case

Based on ES data, each $1/Mwh increase in the initial 2016 market price 

assumption would increase the NPV of the market option (through 2036) by $135.5

million.88 But correcting the ES analysis to account for inflation changes the $135.5

million figure to $180.5 million.89 Further correcting it to cover a 20-year period for each 

NGS unit would increase the $180.5 million figure to $187.3 million.90 So a $1.51/Mwh 

change in the initial Low Market case purchased power price, due to the effect of closing 

NGS on Palo Verde-area market prices, would increase the cost of the Low Market case 

by an NPV of $283 million.91 That would in turn cause a more-than-twelve-fold increase 

in the advantage of SCR over NGS retirement, from $25 million to $308 million.92

The $308 million figure is based on quantifying the effect of NGS retirement on Palo 

Verde prices, including the contribution of inflation and of ES’s truncation of its analysis 

in 2036 to that quantification. It does not quantify the effect of inflation on ES’s own 

2017-36 prices, which would further increase the cost advantage of SCR over the Low 

Market case.

 

85 In its detailed analysis, ES actually shows that the Low Market case costs more than the SCR case in 

each year from 2025 on, and costs $3.74/Mwh more by 2036. See the ES Model, “DWP-POU DCF” tab, 

line 17 (Low Market case) versus line 31 (SCR case).

86 Table 4, line 5 vs. line 4.

87 ES, p. 16.

88 Table 4, line 4, difference between columns 10 and 13. Note that ES, p. 46, Table 13, shows a $542 

million change in NPV due to a 10 percent change in market price, which also corresponds to a $135.5 

million change in NPV due to a 2.5% change in market price. A 2.5% change in market price is the same as 

a $1/Mwh change in a $40/MWh price.

89 Table 4, line 4, difference between columns 14 and 17.

90 Table 4, line 5, difference between columns 14 and 17.

91 $187.3 million per $1/Mwh x $1.51/Mwh = $282.8 million.

92 $25 million plus $283 million equals $308 million. If the increase in market cost due to a $1/Mwh price 

increase were only $135.5 million, as implied by ES, p. 46, Table 13, a $1.51/Mwh market price increase 

would still increase the gap between the SCR case and the Low Market case more than nine-fold, from $25 

million to $229.6 million. $25 + ($135.5 x 1.51) = $229.6 million.
15

vi. The ES High Market case forecast is also too low

ES projects “high” case market prices that are at most 13 percent above the low 

case prices,93 and on an NPV basis are only about 7 percent above the low case prices .94

That is an absurdly low range of possible outcomes for a forecast 20+ years into the 

future, as shown by the use of a much wider range in the ES sensitivity analysis section, 

up to 20% above the low case.

95 ES admits that it has used a “relatively narrow range of 

market price forecast sensitivities.”96 Its highest Palo Verde price forecast, for the year 

2036 in the High Market case, is only $52.11/Mwh,97 well below the actual annual Palo 

Verde price of $63.50 in 2008.98

At least one NGS participant has used much higher market prices in their own 

sensitivity analysis. The December 2012 LADWP forecasts of future gas prices have a 

high case that is 25% or more above their medium cases in the years 2019-32.

99

Moreover, historical data show gas prices are not symmetrically distributed – the high 

end of the range is farther above the mean than the low end is below it.100 LADWP’s 

projection of NGS replacement costs in 2016-20 increases by more than 44% from its 

low case to its high case,

101 and the high case replacement costs (an average of $89

million per year for LADWP’s share of NGS)102 correspond to $1380 million (2012 NPV) 

more than the low case replacement costs on a full plant basis, just for the years 2016-

20.

103 That is almost quadruple the ES study difference between low case and high case 

for the entire period out to 2036.104

 

93 ES, p. 28, Chart 1; ES Model, “Market Power Price Tables” tab, line 9 versus line 13; Table 4, column 2 

versus column 4.

94 6.8% per ES, p. 7 ($8806 million High Market cost minus $8439 million Low Market cost equals $367 

million difference) and p. 46 ($542 million difference from a 10 percent price change); 367/542 x 10% = 

6.77%. Alternatively, using year-by-year ES market prices that properly account for inflation shows a 

7.26% NPV difference between the Low Market and High Market cases; see Table 4, line 5, column 19.

95 ES, p. 46, Table 13.

96 ES, p. 46.

97 ES, p. 28, Chart 1; ES Model, “Market Power Price Tables” tab, cell AH13; Table 4, line 27, column 4.. 

As discussed above, ES has treated the prices in Chart 1 as nominal prices, and assumed (incorrectly) that 

they already account for inflation, even though they don’t.

98 ES, p. 29.

99 LADWP, 2012 IRP, December 2012, p. 129.

100 Ibid.

101 LADWP, 2012 IRP, December 2012, pp. 130-131. Low case costs for 2016-20 increase $307 million 

when NGS is replaced, while high case costs increase $443 million, or $136 million more. $136/$307 = 

.443 = 44.3%.

102 Ibid. 2016-20 high case costs increase $443 million when NGS is replaced. $443 million/5 years = $88.6 

million/year.

103 Ibid. High cost case costs increase due to NGS replacement by $34 million in 2016, $102 million in 

2017, $118 million in 2018, $131 million in 2019, and $58 million in 2020. Discounting at 7% per year (the 

ES discount, rate, per ES, p. 21, the corresponding figures in 2012 dollar terms are $25.9 million in 2016, 

$72.7 million in 2017, $78.6 million in 2018, $81.6 million in 2019, and $33.8 million in 2020, for a total 

of $292.6 million. Since LADWP is a 21.2% owner of NGS (NREL, p. 14), that corresponds to a full-plant 

cost of $292.6/.212 = $1380.2 million.

104 ES, p. 7, Table E-3, $8806 million High Market cost minus $8439 million Low Market cost equals $367 

million difference. 1380/367 = 3.76.
16

Notwithstanding the above discussion, the fact that ES has failed to evaluate a 

true High Market case is ultimately irrelevant to the BART decision. ES’s own numbers 

show that a Low Market case would be more expensive than BART with SCR. With the 

corrections for depreciation and Low Market prices described above, SCR would be less 

expensive than the Low Market case by over $628 million.105 Medium and High Market 

cases would exceed the cost of SCR by even more. The TSD conclusion regarding Factor 

2 economic impacts, that SCR costs would not trigger NGS retirement, is quite robust.

2. Smaller errors that add up to about $50-100 million in NPV

In addition to the two large errors described above, there are a half dozen smaller 

issues where the ES analysis has not used the most reasonable assumptions. Some of 

these issues, when corrected, increase the cost of the SCR case and others decrease it. 

One of them, future inflation, has indeterminate impacts. For the five issues that have 

been quantified below, the net impact would be to reduce the NPV cost of the SCR case 

by $46-107 million,106 while not affecting the cost of the Market cases. Thus, these five 

issues would collectively move the economic comparison between the SCR case and the 

Market cases an additional $46-107 million in favor of the SCR case.

a. Accelerated depreciation - $75.8 million cost reduction for 

SCR case

According to ES, BART retrofits at NGS, as pollution control facilities, should be 

eligible for accelerated depreciation treatment for tax purposes.107 Accelerated 

depreciation would reduce the NPV cost of SCR. ES quantified the reduction for the case 

in which the LADWP share of NGS has been sold to an investor-owned utility,108

resulting in investor-owned utilities having a combined 54% share of the NGS plant. For 

that scenario, accelerated depreciation would reduce the NPV of the SCR case by $124 

million.109 In the likelier case that LADWP sells to a publicly-owned utility, the investorowned share of NGS would be 33% rather than 54%, which would reduce the benefits of

accelerated depreciation to $75.8 million.110

 

105 $25 million per ES, pp. 7, 24. $320 million due to ES miscalculation and misallocation of depreciation 

costs (see section IV.A.1.a, above). $283 million due to ES miscalculation of NGS retirement impact on 

market prices, and the associated NPV calculation with correct inflation and plant life assumptions. $25 + 

$320 + $283 = $628 million. Note that even with the worst-case assumption that the LADWP share is sold 

to an IOU at a substantial price (apparently $1084 million x LADWP’s 21% share, or $228 million) only 

changes ES’s estimate of the cost advantage of SCR to -$90 million (ES, p. 25, Table 7, $8523 million 

minus $8613 million). With the corrections described above, that would still mean a cost advantage for 

SCR over the Low Market case of -$90 + $320 + $283 = $513 million.

106

-$75.8 million for accelerated depreciation, +0.0 or +49.8 million for costs associated with BOR surplus 

sales, -$26.9 million for Navajo Nation lease payments, +$0.0 or $10.7 million for heat rate penalty with 

SCR, -$4.1 million for replacement energy cost during SCR installation. -75.8+49.8-26.9+10.7-4.1 = -

$46.3 million. With adjustments of zero for the heat rate penalty and BOR surplus sales, the net effect 

would be -75.8-26.9-4.1 = -$106.8 million.

107 ES, p. 49, fn. 25.

108 ES, p. 49.

109 ES, p. 49, Table 16.

110 $124 million x 33/54 = $75.8 million.
17

b. Effect of SCR on net revenues from BOR sales of surplus 

NGS generation – zero to $49.8 million cost increase for 

SCR case

The Bureau of Reclamation owns 24.3 percent of NGS.111 With annual NGS 

generation of 16,952 gwh,112 that corresponds to 4119 gwh per year. Of that, 

approximately 2800 gwh per year is used for CAP pumping,113 and the impact of SCR on 

the cost of those 2800 gwh has been accounted for in the ES study.114 Of the remaining 

1319 gwh, 220 gwh has been sold to SRP under a long-term cost-based contract,115 so 

that SRP would end up paying for increased NGS operating costs due to SCR for those 

220 gwh.116 For the other 1099 gwh, BOR would sell them at market prices, with any 

profits flowed through to CAWCD as a reduction in its otherwise applicable $55 million 

per year repayment obligation to the US government for CAP construction costs.117

Increased NGS costs due to SCR would reduce BOR’s profit on those surplus energy 

sales, which would in turn increase the part of the $55 million annual obligation that 

CACWD actually has to pay.

The ES study itself does not indicate that it has taken account of either the 

increased costs to SRP or CACWD associated with the impact of SCR on BOR surplus 

sales.118 The total of those increased costs would be a fixed annual amount corresponding 

to a proportional share119 of the increased BOR cost for its 24.3 percent share of the cost 

of SCR installation. That BOR cost is $4.65/Mwh in 2018 and after,120 so the resultant 

dollar cost to SRP and CAWCD together would be $6.13 million per year, starting in 

2018.121 The 2012 NPV of the increased SCR costs associated with surplus sales would 

be $49.8 million.122 On the other hand, in the detailed spreadsheet underlying the ES 

study, the full 4119 gwh share of NGS generation for which BOR pays is included,123 and 

NPVs are calculated accordingly for the SCR and Low Market cases.124 So it appears that 

there may be no error at all in this part of the ES analysis.

 

111 NREL, p. 14.

112 ES, p. 32.

113 ES, p. 36, Table 10.

114 ES, p. 36, Table 10.

115 NREL, p. 55.

116 NREL, p. 55, fn. 5.

117 ES, p. 42.

118 ES, p. 36, Table 10.

119 1319/4119, the surplus part of the total BOR share of NGS generation.

120 ES, p. 36, Table 10.

121 $4.65/Mwh x 1319 gwh x 1000 Mwh/gwh = $6.133 million per year.

122 Table 7, “NPV” line.

123 ES Model, “BOR Only DCF” tab, line 3.

124 Ibid., lines 24 (Low Market case), 36 (SCR case), 48 (difference between cases).
18

c. Lease payments to Navajo Nation – $26.9 million cost 

reduction for the SCR case

The ES study assumes that annual lease payments to the Navajo Nation will 

increase by $15 million per year, starting in 2020.125 This is disproportionately high when 

compared to the lease payment increase at Four Corners, of $7 million126 for a 1490 Mw 

plant.127 On a proportional basis, assuming the same lease payment increase per Mw for 

both Four Corners and NGS, the lease payment increase for NGS would be $10.57 

million per year,

128 not $15 million per year. That is $4.43 million more than ES has 

assumed.

ES has calculated the impact of a $10 million per year change in the increased 

NGS lease payment.129 Table 7 confirms the accuracy of the ES calculations.130 If a $10 

million per year lease decrease would reduce the NPV of the SCR alternative by $60.8 

million,131 then a new lease payment increase proportional to the one at Four Corners 

would decrease the NPV of ES’s SCR case by $26.9 million.132

d. Heat rate penalty from use of SCR – either zero or $10.7 

million cost increase for SCR case

According to SRP, installation of SCR would worsen the heat rate of NGS by 0.5 

percent. This means that in an SCR case, 0.5% more coal would be needed to fuel NGS 

than in the business-as-usual (BAU). This is equivalent, economically, to using the same 

amount of coal as in the BAU case but paying an 0.5% higher price for it. The ES 

analysis does not take account of this heat rate penalty,133 asserting that it is already 

included as an operating cost for SCR.134 If so, then the ES model has correctly addressed 

this issue. However, to the extent the heat rate penalty really exists, and is not already 

accounted for in the SCR O&M cost estimates in the ES analysis, its magnitude can be 

estimated.

 

125 ES, p. 47.

126 ES, pp. 46-47.

127 The Four Corners plant is currently 2040 Mw, but APS plans to retire the three smaller units there, 

leaving a 2-unit plant (Four Corners 4-5) with a capacity of 1490 Mw. See 

http://www.srpnet.com/about/stations/fourcorners.aspx for unit capacities. The analysis here assumes the 

$7 million per year lease payment is for a 1490 Mw plant.

128 $7 million/year x 2250 Mw (NGS)/1490 Mw (Four Corners) = $10.57 million.

129 ES, p. 47, Table 14.

130 Table 7, “NPV” line.

131 Ibid.

132 $60.8 million NPV change / $10 million lease payment change x $4.43 million lease payment change = 

$26.93 million NPV change.

133 ES, p. 48, Table 15, shows identical changes to the BAU and SCR cases from changes in coal prices, 

implying that the tonnage of coal consumed is the same in both cases.

134 ES Model, “Input Table” tab, cells F88, I89.
19

ES estimates that a 20% increase in coal costs would cause a $427 million change 

in the NPV of the SCR case.135 Therefore, a 0.5% increase in coal costs would cause an 

NPV increase for the SCR case of $10.7 million.136

e. Capital cost of SCR - $4.1 million cost reduction for SCR 

case

ES, in calculating the cost of SCR, relies upon cost estimates from EPA.137 Those 

cost estimates are available as a spreadsheet file.138 They show that EPA capitalizes the 

cost of replacement energy during NGS shutdowns to install SCR.139 In other words, they 

count as part of the capital cost of installing SCR the money that will be spent to replace 

NGS generation during the maintenance outage required to install SCR. This is wrong 

from an accounting point of view, since it means that owners end up earning profits on 

energy purchases that have been treated as capital costs. Arguably, these costs should be 

expensed and not capitalized, which would cause a de minimus reduction in the NPV cost 

of SCR.

More importantly, EPA has accepted an SRP projection that the cost of 

replacement energy will be $45/Mwh.

140 ES, in turn, treats the EPA cost estimate as a 

2012 value and escalates it forward to the year of SCR installation at an inflation rate of 3 

percent per year.141 The result is implicit replacement energy costs during SCR 

installation of $50.65/Mwh in 2016, $52.17/Mwh in 2017, and $53.73/Mwh in 2018. 

These are much higher than the market prices ES uses everywhere else in its analysis. ES 

forecasts 2016-18 Low Market and Mid Market case market prices for energy of 

$40/Mwh,142 and NGS maintenance would be scheduled in months with lower 

replacement energy costs than the annual average cost (e.g., not in the summer). At a 

replacement energy cost of $38/Mwh (5% below the annual average due to maintenance 

scheduling) and a 1-week outage extension for SCR (the EPA assumption, accepted from 

SRP)

143, the effect of the lower replacement cost would be a reduction in the capital cost 

of SCR of $1.594 million in 2016,144 $1.785 million in 2017,145 and $1.982 million in 

2018.146 The NPV of that change would in turn be a $4.1 million reduction in the cost of 

the SCR case.147

 

135 ES, p. 48, Table 15. $8841 - $8414 = $427 million.

136 $427 million NPV change / 20% price change x 0.5% price change = $10.68 million NPV change.

137 ES, p. 22, Table 4 and fn. 16.

138 EPA, spreadsheet named “EPA_cost_analysis_for_NGS.xlsx” (cited below as “EPA cost analysis”).

139 EPA cost analysis, line 54 in each of the tabs entitled “Revised Costs Unit 1,” “Revised Costs Unit 2,” 

and “Revised Costs Unit 3.”

140 Ibid.

141 ES, p. 22.

142 ES, p. 28, Chart 1.

143 EPA cost analysis, line 54 in each of the tabs entitled “Revised Costs Unit 1,” “Revised Costs Unit 2,” 

and “Revised Costs Unit 3.”

144 750 Mw x 168 hrs x ($50.65/Mwh-$38/Mwh) = $1.5939 million.

145 Mw x 168 hrs x ($52.17/Mwh-$38/Mwh) = $1.7854 million.

146 Mw x 168 hrs x ($53.73/Mwh-$38/Mwh) = $1.9820 million.

147 Reducing the 2016, 2017, and 2018 capital cost of SCR retrofits by $1.594 million, $1.785 million, and 

$1.982 million, respectively (ES Model, “DWP-POU Plant Increm Costs” tab, cells E31, E30, and E32, 
20

f. Inflation

The ES analysis assumes a 3 percent per year inflation rate for all years.148

However, this is higher than the expected future inflation rate that can be calculated from 

the spread between the yield curves for TIPS149 versus regular Treasury notes and bonds. 

Because TIPS are inflation-protected but regular Treasury issuances are not, the 

difference between their yields is a measure of what level of inflation investors are 

expecting. Because there are billions of dollars invested in both TIPS and regular 

Treasury issuances, and the choice between them is driven by inflation expectations, that 

spread is an arguably better forecast of inflation than one simply generated by a 

consultant.

The current Treasury yield for regular issuances is 1.86 percent higher than the 

TIPS yield for a 7-year time period, 2.31% per year higher for a 20-year period, and 2.29% 

per year higher for a 30-year period.150 Thus markets are betting that inflation in the 

2013-20 period will average under 2 percent per year, and for the period from now 

through 2036 (the period of the ES analysis) will average between 2.29 and 2.31% per 

year.

The effect of a lower inflation rate on the ES analysis is unclear, likely small, and 

likely would reduce the cost of the SCR case relative to the Market cases, as calculated 

by ES. A lower inflation assumption would certainly lower the forecasted capital and 

operating costs associated with the SCR case. It ought to lower the forecasted market 

prices in the Market cases as well, but given ES’s exclusion of inflation from its market 

price escalation rates,151 would probably have no effect on the Market cases after 2018.152

Given the uncertainties of inflation forecasting, these comments contain no quantification 

of the effect of changing the ES inflation assumption from 3 percent to a lower number.

B. NREL Study

The NREL study was done a year before the ES study. Its primary focuses, as 

described in its Executive Summary, are the cost of SCR,153 the economic costs 

associated with retiring NGS rather than retrofitting it,154 nonair quality environmental 

 

respectively) reduces the resultant SCR case NPV by $3.1 million (ES Model, “DWP-POU DCF” tab, cell 

C36, $8410.317 million after reduction, versus $8414.408 million before reduction).

148 ES, pp. 6, 22.

149 Treasury Inflation Protected Securities. TIPS pay a yield set in real terms, plus whatever actual inflation 

turns out to be.

150 Yields as of 11/29/13, downloaded from http://www.treasury.gov/resource-center/data-chartcenter/interest-rates/Pages/TextView.aspx?data=yield and http://www.treasury.gov/resource-center/datachart-center/interest-rates/Pages/TextView.aspx?data=realyield.

151 See the discussion above in section IV.A.1.b of inflation in the ES analysis of market prices.

152 For 2012-2018, where the Market cases still include some NGS generation and associated costs, 

changing the inflation rate would reduce the Market case costs.

153 NREL, p. iii.

154 NREL, pp. iii-iv.
21

impacts of compliance,155 existing pollution control technology,156 the remaining useful 

life of NGS,157 visibility impacts of BART,158 and tribal benefits and impacts.159 These 

comments will focus on NREL’s analysis of the economic costs of retiring NGS rather 

than retrofitting it, and on NREL’s discussion of tribal impacts, which is where it 

discusses impacts on CAP water users in general, not just tribal water users.

1. The cost of SCR

a. Main NREL analysis

NREL relies on capital cost and operating cost estimates for SCR which come 

from two other sources,160 and then converts the capital costs into annual revenue 

requirements itself.161 NREL’s revenue requirement calculation is simplistic in the 

extreme; it does not address income taxes for investor-owned utilities,162 it uses a rate for 

SRP that is admittedly not cost-based,163 it is not representative of the normal investorowned utility time pattern of capital cost recovery,164 and it ignores capital structure 

issues.165

Notwithstanding its simplistic model, the NREL conclusions are quite consistent 

with those set forth in the TSD. NREL concludes that the total annual cost of SCR for 

NGS would be $57-70 million per year.166 For comparison, the TSD figure is $63.6 

million per year,167 right in the middle of the NREL range.

The NREL range of $57-70 million per year is calculated by taking capital costs 

from S& L and combining them with operating costs from the NPS, and vice versa. This 

 

155 NREL, p. iv.

156 Ibid.

157 Ibid.

158 Ibid.

159 NREL, pp. iv-v.

160 National Park Service (NPS) and Sargent & Lundy (S&L). See NREL, p. 47, Table 3-6.

161 NREL, pp. 19 (NGS owners other than BOR), 23 and 61 (BOR share of NGS).

162 NREL, p. 19, Table 1-10, “Applied discount rate” column. The resultant understatement of revenue 

requirements for investor-owned utilities may be offset, either in part or in toto, by the fact that the debt 

component of the cost of capital may be overstated for the IOUs, since pollution control retrofits can be 

financed on a tax-exempt basis, and have been at the past at NGS (NREL, p. 21).

163 NREL, p. 19, Table 1-10, note (a). Actual utility-rates are normally cost-based, and do not include 

additional charges to customers to cover hypothetical risks.

164 NREL, p. 19, Table 1-10. The NREL methodology produces a single level annual revenue requirement 

to be used over the 20-year period of capital cost recovery for SCR. Traditional investor-owned utility cost 

recovery is front-loaded, as profits are earned on undepreciated investment, which shrinks over time.

165 Traditional utility financing is based on a combination of equity (obtained either from sales of stock, or 

from retained earnings in the case of public-owned utilities) and debt. Since the financing costs for equity 

and debt can differ, sometimes by large amounts, the relative amounts of each are highly relevant. NREL 

assumes 100% debt financing of the BOR share of SCR costs (NREL, p. 23, Table 1-13) and does not 

address the capital structure to be used for the other NGS owners’ shares of SCR costs.

166 NREL, pp. iii (Figure ES-1) and 111.

167 TSD, p. 5, Table ES-1, showing a cost of $58.8 million per year for SCR + LNB/SOFA, and a cost of 

$5.2 million per year for LNB/SOFA alone. Thus the incremental cost for SCR alone (since LNB/SOFA 

has already been installed) is $58.8 minus $5.2 = $53.6 million per year.
22

exaggerates the spread of opinion about total costs, since the NPS estimates have higher 

operating costs but lower capital costs, while the S&L costs are higher for capital but 

lower for operations.168 If the total cost components were taken consistently from 

NREL’s two sources, they would result in an NPS cost of $62.0 million for the NPS,169

and $64.8 million for S&L.170 These costs are much closer together than those published 

by NREL, and the TSD estimate ($63.6 million per year) is once more in between them.

b. NREL’s sensitivity case with 10-year amortization is 

unrealistic

Besides its main cost analyses, which use a 20-year amortization period,

171 NREL 

also presents an “accelerated”172 scenario in which retrofit costs are amortized over a ten 

year period. This scenario is unrealistic.

Once built, SCR and baghouses have minimal effect on the marginal cost of NGS, 

so it would run even if its total cost exceeded the cost of replacement power (absent a 

very large CO2 cost, which would cause shutdown with or without SCR). So if SCR is 

going to be installed at all, it’s reasonable to use a 20 year depreciation period.

c. Differences between NPS and S&W re SCR capital costs

NREL refers in passing to lost revenues (they mean replacement power costs

during NGS outages while SCR is being installed) during SCR installation, and 

hypothesizes that the differences between NPS and S&L re SCR capital cost are because 

of differences regarding unit size used in calculating those replacement power costs.

173

The difference is more likely to have occurred because S&L assumes more weeks of 

incremental shutdown during SCR installation (especially for unit 2) than NPS. The real 

problem is that both estimates are too high in this area, because they assume replacement 

energy will cost $45/Mwh and be capitalized rather than expensed.174

2. Costs associated with retiring NGS

The NREL report concludes, as the ES analysis and the TSD subsequently would 

as well, that the cost of retiring NGS and replacing its generation with generation at other 

powerplants would be more than the cost of installing SCR at NGS and continuing to 

operate it. The NREL authors write that “The basic costs of installing SCRs at Navajo 

GS would likely be less than the basic costs of shutting it down and replacing it with 

 

168 NREL, p. 47, Table 3-6.

169 NREL, pp. 19 (non-BOR capital costs of $36.2 million per year), 23 and 61 (BOR capital costs of $9.1 

million per year) and 47 (O&M costs of $16.7 million per year). $36.2+$9.1+$16.7 = $62.0 million per 

year.

170 NREL, pp. 19 (non-BOR capital costs of $42.3 million per year), 23 and 61 (BOR capital costs of $10.6 

million per year) and 47 (O&M costs of $11.9 million per year). $42.3+$10.6+$11.9 = $64.8 million per 

year.

171 NREL, p. 19, Tables 1-10, 1-11, 1-12.

172 NREL, p. 20.

173 NREL, p. 47.

174 This issue was discussed above in section IV.A.2.e.
23

power from unused capacity elsewhere in the West.”175 The word “likely” in the NREL 

state is excessively cautious; the NREL numbers show a cost range of $57-70 million per 

year for SCR and a cost range of $197-502 million per year for replacing NGS generation 

with redispatch of existing powerplants.176 These two ranges are not even close. Even if 

BART cost twice as much as the upper end of the NREL range, it would still be $57 

million per year cheaper than the low end of the NREL estimate of the cost of NGS 

retirement.

While the NREL study certainly supports the TSD’s Factor 2 conclusion, a close 

review of the study reveals a variety of aspects of the study which make it less than ideal 

as a document for the EPA to rely upon. These are discussed below.

a. Future market prices

The NREL report does not directly address the question of future market prices, 

except for CAP replacement energy if NGS is retired. Its analysis of the cost of replacing 

NGS generation is based on “least-cost redispatch of existing units”177 and implicitly 

assumes that all energy will be priced at locational marginal prices (LMP).

For CACWD, part of whose roughly $55 million per year repayment obligations 

to the U.S. Treasury are defrayed by market sales of BOR surplus generation,178 the 

market price of generation is relevant even if NGS is not retired. And for all of the NGS 

owners, the cost of replacing NGS if it were retired would depend on market prices, to 

the extent they replaced NGS with purchased energy rather than increased generation 

from generators they already own.

The NREL analysis shows that (with the possible exception of NPC), the NGS 

owners would need to replace NGS generation in part with imports from outside their 

balancing areas.179 NREL admits that the ability of APS and TEP to increase dispatch 

from resources under their own control will “partially mitigate the price impact on APS 

and TEP of retiring NGS.”180 The reason for this, which NREL does not explain, is that 

APS and TEP, as vertically-integrated utilities, do not have to charge LMP to themselves 

for generation delivered to their own retail customers. So increases in LMP at their own 

powerplants need not translate into increased costs. Thus, the NREL calculations of LMP 

changes for individual utilities do not provide an accurate measure of the cost of NGS 

retirement for those particular companies. The NREL focus on redispatch enables them to 

 

175 NREL, p. 111. Italics in original.

176 Ibid.

177 Ibid.

178 NREL, p. 54.

179 NREL, pp. 33 (Table 2-2) and 35 (Table 2-3). Table 2-2 shows that, with NGS retired, less than1/3 of 

the annual replacement energy (5.5 TWh out of 17.5TWh) would come from within the balancing areas of 

the current owners. Table 2-3 shows that less of the NGS replacement energy would come from the current 

NGS owners’ balancing areas (5.52 TWh) than from either the California Independent System Operator 

(CAISO) balancing area (6.16 TWh) or other balancing areas (5.83 TWh).

180 NREL, p. 37. The same thing is true for the other NGS owners, other than BOR, which are also 

vertically-integrated utilities owning their own generation and using cost-based rather than market-based 

pricing for deliveries to their own retail customers.
24

verify that the Western grid as a whole would be better off with SCR than with NGS 

retired, but it does not directly address the cost impacts of NGS retirement on the NGS 

owners themselves.

Table 2 shows, using NREL’s data, what the NREL results about LMP would 

imply for the individual NGS owners other than BOR, if market prices and LMPs were 

indeed equal as assumed by NREL, and if all energy were priced at LMP. It shows that, 

of the $197-502 million annual increase in Western grid costs due to NGS retirement,181

$151-265 million of that increase would inure to the non-BOR owners of NGS.182 That is 

still much bigger than those owners’ $45-$55 million per year cost to install SCR.183

For BOR surplus generation, NREL acknowledges that most of it184 would be 

available for sale at market prices. But NREL then goes on to assume that those market 

prices would be only $27.25/Mwh,185 lower than the assumed $30/Mwh cost of 

production at NGS,186 and thus BOR would choose not to make surplus sales at all.187 As 

discussed above with regard to the ES study, actual future market prices are likely to be 

over $40/Mwh if NGS is retired.

Even as a measure of current market prices, NREL’s $27.25/Mwh figure is too 

low. NREL’s figure is based on actual historical prices, weighted 11% on-peak and 89% 

off-peak.188 But a correct weighting would be 52% on-peak and 48% off-peak.189

NREL’s assumption of a $27.25/Mwh sales price if NGS remains in service and 

sells surplus energy also contradicts its calculation that the market price of replacement 

 

181 NREL, p. 36, Table 2-4.

182 Table 2, line 7, columns 10 and 12. Owner-specific data is on lines 1-5. Calculated based on data from 

NREL, pp. 40 and 42 (LMPs by owner, with and without NGS) and 19 (annual sales per owner, used as a 

proxy for generation per owner).

183 Table 2, line 7, columns 1 and 2, based on data from NREL, pp. 14 (ownership shares of NGS), 19 

(SCR capital cost by owner), and 47 (SCR annual O&M costs).

184 An estimated 1280 gwh per year out of a total of 1500 gwh, with the other 220 gwh already sold under a 

long-term cost-plus-fixed-fee contract to SRP. See NREL, p. 55.

185 NREL, p. 60 and fn. 14.

186 NREL, p. 60. The $30/Mwh figure includes the fixed costs of NGS operation and maintenance. The 

variable costs, which are the relevant costs for operation, are only “slightly above $20/Mwh.” (NREL, p. 

31). Thus, even with a market price of $27.25/Mwh, NGS would still make surplus power sales (contrary to 

NREL) that would more than cover the variable cost of operating NGS, and would cover part of its fixed 

O&M costs as well.

187 NREL, p. 60 and Table 4-8 on p. 61 (no net value of NGS surplus power other than for portion already 

sold to SRP), p. 62 (no impact from SCR on NGS surplus power sales revenues, since those revenues, 

except for the SRP sale, are assumed to be zero with or without SCR).

188 NREL, p. 60, fn. 14.

189 NGS operates as a baseload plant, and produces electricity (on average) at the same rate in all hours. For 

the year as a whole, 55.68% of the hours are on-peak (16 on-peak hours/day x 6 days/week minus 8 

holidays per year, equals 4864 hours per 52 weeks). Of the 1500 gwh/year of NREL-forecasted surplus 

sales, 220 gwh (14.67%) would be to SRP, all of them on-peak. So the remaining 1280 gwh per year of 

surplus sales would have an off-peak share of (1-.5568)/(1-.14.67) = .5193 = 52%, not the 89% assumed by 

NREL.
25

power for CAP pumping, if NGS were shut down, would be $32.44-$49.48/Mwh.190

NREL attempts to explain away the discrepancy as caused by the fact that NGS surplus 

power sales would be “primarily off-peak power, which has a lower market price than 

on-peak power.”191 But that explanation is faulty. First, NREL has greatly overstated the 

percentage of NGS surplus generation sales that would be off-peak.192 Thus, on-peak/offpeak price differentials would only reduce the effective market price for CAP surplus 

sales by about $0.70/Mwh below the average market price,193 not the $5.19/Mwh 

assumed by NREL.194 Second, even if on-peak/off-peak price differentials explained the 

difference between $27.25/Mwh and $32.44/Mwh (NREL’s low price), they do not begin 

to account for the difference between $27.25/Mwh and $49.48/Mwh (NREL’s high price).

If it were really true that market prices are below the NGS cost of production, as 

NREL assumes for BOR surplus sales, then NGS should be retired immediately, without 

regard to BART. The bulk of the NREL analysis, which shows dispatch costs would go 

up sharply without NGS, implies that NGS generation cannot be replaced at market 

prices that are lower than the operating cost alone of NGS. Indeed, NREL suggests 

elsewhere that wholesale market prices for BOR “would be close to the LMPs in the 

areas where the CAP pumps are located,”

195 and it actually uses SRP LMP’s as the source 

of its cost estimates for CAP pumping energy costs if NGS were retired.196 NREL has 

quantified LMPs for SRP both with and without NGS. For gas prices between $4 and 

$5/MMBtu, they range from $31.08/Mwh to $38.46/Mwh,197 above both the NREL 

market price assumption elsewhere of $27.25/Mwh198 and the NREL assumption of the 

total cost of NGS of around $30/Mwh.199 That is why NREL concludes that replacing 

NGS generation with increased generation from other existing powerplants would 

increase grid costs by $197-502 million per year, and why Table 2 shows that $151-265 

million per year of that increase would occur inside the APS, LADWP, NPC, SRP, and 

TEP balancing areas.200

 

190 NREL, p. 66. The $32.44/Mwh low price comes from NREL, p. 42, Table 2-7, and is the SRP LMP with 

NGS retired and gas at $4/MMBtu. The $49.48/Mwh price comes from NREL, p. 40, Table 2-6, and is the 

SRP LMP with NGS retired and natural gas priced at $6.90/MMBtu.

191 NREL, p. 66, fn. 15.

192 See previous paragraph, showing an off-peak percentage of 52% rather than NREL’s 89%.

193 Table 2, lines 85-86, difference between two right-most columns.

194 $32.44/Mwh average market price per NREL, p. 42, Table 2-7, with NGS retired; $27.25/Mwh average 

CAP surplus sales price per NREL, p. 60 and fn. 14; $32.44 - $27.25 = $5.19/Mwh.

195 NREL, p. 41.

196 The NREL estimates for high and low CAP pumping costs on p. 67, Table 4-19 are identical to its 

estimates of SRP LMPs on p. 42, Table 2-7 ($4/MMBtu gas) and p. 40, Table 2-6 ($6.90/MMBtu gas).

197 NREL, p. 42, Table 2-7.

198 NREL, p. 60.

199 Ibid.

200 Table 2, lines 7 and 11, columns 10 and 12. Note that if SRP were to acquire the LADWP share of NGS, 

that would increase its exposure to NGS SCR costs, but would not increase its replacement energy costs 

after an NGS retirement. Even in that scenario, SRP’s prospective share of NGS SCR costs, $25-41 million 

(Table 2, columns 1 and 2, sum of lines 1 and 2), would still be less than the SRP-area increase in cost due 

to NGS retirement of $44-81 million (Table 2, line 1, columns 10 and 12).
26

b. Future gas prices

The NREL analysis assumes a natural gas price of $6.90 per million Btu, with 

sensitivity analyses at $4, $5, and $13 per MMBtu.

201 The $6.90/MMBtu price is higher 

than current forward Henry Hub prices through 2022 (when the forward price is 

$4.866/MMBtu),202 but the $4-$5 range is consistent with current prices ($3.98/MMBtu

rising to $4.41/MMBtu in 2014-19).

203 Given historical spikes,204 NREL’s range of prices 

up to $13/MMBtu is reasonable, and its sensitivity studies at $4-5/MMbtu are reasonable 

as expectations of what is likeliest to happen in the near future.

c. Inflation—not addressed by NREL

The NREL study does not address inflation.205 Since it is concerned primarily 

with redispatch costs, which are largely driven by natural gas prices, and since it analyzes 

a wide range of potential gas prices, ignoring inflation makes a certain amount of sense, 

and certainly simplifies the NREL analysis. But ignoring inflation comes with a cost. To 

the extent future prices for some key inputs (e.g., market prices, gas prices, CO2 prices) 

rise at different rates than others (e.g., SCR capital costs, coal costs), then NREL’s 

attempt to compare the costs of those alternatives will be flawed.

d. Carbon costs—not addressed by NREL

The NREL study also does not address future potential carbon taxes or other 

carbon costs.206 See comments above regarding the similar omission in the TSD.207

e. LMP analysis

NREL’s analysis of the increase in grid costs if NGS retires ($197-502 million per 

year)208 is a WECC-wide estimate. Some of that cost would be borne by non-owners of 

NGS, whose resource procurement wouldn’t change but whose LMPs would go up. Even 

for the NGS owners, much of their non-NGS generation is priced at cost, and so NGS 

retirement would not affect the costs of that generation. To the extent the non-NGS 

generation of NGS owners is currently sold at a profit rather than used to meet their own 

load, NGS owners would see a revenue decrease if they shut down NGS and had to use 

that generation to meet their own loads rather than selling it at a profit. But to the extent 

an NGS owner could make new sales to the other owners to replace their NGS generation 

after a shutdown, closing NGS would actually increase their profits. NREL’s analysis 

suggests the latter situation applies to NPC.209

 

201 NREL, pp. 31, 36, 37, 42.

202 Table 3, line 13.

203 Ibid.

204 NREL, p. 31, Figure 2-3.

205 See NREL, pp. 3-4, which omits inflation from the list of key assumptions.

206 NREL, p. 3.

207 Section III.B., above.

208 NREL, p. 111.

209 NREL, p. 33, Table 2-2 and p. 35, text and Table 2-3.
27

NREL apparently made no quantitative analysis of the costs to the NGS owners 

after a shutdown. Thus NREL makes a strong, but inaccurate, case that it is in society’s 

interest to retrofit SCR rather than retire NGS, and does not actually address the 

affordability issue analyzed by ES. However, based on NREL’s assertion that “wholesale 

costs” (i.e., market prices) would track LMPs,210 an approximate incremental cost to 

replace NGS for the NGS owners (other than BOR) only can be calculated from NREL’s 

data.

That cost is $46 million per year with gas at $4/MMbtu (basically equal to the $45 

million per year incremental cost of SCR in the low-SCR-cost case) but increases rapidly 

to $155 million per year with gas at $5/MMBtu (almost triple the $55 million per year 

cost of SCR in the high-SCR-cost case ).211

NREL provides another datum which also suggests that retaining NGS in service 

is in the economic interests of the NGS owners as well as the grid as a whole. NREL 

reports an LADWP expected sale price for Navajo of $360 million212 (equivalent to $1.7 

billion on a full-plant basis).

213 That number implies that operating NGS is cheaper than 

shutting it down by $1.7 billion on an NPV basis as of the time of sale (or else no one 

would pay to buy NGS). $1.7 billion is much bigger than the spread calculated in ES 

between operating NGS and closing it ($673-1040 million on a 2012 NPV basis,214

although that estimate is low by at least $600 million as discussed above215).

However, the basis for the NREL number is LADWP’s 2010 Integrated Resource 

Plan (IRP).

216 LADWP’s subsequent December 2012 IRP does not show a specific 

expected sale price for NGS.

The discussion above in this section addresses the NGS owners as a group. 

However, the LMP data provided by NREL also allow the natural gas prices at which 

retaining NGS becomes affordable even with high-cost SCR to be calculated on an 

owner-by-owner basis.

The calculated results range from $4.60/MMBtu (for SWP) down.217 The SWP 

price is highest because NREL accepted SWP’s claimed 9.8% discount rate,218 which is 

arguably high.

219 Even so, $4.60/MMBtu is below Henry Hub futures prices for all years 

after 2017,

220 strongly suggesting that ES and the TSD are correct in finding SCR 

 

210 NREL, p. 

211 Table 2, lines 7 (SCR cost) and 13 (net replacement cost of NGS energy).

212 NREL, p. 15.

213 $360 million for LADWP share (NREL p. 15), 21.2% LADWP share of NGS (NREL p. 14). $360 

million / .212 = $1698 million.

214 ES, p. 7.

215 See section IV.A.1, above.

216 NREL, p. 15, fn. 13.

217 Table 2, lines 13-19, column 10.

218 NREL, p. 19, Table 1-10.

219 See section IV.B.8.d, below.

220 Table 3, line 13.
28

affordable. The $4.60 per MMBtu gas price above which retaining NGS is economically 

preferable even with SCR is for the upper end of the NREL range of SCR costs. At the 

lower end of the range, the breakeven gas price drops to $4.37/MMBtu for SRP, and 

$4.28/MMBtu or less for the other non-BOR owners of NGS.221

In addition, the breakeven gas prices of up to $4.60/MMBtu implied by NREL’s 

data ignore the effect, calculated by NREL, of NGS retirement on LMPs. To the extent 

the NGS owners would obtain some of their supply at market prices even with NGS in 

service, then the price of those market-based supplies would increase if NGS were retired. 

In the extreme case (which NREL has assumed in its LMP analysis), where 100 percent 

of the NGS owners’ electricity supplies are priced at market rates, the increase in cost for 

non-NGS resources would be even larger than the increase in cost associated with 

replacing NGS generation itself. The resultant gas prices at which retiring NGS would 

increase electricity procurement costs would be no more than $2.16/MMBtu.222 That is 

such a low gas price that there is no doubt that keeping NGS in service, even with SCR, 

would be a cheaper alternative than retiring it.

f. Depreciation

Unlike ES, which miscalculated the remaining undepreciated cost of NGS at over 

$1 billion,223 the NREL study used depreciation data from the NGS owners themselves 

and shows net plant in service plus construction work in progress, as of 2010, of about 

$363 million.224 However, like ES, NREL incorrectly says NGS shutdown removes NGS 

undepreciated costs from profits and rates.

225 NREL is wrong to simply assume that NGS 

owners would not be able to charge their customers for their remaining undepreciated 

NGS plant costs if NGS were retired.

NREL’s incorrect assumption about depreciation costs after an early NGS 

retirement does not seem to have affected its study results. In the no-NGS analysis, 

NREL looks at the change in production costs resulting from closing NGS, but does not 

discuss any change in fixed costs such as depreciation.226

g. NGS capacity factor

The NREL report shows an NGS capacity factor of 83% for 2010.

227 However, 

this is lower than the long-term average NGS capacity factor because it includes a major 

maintenance outage. Elsewhere NREL says NGS has low marginal costs and “would be 

 

221 Table 2, lines 13-19, column 9.

222 Table 2, lines 13-19, columns 12 and 14.

223 See section IV.A.1.a, above.

224 NREL, p. 17.

225 NREL, p. 20.

226 NREL, Chapter 2.

227 NREL, p. 24 and p. 25, Table 1-15.
29

used as often as possible.”

228 This is confirmed by annual capacity factors in 2001-08 

averaging 87.2%,229 and NREL dispatch modeling predicting an 88.7% capacity factor.

230

While a long-term capacity of 88.7% for NGS is certainly possible, it is higher 

than the NREL-reported 2001-08 average capacity factor of 87.2%. If NREL has slightly 

overestimated the future performance of NGS, then it has slightly underestimated the cost 

per Mwh of BART, because the fixed costs of BART would have to be spread across 

slightly fewer Mwh of generation. By the same token, NREL would have slightly 

overestimated the cost of replacing NGS generation with redispatch of existing plants, 

because the amount of generation needing to be replaced would be slightly lower than 

NGS has estimated. Given the enormous disparity in the two estimates however ($57-70 

million per year for BART and $197-502 million per year for redispatch),231 any NREL 

error with regard to NGS capacity factor is minor.

h. Source(s) of replacement energy if NGS is shut down

NREL assumes all replacement energy can be obtained by redispatching existing 

generation, and uses its dispatch model to quantify the costs of doing so. NREL dismisses 

any need for replacement capacity as something that would happen “eventually.”

232 But 

with a reported Desert Southwest regional reserve margin of 27% in 2011,233 load growth 

of 1-2% would reduce that to 13.5% by 2017-23.

234 13.5% is reported by NREL as the 

Desert Southwest “reference reserve margin,”235 the planning reserve limit that would 

trigger new generation for reliability purposes. 2017-23 is squarely athwart the proposed 

NGS retrofit dates of 2018-23.236 So it is certainly plausible that retirement of NGS 

would trigger a need for replacement capacity during most or all of the succeeding 20 

years.

NREL has assumed there will be no capital costs of replacement capacity.237 To 

the extent there is, NREL has underestimated the cost of replacing NGS generation if 

NGS is retired.

3. Nonair quality environmental impacts of compliance

Not addressed in these comments.

 

228 NREL, p. 31.

229 NREL, p. 32. 17.2 TWh/year / (2250 Mw x 8766 hours/yr x 1 TWh/1000000Mwh) = .8721 = 87.21%.

230 Ibid. 17.5 TWh/year / (2250 Mw x 8766 hours/yr x 1 TWh/1000000Mwh) = .8873 = 88.73%.

231 NREL, p. 111.

232 NREL, p. 27.

233 Ibid. 27% is after taking into account currently anticipated new plants, and assuming NGS is retired.

234 The number of years for an x%/year growth rate to reduce a 27% reserve margin to a 13.5% reserve 

margin is log(1.27/1.135)/log(1+x/100). For a 2% per year growth rate, that corresponds to 5.7 years, and 

for a 1% per year growth rate that corresponds to 11.3 years. So, from 2011, with rounding up to the 

nearest integer year, reserve margins would shrink to 13.5% by 2017-2023.

235 NREL, p. 27.

236 TSD, p. 10, Table ES-3.

237 NREL, pp. 27, 28.
30

4. Existing pollution control technology

Not addressed in these comments.

5. The remaining useful life of NGS

While the remaining useful life of NGS is one of the key issues flagged in the 

executive summary of the NREL report, the discussion of it in the body of the report is 

less than one page long.238 The key conclusion NREL draws is that, for “larger coal units 

built around the time of Navajo GS,” NREL and others have found “statistical analysis 

points to a normal operating life of 65 to 70 years.”239 Based on an NGS age of 45 years 

in 2019,240 that would correspond to a retirement date of 2039-44, consistent with a 20+ 

year life for BART retrofits. The fact that the NGS owners have been actively involved in 

trying to negotiate a land lease extension with the Navajo tribe to 2044 is further 

evidence that NGS itself, in the opinion of its owners, is physically capable of operating 

into the 2040s.

As NREL points out, installing SCR at NGS would have a very small effect on 

the ongoing annual operating and maintenance cost to operate NGS, adding just $0.68-

$0.96/Mwh to a production cost that was $24.45/Mwh in 2010.

241 Thus, once SCR was 

installed and its capital costs were sunk, the economic benefits of keeping NGS in service 

would be affected very little by the cost of operating and maintaining the SCR units. In 

short, it is reasonable to assume a 20 year remaining life for NGS, whether or not SCR is 

installed.

6. Visibility

Not addressed in these comments.

7. Tribal benefits and impacts

The last of the major focuses of the NREL report, as described in its Executive 

Summary, is tribal benefits and impacts.242 The tribal impact analysis looks at both the 

impacts on the Navajo and Hopi tribes in their roles as suppliers of land, employees, and 

coal to NGS, and water-using tribes who pay for a portion of NGS costs as part of their 

water supply costs.243

 

238 NREL, pp. 112-113.

239 Ibid.

240 NREL, p. 112.

241 NREL, p. 61, Table 4-9. See also NREL, pp. 25 (Table 1-15, showing 2010 production cost of $24.45, 

composed of $17.80/Mwh for fuel and $6.66/Mwh for non-fuel O&M expenses), 47 (Table 3-6, showing 

annual O&M costs of $11.9-$16.71 million) and 32 (annual generation of 17.5 million Mwh). $16.71 

million / 17.5 million Mwh = $0.955/Mwh. $11.9 million / 17.5 million Mwh = $0.68/Mwh.

242 NREL, p. iv. 

243 NREL, p. 5.
31

For the Navajo and Hopi, installing SCR would have no direct impact on them 

compared to the status quo,244 but retiring NGS would have major negative impacts due 

to loss of both NGS and mining jobs, loss of coal leasing revenue, and loss of NGS land 

lease revenue. NREL discusses the context in which these losses would occur,

245 and 

these comments do not further address them.

For the nine246 water using tribes, impacts on them would be a subset of impacts 

on CAP water users in general.247 General CAP water user impacts are discussed in 

Chapter 4 of the NREL report,248 and impacts on specific tribes are discussed in Chapter 

6 of the report. The comments below address both.

a. General CAP water user impacts

i. BOR capital costs for SCR

The Bureau of Reclamation (BOR) owns 24.3% of NGS,249 and is billed by SRP 

(the NGS operator) for that percentage of NGS costs.250 The NREL report assumes that 

the Federal (Bureau of Reclamation) share of SCR costs would not be financed with any 

federal appropriation or financing;251 rather, NREL assumes that CACWD would issue 

20-year bonds and use the proceeds of those bonds to finance the BOR share of SCR 

costs.252 NREL assumes CACWD would have to pay a 5 percent per year interest rate on 

such bonds.253 CACWD has previously issued bonds that were secured by revenues from 

sales of NGS surplus energy.254

The assumption of no federal financing for SCR capital costs is a reasonable 

assumption, but also a worst-case assumption. Any other outcome would reduce the

impacts of SCR on CAP water users. The assumption of a 5% per year cost for CACWD 

bonds may also be too pessimistic. A recent presentation to Arizona water users assumed 

3.2% per year financing with a 25-year term.

255 The lower rate is more consistent with 

current market rates for tax-exempt debt.256 If the BOR share of CAP could be financed 

 

244 Except for possible employment benefits during installation of SCR, and small employment benefits to 

operate SCR once installed.

245 NREL, Chapter 7.

246 NREL, p. 101.

247 NREL, p. 5.

248 NREL, pp. 53-70.

249 NREL, p. 53.

250 NREL, p. 54.

251 NREL, pp. 3-4, 59.

252 NREL, p. 59.

253 Ibid.

254 2017.powerauthority.org/wp-content/uploads/2013/03/CAP.pdf, p. 18 of 20, presentation by Thomas W. 

McCann of Central Arizona Project.

255 Arizona Municipal Water Users Association, 3/6/13, Agenda Item #5, Attachment A, “Central Arizona 

Project Financial and Power Issues” (cited below as “AMWUA”), p. 6. Available online at 

www.amwua.org/pdfs/33_201303_mgmt_item5a.pdf.

256 For example, on 11/27/13, there were ten transactions involving SRP tax-exempt bonds due in January 

2035 (21 years from now), at a weighted average yield average yield of 2.63%. See 

arizona.municipalbonds.com/bonds/issue/79575DUJ7, listings for 11/27/13.
32

with 20-year bonds paying 3.2% per year instead of 5% per year, that would lower 

NREL’s estimate of the capital cost of SCR, for CAP water users, by more than a third.

ii. NGS operating costs before SCR

NREL assumes a Navajo cost of production of $30/Mwh (pp. 55, 58, 60), 

intermediate between higher 2010 costs claimed by CAWCD ($32.27/Mwh; NREL, p. 55, 

fn. 6), and a 2010 cost of $24.45/Mwh from “various federal filings” (NREL, p. 25 and p. 

55, fn. 6). The CAWCD costs may include some Hoover energy257 and/or transmission 

costs – NREL was unable to determine exactly what costs were including in CAWCD 

power payments.258 Disaggregated CAWCD data shows that their actual 2010 NGS cost 

was $31.79/Mwh.259

Looking at later data does not resolve the ambiguity faced by NREL. NGS costs 

are reported by the IOU owners on FERC Form 1, but widely varying NGS operating 

costs were reported by the different owners in 2011 and 2012.

260 On the other hand, an 

Arizona water users report from 2013 gives a 2012 NGS projected operating cost of 

$26.48/Mwh and an actual operating cost of $30.89/Mwh,

261 and CAWCD’s November 

2011 budget for the 2012/13 water year forecasted an NGS pumping energy cost of 

$28.84/Mwh in 2012 and $29.34/Mwh in 2013,

262

Given the discrepancies regarding past costs, let alone future costs, the NREL 

assumption of a $30/Mwh production cost for NGS is reasonable, although (as discussed 

below) NREL’s use of it is not.

iii. Paying for BOR’s share of SCR – implications for 

NGS surplus sales by BOR

NREL assumes CAWCD pays 100% of the BOR share of SCR capital costs,263

but only 28/43 of the BOR share of SCR O&M costs (pp. 60-61).264 This is an apparently 

 

257 See, e.g., NREL, p. 56, Table 4-2, Line B, showing Hoover energy used for CAP pumping.

258 NREL, p. 55, fn. 6.

259 CAWCD, 2012/2013 Biennial Budget, p. 8-7, showing historical data for 2010. Available online at 

www.cap-az.com/index.php/2012-13-budget.

260 FERC Form 1s for NPC, TEP, and APS for 2011 and 2012, showing 2011 “expenses per net kwh” of 

$27.80/Mwh (NPC), $28.60/Mwh (TEP), or $28.70/Mwh (APS) and showing 2012 “expenses per net kwh” 

of $29.20/Mwh (NPC), $31.70/Mwh (TEP), or $34.30/Mwh (APS). To make matters worse, the “expenses 

per net kwh” reported by the NGS owners do not match the ratio of “total production expenses” to “net 

generation, exclusive of plant use” for those same owners. See Table 8, columns 4 and 5.

261 AMWUA, p. 1.

262 CAWCD, 2012/2013 Biennial Budget, p. 8-7, available online at www.cap-az.com/index.php/2012-13-

budget.

263 NREL, p. 60: “Annual capitalized costs of BART controls would be applied to CAP pumping power 

only.” See also NREL, p. 22, re BOR’s share of SCR capital costs: “In the absence of guidance otherwise, 

this analysis assumes that all of the federal share would be passed on to CAWCD for recovery from CAP 

rates.”

264 NREL, p. 60 (“Variable production costs would be applied to pumping power and excess power”). 

NREL expects annual pumping power requirements of 2.8 Twh per year (NREL, p. 60) and annual excess 
33

strange but ultimately plausible expectation. It results from the fact that 100 percent of 

the capital costs have to be paid by someone, and there is no way to collect those costs 

with any certainty from market-priced sales of excess power. So NREL assumes 

CAWCD pays all of the BOR share of SCR capital costs. On the other hand, operating 

costs are largely variable,265 so it is reasonable to assume that BOR could charge them to 

CAWCD and excess power customers in proportion to the energy usage.

NREL ends up assuming that CACWD will use 16% of NGS generation266 but 

pay 24.3% of NGS SCR capital costs.267 As a result, the impact of SCR on the cost of 

BOR surplus NGS energy is only $0.68-$0.96/Mwh,268 which greatly reduces the impact 

of SCR on CAWCD credits from NGS surplus sales. NREL assumes those impacts won’t 

exist at all because surplus energy won’t be sold,269 because its cost will exceed the 

market price it could command. But NREL is wrong in a couple of ways. First, even if it 

were true on average, it would be false for many hours per year. More importantly, 

average O&M cost is different than marginal cost, because of fixed O&M. NREL itself 

says the marginal cost of NGS is barely $20/Mwh,270 leading it to operate “as often as 

possible.”

271 SCR won’t change that. Even with NREL’s assumed market price of 

$27.25/Mwh, NGS’s variable cost would be lower than that, and surplus sales would still 

be made.272 So NREL’s assumed $0 impact of SCR on NGS surplus sale net revenue273 is 

wrong. 

However, the dollar impact of NREL’s error is small. NREL says expected 

surplus sales (beyond those already made to SRP at a fixed price of $25 million per year 

above cost) will be 1.280 million MWh per year.274 The O&M cost of SCR will be $0.68-

0.96/Mwh.275 The capital cost impact of SCR on surplus sales will be zero because of the 

 

power generation of 1.5 Twh per year (NREL, p. 61, Table 4-7), for a total BOR share of NGS generation 

of 4.3 Twh per year.

265 In 2010, for example, almost 3⁄4 of NGS operational costs were fuel costs, which were variable, and 

some proportion of the other 1⁄4 were variable O&M (the rest was fixed O&M). See NREL, p. 25, Table 1-

15.

266 NREL, p. 60 (CAWCD uses 2.8 TWh for pumping energy) and p. 33, Table 2-1 (17.5 TWh per year 

total NGS production). 2.8/17.5 = 0.16 = 16 percent.

267 NREL, p. 59

268 NREL, p. 61, Table 4-9.

269 NREL, p. 60 (text) and p. 61, Table 4-8, showing $0 impact from sales of NGS surplus other than under 

the existing long-term SRP contract.

270 NREL, p. 31, text and Figure 2-3.

271 NREL, p. 31.

272 Assume (as NREL does) that the market price is $27.25/Mwh and the total production cost of NGS is 

$30/Mwh. Further assume, consistent with data presented by NREL (p.25, Table 1-14), that variable costs 

make up 80% of production costs and fixed O&M costs make up the other 20 percent. NREL argues that 

$30 is bigger than $27.25, and so surplus sales would not be made. But if surplus sales are not made, BOR 

would receive no revenue to cover its fixed O&M costs of $6/Mwh (20% of $30/Mwh), and would thus 

incur a loss of $6/Mwh from its surplus sales program. It would be better off to make surplus sales at 

$27.25, incurring a loss of $2.75 per Mwh. Sales at $27.25/Mwh would cover all of its variable operating 

costs ($24/Mwh, 80% of $30/Mwh) and part (3.25/6) of its fixed costs. Only if the market price were below 

$24/Mwh would NREL’s logic be valid, and BOR be better off ceasing surplus sales.

273 NREL, p. 62.

274 NREL, pp. 55, 57, and p. 61, Table 4-7.

275 NREL, p. 61, Table 4-9.
34

assumption described above, that CAWCD pays 100% of SCR-related capital costs. Thus 

the decreased revenues from NGS surplus sales will be just $0.87 - $1.23 million per 

year.276

NREL calculates CAWCD impacts of SCR in the $11-13.3 million per year 

range.277 Adding $0.87-1.23 million to those impacts due to decreased surplus sales net 

revenue increases them, but only slightly. M&I water users whose rates contribute to 

CAWCD $55 million annual CAP repayment operation would have to pay the extra 

$0.87-1.23 million. Those users get 0.86 million acre-feet of CAWCD water per year.278

So the impact on them would be $1.01 - 1.43/acre-foot,279 as compared to CAWCD’s 

expected 2016 M&I rates of $141-167/af in 2016.280 For agricultural water users, the 

impact would be zero, since they already don’t pay anything towards the $55 million cost 

that NGS surplus sales partially defray.

iv. Bottom line impacts on CAWCD of alternatives

NREL’s bottom-line conclusions are that SCR would increase CAWCD annual 

costs by $11.0-13.3 million, consisting of $9.1-10.6 million for 100% of the BOR share 

of SCR capital costs plus $1.9-$2.7 million for a 2800 gwh share of SCR operating 

costs.281 The range of costs involves combining the high capital cost from one source 

(NPS) and the high operating cost from another (S&L) to get the high end of the range, 

and vice-versa for the low end of the range. Without NREL’s mixing and matching of 

data sources, its range of total SCR costs would have been $11.7-12.5 million per year.

NREL’s numbers need to be increased by $0.9 - $1.2 million per year to account 

for the reduced profits from NGS surplus sales (other than to SRP)282 by BOR, and the 

corresponding reduction in the annual credit to CAWCD for surplus sales profits.283 So 

the overall impact of SCR on CAWCD would be a cost increase of $11.9-$14.5 million. 

This would be spread across annual CAP deliveries of 1.535 million acre-feet (maf),284

 

276 $0.68/Mwh x 1.28 TWh x 1 million Mwh/Twh = $0.8704 million; $0.96/Mwh x 1.28 TWh x 1 million 

Mwh/Twh = $1.2288 million.

277 NREL, p. 62, Table 4-10.

278 NREL, p. 67, Table 4-20 (using 2011 data).

279 $0.87 million / .86 million acre-feet = $1.01/acre-foot; $1.23 million / 0.86 million acre-feet = 

$1.43/acre-foot.

280 NREL, p. 59, Table 4-6.

281 NREL, p. 61, Table 4-9. Note that Table 4-9 shows a total BOR share of NGS generation of 4250 gwh 

per year, which implies surplus sales of 1450 gwh after subtracting CAP pumping load of 2800 gwh per 

year. This contradicts the 1500 gwh per year of surplus sales reported by NREL on p. 53 and p. 54 (fn. 4), 

discussed on p. 55, an shown in Table 4-9 on p. 61. The 50 gwh/year discrepancy does not affect the results 

of Table 4-9, since it is within rounding error for the results shown.

282 Because the SRP sale is a cost-plus-fixed-margin sale, the increase in NGS costs due to SCR O&M 

($0.68-$0.96/Mwh x 220,000 Mw, or $0.1-$0.2 million per year) would be paid by SRP, and would not 

effect net revenue to BOR or the credit to CAWCD for net surplus sale profits.

283 See the previous section of these comments for the basis for, and calculation of, the $0.9-$1.2 million 

per year figure.

284 1.55 MAF/year in 2011 per NREL, p. 62, Table 4-10, p. 65, Table 4-15, and p. 67, Table 4-20. 

However, the multi-year average is 1 percent lower, or 1.535 MAF/year, per annual data for 1999-2012, 

inclusive, at http://www.cap-az.com/index.php/departments/water-operations/deliveries.
35

resulting in an average cost increase of $7.75 - $9.45 per acre-foot (af),285 slightly higher 

than the $7.10-$8.58/af reported by NREL.286

Alternatively, if NGS were to be retired and CAP pumping energy replaced from 

market sources, NREL projects that CAWCD annual costs would increase by $31.8-

$79.5 million,287 which when spread across 1.535 maf/year288 corresponds to an average 

increase in CAWCD costs of $20.72-$51.79/af. The actual impact on CAWCD would be 

even greater, because NREL assumed no foregone revenues from surplus sales if NGS 

were shut down. But in reality, as discussed above, market prices of $32.44-

49.48/Mwh,289 even if adjusted down slightly to account for a greater proportion of offpeak generation,290 would still be far above an NGS variable production cost of no more 

than $24.45/Mwh.291 That means there would be NGS surplus sales if NGS remained in 

surplus, and hence lost revenue from those sales if NGS were retired.

The bottom line is that, for CAWCD as a whole, paying for SCR at NGS would 

be far less expensive than retiring NGS and finding a new source of CAP pumping 

energy and CAP repayment revenue.

b. Impacts on Indian (and other) end-users of CAP water

i. Dollar per af impacts

The discussion of CAWCD costs in the previous section was for CAWCD as a 

whole. However, CAWCD has a pricing structure under which different customers can 

pay widely varying amounts per af of water. In particular, the effects of changes in NGS 

surplus sales revenue are borne entirely by municipal and industrial (M&I) customers, 

and not at all by Indian and agricultural customers.

NREL’s summary table shows costs, in dollars per af, for different CAWCD 

customer classes under different scenarios.292 NREL expects increases from the base case 

due to SCR of $7-9/af for all customers, and increases from the base case if NGS is shut 

down of $33-64/af for M&I customers but $4-35/af for Indian and agricultural 

customers.293

 

285 $11.9 million/1.535 maf = $7.75/af; $14.5 million/1.535 maf = $9.45/af.

286 NREL, p. 62, Table 4-10.

287 NREL, p. 67, Tables 4-19 ($6.8-$54.5 million increase in cost for CAP pumping energy, based on 

changing from NGS at $30/Mwh to market-priced purchases) and 4-20 (foregone CAWCD revenue of $25 

million from terminated SRP contract with BOR for surplus NGS energy).

288 See previous paragraph. 1.535 maf/year is the 1999-2012 average CAP delivery, per http://www.capaz.com/index.php/departments/water-operations/deliveries.

289 NREL, p. 67, Table 4-19.

290 As discussed above (fn. 189), NGS total generation is 44.3% off-peak, but surplus generation sales 

(other than those to SRP) are 51.9% off-peak (not the 89% erroneously reported by NREL).

291 $24.45/Mwh is the 2010 NGS operating cost including fixed O&M (NREL, p. 25, Table 1-15). 

Elsewhere, NREL suggests the BOR’s variable operating cost for NGS would be “around $20/Mwh” 

(NREL, p. 41).

292 NREL, p. 69, Table 4-24.

293 Ibid.
36

Based on the comments above, NREL’s M&I cost increase estimates for the SCR 

case are too low by about $1/af ,

294 and their M&I cost increase estimates for the NGS 

retirement scenario are low by more than that, at least in the high power price scenario.295 

The NREL cost increase estimates for Indian and agricultural users are consistent with 

NREL’s data sources for SCR costs and NREL’s modeling of WECC redispatch if NGS 

were retired.

For Indian and agricultural water users, the NREL results suggest that a worst 

case result will be a water price increase of no more than $9/Mwh, the high end of the 

cost range for SCR. If market prices are high, then the owners of NGS will not want to 

shut it down, because NGS (even with SCR) will be much cheaper than market-priced 

generation. For example, NREL calculates that installing high-cost SCR would add $70 

million per year to the total cost of NGS,296 which corresponds to just under $4/Mwh.297

If the base NGS operating cost is $30/Mwh, that means SCR is economically preferable 

to NGS retirement as long as the cost of replacement energy is under $34/Mwh. But the 

only scenario in which the LMP’s for any of the NGS owners are under $34/Mwh are 

when natural gas prices are close to $4/MMBtu, the very bottom of NREL’s gas price 

range.

298 So realistically, a low gas price scenario is the only scenario where an NGS 

shutdown is even vaguely credible. But in that scenario, there would also be low market 

prices for purchased CAP pumping energy to replace NGS, and Indian and agricultural 

water users would actually benefit compared to SCR. NREL shows that with gas prices at 

$4/MMBtu, its low power price case, Indian and agricultural users of CAP water would 

pay only $4/af above the base case, even less than with SCR.

299

An increase in water costs of $4/af (low gas prices, NGS retired) or $7-9/af 

(moderately low or higher gas prices, SCR installed at NGS) over current prices would 

leave Indian and agricultural water users paying only one-third to one-half of what M&I 

water users are already paying.300 It would be comparable to the increases that 

agricultural customers have already experienced in 2013 ($4/af), will provisionally 

experience in 2014 ($6/af), and have been advised to expect in 2015 ($7/af).301

 

294 See section IV.B.7.a.iii, above.

295 See section IV.B.7.a.iv, above.

296 NREL, p. 111. $70 million is a rounded off number. The actual NREL number, per data on NREL pp. 

19, 47, and 61, is $69.65 million. See Table 2, column 2, sum of lines 6 and 7.

297 $69.65 million/year / 17.5 million MWh/year = $3.98/Mwh.

298 NREL, p. 42, Table 2-7, showing LMPs after NGS retirement of $32.44-$33.75/Mwh.

299 NREL, p. 69, Table 4-24.

300 CACWD, “Approved 2013-2018 CAWCD Final Water Rate Schedule.pdf,” p. 1, showing the CAP’s 

“Final 2013-2018 Rate Schedule,” approved 6/7/12, downloaded 7/24/13 from www.cap-az.com. 2013 

agricultural rates shown as $53/af (the same as NREL, p. 69, Table 4-26), 2013 M&I rates range from 

$129-168/af ($1-7/af higher than shown in NREL, p. 69, Table 4-24). ($53+$9)/$129 = .481 = 48.1%. ($53 

+ $4)/$168 = .339 = 33.9%.

301 Ibid.
37

ii. Percentage increases

The NREL analysis indicates that rate increases under various scenarios will be 

higher for Indian and agricultural customers in every scenario except for the one in which 

natural gas prices are $4/MMBtu and NGS is retired.302 However, this result is a 

misleading mathematical artifact of the fact that those users pay less than everyone else to 

start with. Because their current rates are so low, even small nominal increases appear 

large in percentage terms. But real water users pay for water in dollars, not percentages. 

And agricultural and Indian water users will still pay less than M&I water users, by a lot, 

after installation of SCR at NGS.

iii. Affordability of water rate increases

The biggest single allocation of CAP water is the 311,800 af/year entitlement of 

the Gila River Indian Community (GRIC).303 This is less than half of the total GRIC 

water budget of 653,500 af/year,304 meaning that a $7-9/af increase in CAP water costs 

would increase average GRIC water costs by approximately $3.30-$4.30/af.305 An 

increase in CAP water costs of $7-9/af would cost the GRIC $2.2-2.8 million per year, if 

it were fully using its entitlement.

For comparison, the GRIC received $36.2 million in Federal funding in 2009 to 

subsidize construction of various portions of the Pima-Maricopa Irrigation Project (PMIP) to allow GRIC to use its CAP allocation for irrigation purposes,

306 and had 

previously spent $117 million in 1998-2004 to construct the initial portions of the PMIP.307 The ultimate investment is expected to be $645 million.308 The GRIC intends to 

eventually use its CAP water in large part for the Pima-Maricopa Irrigation Project, 

which is intended to irrigate up to 146,330 acres of land.309 An increased CAP water cost 

of $2.2-2.8 million per year would thus correspond to less than $2 per year per acre of PMIP land. Since farming margins are currently above $113 per acre,310 an additional cost 

of under $2 per acre would reduce margins by less than 2%.

According to NREL, GRIC estimates that SCR at NGS would “reduce the tribe’s 

net farm income by 2% in 2015, and by 3.3% in 2020.”311 The GRIC estimates are 

consistent with the data in the previous paragraph, which indicate that the GRIC share of 

SCR costs, while a significant number of dollars, would be considerably less than has 

already been spent on P-MIP.

 

302 NREL, p. 70, Table 4-25.

303 NREL, p. 103.

304 http://www.justice.gov/enrd/4533.htm.

305 $7/af x 311,800 af / 653,500 af = $3.34/af; $9/af x 311,800 af / 653,500 af = $4.29/af.

306 http://www.recovery.gov/Transparency/RecoveryData/pages/RecipientProjectSummary508.aspx?

AwardIdSur=38728.

307 http://www.gilariver.com/lessons/Water%20Settlement%20Chapter%207.pdf, p. 5.

308 NREL, p. 103.

309 http://www.gilariver.com/status.htm.

310 NREL, p. 103.

311 NREL, p. 102.
38

For all other tribes besides the GRIC, NREL reports that their combined 

allocation of CAP water is less than that of the GRIC, or about 262,000 af/year.312 Of this, 

a substantial portion (over 78,000 af/year) has been leased to various cities or 

companies.

313 Assuming the lease payments would increase in line with any NGS cost 

increases,

314 these tribes would not be financially affected by increases in CAP delivery 

costs for the water they have leased to others. Thus, there may be as little as 184,000 

af/year of non-GRIC Indian water for which tribes themselves are at risk of paying 

increased costs due to SCR. At $7-$9/af, the potential cost to these tribes would be $1.3-

$1.6 million per year. Whether that amount is significant from the point of view of the 

concerned tribes is unclear,315 but it is certainly small compared to the roughly $500 

million capital cost of SCR.

iv. The “second cascade” issue

A final issue discussed in the NREL report is the “second cascade” issue. When 

and if net profits from sales of NGS surplus energy exceed CACWD’s repayment 

obligation to the Federal government, which is about $55 million per year, surplus sales 

profits above that $55 million level would flow to a “second cascade” of recipients, 

including Indian tribes.

316

Currently, surplus sales are guaranteed to produce $25 million per year of profits 

under a long-term contract with SRP.317 To produce a further $30 million in year in 

surplus sales profits, so that the total exceeded $55 million per year, would require

market prices for surplus energy to exceed NGS operating costs by more than 

$23/Mwh.318 With NGS operating costs of about $30/Mwh before adding SCR, that 

means market prices would have to exceed $53/Mwh. NREL has calculated that, even 

with gas prices of $6.90/MMBtu, market prices will still be below $48/Mwh in 

Arizona.319 Thus it is very unlikely that there would be any “second cascade” revenues 

even with no SCR, and so SCR will not affect “second cascade” revenues.”

 

312 NREL, pp. 102-104.

313 NREL, pp. 102 (Ft. McDowell Yavapai Nation leases 4300 af/year to Phoenix at full cost; Ak-Chin 

Indian Community leases 10,000 af/year to Del Webb Corporation), 103 (SRPMIC leases 100% of its 

13,300 af/year allocation to Phoenix-area cities at full cost; the San Carlos Apache Tribe leases 26,500 

af/year to Scottsdale and Phelps Dodge), and 104 (Yavapai-Prescott Indian Tribe has assigned 500 af/year 

to Scottsdale; the White Mountain Apache Indian Tribe has leased 100% of its 23,782 af/year of CAP 

water).

314 Ibid. For some leases, NREL specifies that the lease is at full cost, while for others it does not address 

lease terms.

315 NREL, p. 113: “determining the threshold at which a [tribal] rate increase would be materially 

significant would require a legal analysis that was beyond the scope of this study.”

316 NREL, p. 113.

317 NREL, p. 55 and fn. 5.

318 NREL, p. 55 and p. 61, Table 4-7 (remaining NGS surplus sales after the SRP sale will be 1.28 million 

Mwh per year). To make a profit of $30 million on sales 1.28 million Mwh requires a profit margin of $30 

million / 1.28 million Mwh = $23.44/Mwh.

319 NREL, p. 40, Table 2-6, LMPs with NGS in service, values for APS, SRP, and TEP.
39

Conversely, in the unlikely case that there would be “second cascade” revenues 

without SCR, then the $0.9-$1.2 million SCR-related cost which was calculated above as 

being incurred by M&I customers320 would instead be incurred by Indian tribes. But in 

that case, by assumption, CAWCD would be getting its entire $55 million annual 

repayment obligation to the Federal government paid by NGS surplus sales, as opposed 

to the situation in 2009-10 when NGS surplus sales resulted in net revenue of only $24-

34 million.321 So CAWCD would be better off, even with SCR, than it was just a few 

years ago,322 and there is no doubt that SCR would be economically affordable for 

CAWCD.

8. Other minor comments on the NREL report

a. SRP depreciation

The potential adjustment to the SRP depreciation schedule referenced by NREL323

in fact occurred in 2012.324

b. Maintenance at NGS and EPA Alternatives 1-3

The maintenance cycle discussion in the NREL report325 indicates that the NGS 

units are on a six-year maintenance cycle, with each unit getting major maintenance 

every six years, and the last major maintenances done in 2009, 2010, and 2011, 

respectively, for the three units. The NREL report implies that the next major 

maintenance years for the three NGS units will be 2015-17, followed by 2021-23. That 

schedule is consistent with the conclusion above326 that, if EPA were going to adopt a 

deferral scenario, it should be the EPA-proposed Alternative 1 with SCR operation 

deferred to 2021-2-3.

c. The SRP discount rate of 9.8% per year is too high.

NREL assumes that cost recovery for SRP’s share of SCR installation at NGS 

would be paid over a 20 year period, based on a 9.8% per year discount rate.327 As NREl 

itself acknowledges, this rate does not reflect SRP’s actual cost of capital, but instead 

“includes a risk premium.”328 Including such a risk premium is inappropriate in 

 

320 See section IV.B.7.a.iii.

321 NREL, p. 55, Table 4-1.

322 $21-$31 million per year of extra revenues to CAWCD from NGS surplus sales (as compared to 2009-

10), due to high market prices, would more than offset the $11-13.3 million year extra cost to CAWCD 

(NREL, p. 62, Table 4-10) for SCR.

323 NREL, p. 21.

324 SRP, 2012 Annual Report.

325 NREL, p. 24.

326 See section III.F.2.

327 NREL, p. 19, Table 1-10.

328 Ibid., note (a).
40

determining the actual amount that customers would pay. The TSD, appropriately, does 

not include a risk premium.329

d. Non-Indian agricultural water users

For non-Indian agricultural water users, NREL doesn’t discuss the fact that NIA 

users rights to CAP water shrink over time, by 25% from current levels in 2017 and to 

zero by 2031.

330 So any impacts on them will be for a shorter term than impacts on other

water users, especially if the start of SCR is deferred into the 2020s.

 

329 TSD, p. 43, Table 12, reducing the SRP interest rate from 9.8% per year to 7% per year, consistent with 

the EPA’s Cost Control Manual (CCM).

330 Arizona Municipal Water Users Association, 4/19/13, Agenda Item #5, Attachment B, “Summary of the 

CAP Agricultural Water Incentive Pricing Program,” p. 1. Available online at 

www.amwua.org/pdfs/40_201305_mgmt_item5b.pdf. See also ES, p. 77.