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, 20132

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 alterna tive 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, 1 as well as a study done by the National Renewable Energy Laboratory (NREL) 2 for the Department of the Interior (DOI), 3 these comments address

tho se two studies in detail.

II. SUMMARY OF C ONCLUSIONS

EPA is correct to conclude in its Factor 2 analysis that th e 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 c orrect 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 NO X control retrofits at issue here, in
which c ase 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 li fe.

The ES study of NGS economics contains a major error regarding depreciation, and a series of other errors or assumptions which lead it to gener ally 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 cost

competitiveness 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 NO X retrofits would make NGS uncompetitive from the point of view of its owners . The analysis that NREL does do shows that NGS with NO X retrofits is pref erable 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,

p repared 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 impact s of NGS, compared to the no

- de ferral alternative. Among the deferral alternatives, the EPA

- proposed deferral with NO X control

retro fits in 2021

- 23 would be the best on both technical grounds and pollution control grounds.

III. EPA A NALYSIS IN TECHNICAL SUPPORT DOCUMENT (TS D)

A. Factor 1

— C ost s of C ompliance 4

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 NO X 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

T he TSD concludes that SCR would cost $58.8 million per year to achieve a NO X 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 e xperts. 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. 7 It 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 Q uality E nvironmental I mpacts” 9

As part of its Factor 2 analysis, the TSD includes a n “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 an nual 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 calc ulates 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 “N REL”). 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 hig h 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 co st 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 bel ow 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 tr igger 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 er rors 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 CO 2 pricing impacts. However, the EPA was correct to not adjust its affordability analysis for potential future CO 2 charges. Current CO 2 prices

–

zero for NGS owners outside of California

– will have no effect on the economics of adding SCR to NGS. Sufficien tly high CO 2 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 CO 2 prices would cause the economics of retaining vs. retiring NGS to be
different with and without SCR. Th ere is no reason to believe future CO 2 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 CO 2 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. Th e 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 CO 2 , 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 i ts units, to be retired.

16 Indeed, even if some current NGS owners expect future CO 2 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 will ing 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 unit s under non

IOU owne rship 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

, sinc e the new owners would not face income tax consequences associated with earning profits on SCR

.

C. Factor 3

— Existing Controls

— No I ssues

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 L ife

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 N GS 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

- ye ar 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 pr ices 20 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 insta lled, 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 leas e. 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

- 141.6

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 A nalyzed

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 A lternative

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 year s. 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 NO X 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

t ons 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

Alt ernative 1 is “better than BART” ignores the plain fact that Alternative 1 would have emissions 71,930 tons greater tha n BART. 28

T he 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 a n 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 def erred 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 2023.7

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 propos ed deferral is

the most reasonable of the set of deferra l options identified in the TSD, from both an emissions point of view an d an engineering point of view.

From an emissions point of view, Alternative 1 would result in emissio ns lower than either Alternative 2 or Alternative 3. Compared to Alternative 2, Alternative 1
would have lower lifetime NO X emissions by almost 36,000 tons. 33 Even if Alternative 2 included EPA’s proposed short

- term or long

- term “emissions bridge” to offse t an additional 15,179 tons of NO X 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 NO X emissions by almost 54,000 tons. 36 Even if Alternative 2 incl uded EPA’s proposed short

term or long

- term “emissions bridge” to offset an additional 33,160 tons of NO X 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 co ordinating 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

- 2 2

- 2 3. 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 retro fits (2024

- 25

- 26) 40 wou ld 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) minu s 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 48.8

IV. M AJOR S TUDIE S RELIED U PON BY EPA

A. Energy Strategies (ES) A nalysis

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 anal ysis 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 wit h 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 $6 03 million. 44 Thus, while the ES

st udy says the Low Market case would cost $25 million more than an SCR case, correcting the ES study raises the difference between the Low Marke t and SCR cases to at least $6 28 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 avoidabl e. 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 sh areholders) 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. E S 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 plan t 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 theoreticall y absorb undepreciated investment costs. The publicly

owned 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 s cenario.

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 depreciatio n 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 re maining undepreciated NGS rateba s e 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 f urther 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, col umn 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 its10

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, alth ough 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

siz e of the ES depreciat ion 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 pl ant in service, and construction work in progress (which would have to be deprec i ated 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 de preciation 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 l ow 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 w hether 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 S CR 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 Ma rket 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 r esult is that

the near overlap that ES projects between the cost of the SCR c ase and the cost of the

Low M arket cost case isn’t really there.

i. Low case forecast starting point

ES T able s E

- 3 and 6 shows SCR only $25 million better (in NPV terms) than an
NGS retirement scenarios with “L ow Market” replaceme nt 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 $ 3 1.97 /Mwh. 59 For the same twelve months

, average Henry Hub natural gas prices were $3. 516 /MM Btu, 60 for an implicit heat rate of 9, 093 Btu/kwh. 61 Current Henry Hub forward prices for 2016 are $4. 143 /M MBtu

, 62 which at the same implicit heat rate would correspond to a price of $ 3 7.672 /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

L ow Market case are reasonable

.

ii. Low case esca lation ignores the effect of retiring

NGS

T he 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, whi le not quantified by ES , could be qui te 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 2 016 Henry Hub

57 ES, pp. 7, 24.

58 ES, pp. 2 7 (“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 th at 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 B tu/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 price s 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

3.7 6 %, 67 which would increase ES’s $40 .16 /Mwh forecast by $1.5 1 /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 Admi nistration (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 o f 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 colu mn 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 $13 5. 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. 1 3 million (0

. 1 %) of the $135.5 mi llion 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 $843 9 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 be13

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 rat e s 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, i ncluding 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 1 40% in nominal terms
from 2016 t o 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 sto ps 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.

U nder all the Market case s , 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 T hus, 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 h ave extended to the y ear 2038 for the third unit.

v. Partially q uantifying 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 ini tial 2016 market price assumption would increase the NPV of the market option (through 2036) by $13 5. 5
million. 88 But correcting the ES analysis to accoun t 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 $2 83 million. 91 That would in turn cause a more

- than

- twelve

- fold increase in the advantage of SCR over NGS reti rement, 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 q uantify th e 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 DC F” 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 impli ed 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 p rojects “ high ” case market prices that are at most 1 3 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 cas e

. 95 ES admits t hat 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, histori cal 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 $13 80 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 fr om 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 a ccount 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. Discoun ting 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 milli on. 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. 1380/36 7 = 3.76.16 Notwithstanding the above discussion, t he 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 Mar ket 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 t wo 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 i nflation, 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 $ 4 6

- 10 7 million, 106 while not affecting the cost of the Market cases. Thus, these five
issues would co llectively move the economic comparison between the SCR case and the Market cases an additional $ 4 6

- 10 7 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 poll ution 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 i nvestor

- 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 public ly

- owned utility, the investor

owned 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. 2 5.

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 impa ct of SCR on the cost of those 2800 gwh has been accounted for in the ES study. 114 Of the remaining 1319 gwh, 2 2 0 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 fo r those 220 gwh. 116 For the other 109 9 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 take n acc ount 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 share 119 of the increased BOR cost for its 24.3 perc ent 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 sur plus 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 (differe nce 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 milli on per year, starting in 2020. 125 This is disproportionately high when compared to the lease payment increase at Four Corners, of $7 million 126 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 es timates 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/st ations/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 to nnage 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 cas e 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 re duction in the NPV cost
of SCR.

More importantly, EPA has accepted an SRP projection that the c ost 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 infl ation 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 201 7

, and $53.73/Mwh in 2018. These are much higher than the market prices ES uses everywhere else in its analys is. ES
forecasts 201 6

- 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 ene rgy 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 $ 1.5 94 million in 2016, 144 $ 1.785 million in 2017, 145 and $ 1.982 million in

2018. 146 The NPV of t hat 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 Ibi d.

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 ($52.1 7/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 Incre m 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 TIPS 149 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 inves tors 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 expectatio ns, 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 t ime period, 2.31 % per year highe r for a 20

- ye ar 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 ana lysis) will average between 2 .29 and 2.31 % per

year.

The e ffect 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 low er 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 ef fect 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 S tudy

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 Infla tion 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

- chart

center/interest

- rates/Pages/TextView.aspx?data=yield and http://www.treasury.gov/resource

- center/data

chart

- center/interest

- rates/Pages/TextView.aspx?data= real yield

. 151 See the discussion ab ove 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 pollutio n 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 discussio n 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 a nd 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 i s admittedly not cost

- based, 163 it is not representative of the normal investor

owned 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 fo rth 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 cal culated 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 overstat ed 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 charg es 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

rec overy 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

- own ed 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 doe s 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 mil lion 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 clos er 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 CO 2 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 becau se 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 re al 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

ope rate i t. The NREL authors write that “ T he 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 NRE L, 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

sta te 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 c lose 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 q uestion of future mark et prices, except for CAP replacement energy if NGS is retired. It s 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 price s (LMP).

F or 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 NG S 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 mitiga te 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 no t 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. T he 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 C alifornia 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 gen eration 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 impl y for the individual NGS owners other th an 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 it 184 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 a nnual 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 (cont rary 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

NR EL.25

power for CA P 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 tha t explanation is faulty. First, NREL has greatly overstated the percentage of NGS surplus generation sales that would be off

- peak. 192 Thus, on

- peak/off

peak 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 be tween $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 producti on, 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 NG S. 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/Mwh 198 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, an d 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 N GS 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

- a rea 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 202 2 (when the forward price is $ 4.866 /MMBtu), 202 but the $4

- $5 range is consistent with current prices ($ 3.9 8 /MMBtu rising to $ 4.4 1 /MMBtu in 2014

- 19 )

. 203 Given historical spikes, 204 NREL’s range of prices up to $13/MMBtu is reasonable , and its sensitivity studies a t $4

- 5/MMbtu are reasonable as expectations of what is likeliest to happen in the near future.

c. In flation

— 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 analys is. But ignoring inflation comes with a cost. T o the extent future prices for some key inputs (e.g., market prices, gas prices, CO 2 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 analy sis 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, mu ch 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 woul d 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 shutdo wn, 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 assumption s.
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 a n approx imate incremental cost to replace NGS for the NGS owners (other than BOR) only can be calculated from NREL’s

data

.

T hat 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 r etaining 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 million 212 (equivalent to $1.7

billion on a full

- plant basis)

. 213 That number implies that opera tin g NGS is cheaper than

shut ting it down by $1.7 billion on an NPV basis as of the time of sale (or else no one would pay to buy N GS )

. $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 above 215 ).

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 specif ic 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 c alculated results range from $4. 6 0/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. 6 0/MMBtu is below Henry Hub futures prices for all years
after 201 7

, 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 l ess 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 a t 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 pric ed 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 rem oves 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 depr eciation 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 depreciat ion. 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 annua l 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 i s 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 sprea d 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 th an 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 i f 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 “ev entually

. ” 232 But with a reported Desert Southwest regional reserve margin of 27% in 2011, 233 load growth

of 1

- 2% would reduce that to 1 3.5% by 2017

- 23

. 234 1 3. 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 d uring 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 NG S 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 plant s, 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 g rowth 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. Existi ng 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 sum mary 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 i n 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 s mall effect on the ongoing annual operating and maintenance cost to operate NGS, adding just $0.68

- $0.96 /Mwh to a production cost that wa s $24.45 /Mwh in 2010

. 241 Thus, once SCR was installed and its capital costs were sunk, the economic benefits of keeping N GS 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. Visibilit y

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 (an nual 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 Na vajo 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. NRE L discu sses the context in which these losses would occur

, 245 and

these comments do not further address them.

For the nine 246 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 N GS, 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 tha t 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 rev enues from sales of NGS surplus energy. 254

Th e 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 ben efits 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 a verage 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 (p p . 55 , 58, 60 )

, intermediate between higher 2010 costs claimed by CAWCD ($32.27/Mwh; NREL, p. 55

, fn. 6 )

, and a 2010 cost of $2 4.4 5/Mwh from “various federal filings” (NREL, p. 2 5 and p. 55, fn. 6 ). The CAWCD costs may include some Hoover energy 257 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 do es 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 a n 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 sal es by BOR

NREL assumes CA WC D 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 Bud get, 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 mak e 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 a pplied to pumping power and excess power”). NREL expects annual pumping power requirements of 2.8 Twh per year (NREL, p. 60) and annual excess33

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 a re 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 us e 16% of NGS generation 266 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 CA WC D 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 . B ut 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 c ost, 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 revenue 273 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 pr ice 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 pum ping 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 ex isting 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, Tab le 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 reve nue 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 al l 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 de creased 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 m illion 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 $1 1.0

- 13.3 million, consisting of $9.1

- 10.6 million for 100% of the BOR sha re 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 wo uld be spread across annual CAP deliveries of 1.5 3 5 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 da ta).

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 CAW C D annual costs would increase by $31.8

- $79.5 million, 287 which when spread across 1.535 maf/year 288 corresponds to an average increase in CAWCD costs of $20.72

- $51.79/af. The actual im pact on CAWCD would be even greater, because NREL assumed no foregone revenues from surplus sales if NGS were shut down. But in reality, as di scussed above, market prices of $32.44

- 49.48/Mwh, 289 even if adjusted down slightly to account for a greater proport ion of off

peak 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 t hose 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 imp acts

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 surplu s sales revenue are borne entirely by municipal and industrial (M&I) customers, and not at all by Indi an and agricultural customers.

NREL’s summary table shows costs, in dollars per af, for different CAWCD

customer classes under different scenarios. 292 NRE L expects increase s 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 paragr aph. 1.535 maf/year is the 1999

- 2012 average CAP delivery, per http://www.cap

az.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 Ind ian 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 cal culates 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 c ost 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 pric e 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

misl eading 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 p ercentages. 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 GR I C water costs by approximately $3.30

- $4.30/af. 305 A n increase in CAP water costs of $7

- 9/af would cost the GRIC $2.2

- 2.8 million per year, if
it we re 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

- Mar icopa Irrigation Project (P

MIP) 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 P

MIP. 307 The ultimate investment is expected to be $645 million. 308 The GRIC intends to eventually use its C AP water in large part for the P ima

- Mar icopa 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 P

MIP 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 f arm 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 26 2 ,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 poin t 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 profit s 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 tribe s. 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. 1 02 (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 Carl os 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 s ome 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 wa s 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 req uires 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 inc u rred by M&I customers 320 would instead be incurred by Indian tribes. But in that case, by assumption, CAWCD would be get ting 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 w ith 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 p otential adjustment to the SRP depreciation schedule referenced by NREL 323

in fact occurred in 2012. 324

b. Maintenance at NGS and EPA Alternatives 1

- 3

The m aintenance cycle discussion in the NREL report 325 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 n ext major maintenance years for the three NGS units will be 2015

- 17, followed by 2021

- 23. That

schedule is consistent with the conclusion above 326 that, if EPA were going to adopt a deferral scenario, it should be the EPA

- proposed Alternative 1 with SCR oper ation

deferr ed 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 acknow ledges, 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, 2 012 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 ri sk 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 203 1

. 330 So any impacts on them will be for a shorter term than impacts on other

water user s, 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.