20241106Direct Don Reading.pdf

RECEIVED
Wednesday, November 6, 2024
IDAHO PUBLIC
UTILITIES COMMISSION
I
2 BEFORE THE IDAHO PUBLIC
3
4 UTILITIES COMMISSION
5
6
IN THE MATTER OF THE Case No.: IPC-E-24-07
7 APPLICATION OF IDAHO POWER
8 COMPANY FOR AUTHORITY TO
9 INCREASE RATES FOR ELECTRIC
SERVICE TO RECOVER COSTS
10
ASSOCIATED WITH INCREMENTAL
I I CAPITAL INVESTMENTS AND
12 CERTAIN ONGOING OPERATION
13 AND MAINTENANCE EXPENSES
14
15
16
17 INDUSTRIAL CUSTOMERS OF
18
IDAHO POWER
19
20 DIRECT TESTIMONY
21 of
22
DR. DON READING
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READING, DI - I
28 INDUSTRIAL CUSTOMERS
OF IDAHO POWER

I TEST YEAR
2 Q. Please state your name, business address, and occupation.
3
A. My name is Don Reading. My business address is 280 South Silverwood Way,
4
5 Eagle Idaho. I am an independent consulting economist.
6 Q. Please describe your educational background and experience as a consulting
7 economist. My qualifications and background experience are described in attached Exhibit No.
8 301.
9
Q. Dr. Reading, do you support Idaho Power Company's ["Idaho Power" or the
10
II "Company"] proposal in this case that the Commission adopt the use of a year-end of plant
12 balances for purposes of calculating fair,just and reasonable rates for the Idaho Power
13 Company?
14 A. No.
15
Q. Please explain.
16
17 A. The Company's position is succinctly stated by Tim Tatum who is Idaho Power's
18 Vice President of Regulatory Affairs. Mr. Tatum states, at pages 20-21 of his direct testimony
19 that:
20 The use of year-end plant balances as opposed to a historical monthly average will
21 ensure that the rate base included in customer rates reflects plant investments placed in
service up to the time rates to go into effect, thereby reducing, albeit not eliminating,
22 regulatory lag.
23
To hear a regulated state-sanctioned monopolist complain about regulatory lag is much like a
24
firm in a market economy complaining about competition, it is a business risk that, like many
25
26 others, comes with the territory. Regulatory lag is part of the bargain Idaho Power (and all
27 other regulated state-sanctioned monopolies) struck in order to legally prevent competition for it.
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INDUSTRIAL CUSTOMERS
OF IDAHO POWER

I business or for its captive ratepayers. Regulatory lag is a simple, and unavoidable, fact of life
2 that investors in the power company are aware of when they invest in that company.
3
Q. It sounds like you are disapproving of the "state-sanctioned" monopoly construct.
4
Is that true?
5
6 A. Not at all, quite the contrary. I do not intend any pejorative intent in using the
7 phrase, "state-sanctioned monopolist." Some parts of the power company's business are best
8 provided under the state's protection as a monopoly business segment. This is often referred to
9
as a 'natural monopoly' where society as well as the company gains by having it in place.
10
II Q. Mr. Tatum provides the Commission with a definition of the phrase "regulatory
12 lag" on page 17 of his direct testimony. Do you agree with his definition?
13 A. Yes and no.
14 Q Please explain?
15
A. Quite appropriately Mr. Tatum references the definition of regulatory lag provide
16
17 in Bonbright's 1988 classic on utility regulation, "Principles of'Public Utility Rates, " which
18 provides at page 96 that regulatory lag is:
19 the quite usual delay between the time when reported rates of profit are above or below
standard and the lime when an oJfselting rate decrease or increase may be put into effect
20
by commisslon Order...
21
I would have no issue with Mr. Tatum's regulatory lag definition had he stopped at that point.
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However, he chose to recast the definition in a manner that benefits the company's shareholders
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24 and not the company's ratepayers. According to Mr. Tatum on page 17 of his direct testimony,
25 regulatory lag has a more limited definition, to wit:
26 In the context of this particular proceeding, regulatory lag refers to the lime period
27 between when a capital investment is made by the Company and when the Company
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OF IDAHO POWER

I begins to recover that investment through customer rates. Further, the same concept is
2 applicable to O&Nf Labor costs in this instance.
3 Mr. Tatum's definition ignores a fundamental concept of regulatory lag.
4 Q. Please explain?
5 A. Regulatory lag, to paraphrase Bonbright, is the time lag between when a utility's
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profits are out of sync (either too high or too low) and the time necessary for the Commission to
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raise or lower rates to bring the utility's profits back within a normal or appropriate range. Idaho
9 Power's definition ignores the utility's profits (or lack thereof), and only focuses on the limited
10 discreet question of whether a specific widget is included in rate base. Idaho Power hasn't asked
I I the Commission to decide whether it is over earning or under earning only that these particular
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widgets be added to the mix of its approved rate base.
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14 Q. Idaho Power's most recent rate case, which was settled just last year, was the
15 power company's first general rate case in more than ten years. Are there any implications for
16 regulatory lag in the fact that Idaho Power waited ten years to file its most recent general rate
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case?
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A. Waiting ten years to file a general rate case suggests that the Company's earnings
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20 (profits) were more than adequate to satisfy its investors for that long period of time. On the
21 surface, at least, it appears the Company is willing to allow its shareholders to receive benefits of
22 over decade's worth of regulatory lag when its earnings are robust, or to quote Bonbright, when
73 its earnings are "above standard." I say "appears" because we don't know whether the
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company's earnings during the decade it Filed no general rate case were either above or below
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"standard." We can assume, however, that the Company's investors would have pushed
27 management to File a general rate case if earnings were not, at a minimum, adequate. "Thus, it is
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OF IDAHO POWER

I clear that regulatory lag can actually be beneficial to the company's investors at the expense of'
its ratepayers.
3
Q. Are you obiecting to the Company's filing of a limited issue rate case?
4
5 A. No. But, as the adage goes, be careful what you wish for. The Company wanted
6 a limited issue rate case, and all of the parties acquiesced or agreed to proceed with such a case.
7 "thus, the issue of regulatory lag, at least the type of regulatory lag defined by Bonbright is not,
8 and should not be, on the table to influence the Commission's decision as to either when or
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whether these particular widgets belong in the Company's rate base.
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I I Q. You labeled your testimony, "test year." Flow do the issues of regulatory lag and
12 appropriate test year intersect'?
13 A. Idaho Power argues, via Mr. Tatum, that using a year-end partially forecast test
14 year will reduce regulatory lag.
15
Q. Do you agree?
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17 A. No, for several reasons.
18 Q. Please explain'?
19 A. First is the foundational principle that the rate payer should only be charged for a
20 utilitycompany's assets that are used and use fill. This approach to ratemakin has practically.f pP g p Y
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been a universally accepted principle by commissions throughout the country -- including Idaho.
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33 Again, according to Bonbright:
24 In they fit,sl place, Ifin-f they commission's slaffrulc making parrhuses, only just and
reasonable expenses am allo�re(l only use'cl and u1'e'frd proj)ei-q, ispCrmilletlIn rate hase.
25 In the seconct place, the commission musl have a basis fin. e'stinlatNd f ttui,e i,e'venae
26 Y'e'C uirements, This e'stinlale is one of the most. cliff/cull I7rohle'ms in a r'aie case, A
commission is setting rales_for• thc,fulure hctt it has only,Imsl exl)erience (expenses,
27 revenue, demand conditions) to use as a guide.
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OF IDAI10 POWLR

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Hence the tension between test year and regulatory lag becomes a significant issue. Without an
3 earnings test the Commission is shooting in the dark as to the overall impact of inclusion of new
4 investment in rate base.
5 Q. You indicated that the Idaho Commission has adhered to the used and useful
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principle in past general rate cases. Can you provide an example?
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8 A. Yes. Just two years ago in a case involving a major water utility (VEO-W-22-02)
9 the Idaho Commission ruled:
10 The Commission continues to believe that including plant investment in the calculation o
rate base as if it were in service the entire year creates a mismatch between test year
I I revenue and expenses, and it is unreasonable to expect the Commission to allow full
12 recovery gfplanl investment as if'the plant has been in in operation the full year without
a corresponding adjustment to revenues and expenses.
13
14 [Order No. 35762 at p. 23.] The Commission's stated position on this issue is unequivocal.
15 Q. Does it make a difference that the VEO-W rate case involved a water utility and
16 not an electric utility, like the Idaho Power Company?
17 A. No. The regulatory principle is the same whether one is dealing with a water
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utility or an electric utility or a gas utility. The principle holds true also for both large and small
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20 utilities. Simply put, rate payers should not be responsible to pay a return of, and a return on,
21 investments that are not proven to be used and useful in the provision of utility service.
22 Q. Dr. Reading, assume for a moment that Mr. Tatum's complaint about regulatory
23 lag is valid and that this Commission has an obligation to put plant investment into rates without
24
considering their impact on the utility's "rates of profit," as Bonbright characterizes the issue.
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26 Does Mr. Tatum have a valid point?
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READING, DI - 6
28 INDUSTRIAL CUSTOMERS
OF IDAHO POWER

I A. No. One of the primary causes of regulatory lag is when a commission takes an
2 unreasonably long time to prosecute a general rate case. Given the premise of your question, it i.
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important to keep in mind, however, that a reasonable time period between a rate-case-tiling and
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that rate-case-final order is not only normal, it is expected and accepted by all involved --
6 including prospective investors in a state sanctioned regulated monopolies. That said, the Idaho
7 Commission has, in my experience been efficient and timely in prosecuting rate cases for the
8 regulated utilities under its jurisdiction — including Idaho Power.
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Q. Has the Idaho Commission provided Idaho Power with additional mechanisms
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II that mitigate the impact of regulatory lag?
12 A. Yes. Idaho Power has two annual cost adjustment mechanisms -- the Power Cost
13 Adjustment (PCA) and the Fixed Cost Adjustment (FCA). Every year these two mechanisms
14 work against a claim of regulatory lag by providing Idaho Power with what are essentially
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annual automatic cost adjustments in its rates. These are timely and prompt regulatory responses
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17 to the ever-changing cost and cost-recovery environment in which Idaho Power operates.
18 The PCA identities the annual differences between actual net Power Supply Expenses
19 ("NPSE") and the Commission approved a base level of NPSE this is recovered in the
20 Company's base rates. It is filed by the Company in the spring of each year with the change in
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rates taking effect on June I of each year. The FCA intends to break the link between the power
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23 a utility sells and the revenue it receives in order to provide insurance that some of its fixed costs
24 will be recovered. It essentially `decouples' revenues from sales. The FCA is also filed each
25 spring with the change in rates taking effect on June I of each year.
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OF IDAHO POWER

I Q. What is the impact of the FCA and the PCA on the Company's apparent position
2 about regulatory lag?
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A. Both the PCA and FCA adjust the Company's rates on an annual basis. Each
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5 mechanism is, in its own right, a major step in addressing regulatory lag. They help keep the
6 company's earnings (profits) within a reasonable range that has been approved by the
7 Commission in prior general rate cases.
8 Q. Can you identify recent examples of the Idaho Commission's prompt prosecution
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of general rate cases for Idaho Power?
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II A. One need took no further than this case as an example of the Idaho PUC's
12 efficient and speedy resolution of rate cases on behalf of Idaho Power.
13 Q. Please explain?
14 A. This case was filed by Idaho Power on the last day of May 2024. It is schedule t
15
go to hearing on December 6, 2024, and a final order is expected by January 1, 2025. The end
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17 result is that there is only a seven-month span between the initial filing and the final rate order.
18 The last general rate case for Idaho Power was, likewise, resolved in just seven months.
19 Q. At page 21 of his direct testimony Mr. Tatum complains that the used of a 13-
20 month average rate base results in:
21
capital investment that Idaho Po",er vvill have made to serve its customers safely and
22 reliability by January 1, 2025, not being eligible to earn an authorized rate ofrelurn unli
23 some future rate case.
24 Mr. Tatum references "some future rate case" as if it is an external event outside of the
25 Company's control. This is not so. The timing of Idaho Power's future rate cases is wholly
26 within the control and discretion of Idaho Power. If Idaho Power so chooses, "Some future rate
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I case" can take place as early as tomorrow, or January I" or it can wait another decade and File a
2 rate case ten years from now. It is up to Idaho Power when it initiates "some future rate case."
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Q. In sum, the Company proposes to use year-end plant balances as opposed to
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5 historical and justifies its position by saying to do otherwise will exacerbate regulatory lag. Do
6 you agree with the Company's rationale?
7 A, No. As discussed above, there are several reasons why the Company's concerns
8 about regulatory lag are unfounded. Regulatory lag is part of the trade-off in the regulatory
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compact that legally allows the Company to be a monopolist. In the case of Idaho Power, the
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II Company has Commission-approved automatic rate adjustment mechanisms in place for its some
12 of its variable costs (PCA) and some of its fixed costs (FCA). In addition, rate cases in Idaho
13 are resolved in an efficient and timely manner and the Company is not restricted from Filing a
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general rate case whenever it chooses to do so.
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RATE SPREAD
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17 Q. Dr. Reading how does the Company propose to assign its recommended
18 incremental revenue requirement, or rate spread, among the various customer classes?
19 A. Keep in mind that typically, in a general rate case ("GRC"), the incremental
20 revenue requirement is spread among the various customer classes based on a contemporaneous
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cost-of-service study (COSS). However, no new COSS has been prepared for, or filed in, this
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23 case. Rather than update its COSS, the Company is using, as guidance, the old COSS from its
24 2023 GRC case (IPC-E-23-11). Also keep in mind that a COSS is rarely, if ever, adhered to
25 religiously as a requirement for instructing the Company's (or the Commission's) rate spread
26 decisions. Rather the Company tempers and adjusts the COSS results to arrive at a reasonable
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I rate spread recommendation without unduly shaking up established ratepayer-company-
2 Commission expectations. Thus, the Company recommends and the Commission typically
3
adopts a rate spread method that moves customers closer to `parity' or fully cost-based rates
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5 without causing rate shock or major customer cost-responsibility dislocations. In this case the
6 Company asserts that it is not proposing any "structural changes" in rates. [Application p. 5]
7 Q. What method did Idaho Power use to spread incremental revenues to customer
8 classes in the 2023 GRC?
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A. In its last general rate case the Company based its rate spread recommendation on
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II the COSS that was developed specifically for that case. The Company then allocated its
12 incremental revenue requirement and expenses to the various customer classes. That is, it based
13 its recommended movement toward cost-based rates on a rate increase percentage ceiling and
14 percentage floor. This ceiling and floor methodology was agreed to in a stipulated settlement
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that included all of the parties to the case.
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17 Q. What were the ceiling and floor percentages in the settlement of the last general rate
18 case?
19 A. The ceiling was 130% of the overall average increase and the floor was 50% of the
20 overall average increase. [Tatum Direct, IPC-E-23-1 1, p. 29] Thus no customer class received an
21 increase greater that 130% of the overall average and conversely no customer class received less
22 than a 50% of the overall average increase.
23 Q. What was the rate impact of use of the ceiling/floor revenue allocation method in the
24 2023 GRC on your clients who are all Schedule 19 industrial customers?
25 A. The overall percentage increase Stipulated by the Parties and approved by the
26 Commission in the 2023 GRC was 4.25%. Schedule 19 customers were assessed slightly more
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OF IDAHO POWER

I than the 50% floor for a 2.78% increase. Their increase was less than average because the cost-
2 of-service study shows that the Schedule 19 class is paying more than it costs Idaho Power to
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provide them with electric service. Schedule 19 ratepayers are subsidizing other customer
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classes.
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6 Q. How does the Commission approved settlement in the last rate case compare with
7 the Company's rate spread recommendation in this limited issue rate case?
8 A. In this case the Company proposes an overall increase of 7.31% with Schedule 19
9
customers recommended to receive an increase of 7.10% increase,just 0.21 percentage points
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II lower than the recommended overall rate increase. Using the logic (and similar percentage
12 increases) from the Company's last case the industrial class increase should be just slightly
13 higher than the floor which is 3.65% and not subject to an increase just slightly lower than the
14 overall average of 7.10%.
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Q. How do you account for significant difference in the recommended rate increase
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17 for the Schedule 19 customers in this case with the much lower percentage increase in Idaho
18 Power's last rate case?
19 A. Without having an updated COSS I cannot pinpoint the exact cause, however
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there are several factors that may have impacted the change between this case and the 2023
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GRC.
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23 Q. What are the main factors/problems you suspect that may account for the
74 difference in the recommended overall percentage increase in rates for Schedule 19 customers
25 between this case and the last rate case?
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OF IDAI-10 POWER

I A. The first problem is that we don't have an updated, or new, cost-of-service study.
2 It is axiomatic that there have been changes both in the relationship among customer classes as
3
well as the Company's resource mix since the 2023 GRC. The magnitude of these unknown
4
5 changes will naturally impact the results of any prospective new COSS. Therefore, we have no
6 way of knowing how these changes impact the various customer classes' cost causation or their
7 current variance from the parity index of 1.0. (A parity index of 1.0 indicates the class is paying
8 rates exactly equal to its cost-of-service -- neither more nor less.)
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Q. Are there other factors you feel may have affected changes in class cost
10
causation?
II
12 A. Yes, for Schedule 19 the Company observed that;
13 While the 2024 sales,forecast included Simplot Caldwell (Schedule 32)
14 and Lamb Weston (Schedule 34) as individually,forecasted loads, because
both were included as part gf'the .Schedule 19 customer class in the 2023
15 GRC', their torecasted sales were included in the Schedide 19 class, or
purposes ol'developing the Schedule 19 class revenue spread.
16
17 [Tatum Direct, p. 31. Emphasis provided.]
18 In addition, special contract customer Brisbie's (Schedule 33) proposed rates were adjusted in
19 accordance with Schedule 19. [Tatum Direct, Footnote 6, p. 31.] This is important for rate
70 spread purposes because the revenues and the costs that the company has booked for these new
21
special contract customers have been lumped into Schedule 19. So apparently the Company's
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23 rate spread proposal contains information not only for Schedule 19 customers but for those three
24 special contract customers. That means that Schedule 19 data isn't really limited to Schedule 19
25 customers' load and sales -- it is an amalgamation of Schedule 19 and the three special contract
26 customers. There is no individual rate increase proposed for these three special contract
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READING, DI - 12
28 INDUSTRIAL CUSTOMERS
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1 customers in the Company's filing. This creates a potential mismatch and out-of-sync rate sprea
proposal for Schedule 19 and the three new special contract customers.
3
Q. Given the issues you described above do you have an alternative recommendation
4
5 for customer class rate increase spread'?
6 A. Yes. '['he differences discussed above confound the results of what an updated
7 COSS would have accomplished they are mixing apples and oranges. Therefore, instead of
8 what the Company has proposed, I recommend that the percentage difference between the
9
overall rate increase and each individual rate class's rate increase be the same percentage
10
difference that was used and approved by the commission in the last rate case. The 2023 GRC
II
12 was litigated and settled among all parties and ultimately approved by the Commission. My
13 recommendation is not necessarily a long-term Fix. A more accurate customer class allocation
14 should then be developed when the Company Files its next full general rate case along with a
15
new and current COSS.
16
17 Q. Dr. Reading what are the rate spread percentage increases you are recommending in this
18 case`'
19 A A definitive answer can't be given until the revenue requirement increase is finally
20 determined by the Commission in this docket. As a proxy, the following table indicates the
21
impact of my proposal on each customer class at the Company's requested overall increase of
77
23 7.31%. Once the Commission issues its Final order on revenue requirement the following table
24 would have to be revised accordingly.
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READING, DI - 13
28 INDUSTRIAL CUS I-OMFRS
OF IDAHO POWLR

I Final Final
2 Percent Percent New Rate
3 IPC-E-23-11 IPC-E-24-7 IPC-E-24-7
4 Combined Residential 5.52% 7.25% 9.49%
5 Combined Small General Service 5.52% 7.30% 9.49%
6 Large General Service - Prim. & Trans. 2.12% 6.74% 3.65%
7 Large General Service - Secondary 2.12% 6.86% 3.65%
8 Dusk/Dawn Lighting 0.00% 3.65% 0.00%
9 Large Power Service 2.78% 7.10% 4.78%
10 Irrigation Service 5.52% 9.50% 9.49%
11 Unmetered Service 0.21% 7.46% 0.36%
12 Municipal Street Lighting 0.00% 5.96% 0.00%
13 Traffic Control Lighting 5.52% 9.50% 9.49%
Micron 3.65% 5.53% 6.28%
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Simplot 2.12% 4.58% 3.65%
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DOE/IN L 3.67% 3.84% 6.31%
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17 Total Idaho Retail Sales (Excluding CEYW) 4.25% 7.31 /o° 7.31%
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19 Q. Thank you Dr. Reading. Does this conclude your pre-filed direct testimony?
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A. Yes, it does.
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22 Dated this day 6"' day of November 2024.
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OF IDAHO POWER

I CERTIFICATE OF SERVICE
2 I hereby certify that on this 6"' day of November 2024, I caused to be delivered via
3 electronic mail only the foregoing Direct Testimony of Dr. Don Reading in Docket No. IPC-E-
07-24 on the following parties:
4
IDAHO PUBLIC UTILITIES COMMISSION
5
6 Monica Barrios-Sanchez, secretary
mon ica.barriossanchez(c7puc.idaho.gov
7 secretary gpue.idaho.g-ov
8 Chris Burdin, Deputy Attorney General
9 [e-mail]
10
I IDAHO POWER COMPANY
I
12 Lisa D. Nordstrom
Donovan E. Walker
13 Megan Goicoechea Allen
[e-mail]
14 dwalker(u},idahopower.com
15 [e-mail]
16 Tim Tatum
Connie Aschenbrenner
17 Matt Larkin
18 ttatum ci idahopower.com
caschenbrenner a idahopower.com
19 [e-mail]
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21 IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.
22 Eric L. Olson
Lance Kaufman
23 elo(iDechohawk.com
24 [e-mail]
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INDUSTRIAL CUSTOMERS
OF IDAHO POWER

I IDAHO CONSERVATION LEAGUE
2 Matthew Nykiel
3 Brad Heusinkveld
matthew.nykiel(cugmail.com
4 bheusinkveld(' idahoconservation.org
5 FEDERAL EXECUTIVE AGENCIES
6
Peter Meier
7 Emily W. Medlyn
peter.meier(rDhq.doe.gov
s emil .ny �edlync hq;doe.gov
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MICRON TECHNOLOGY, INC.
10
Austin Rueshhoff
I I Thorvald A. Nelson
12 Austin W. Jensen
Kristine A.K. Roach
13 darueschhoff�,chollandhart.com
tnelson cr,hollandhart.com
I4 awiensen(a,hollandhart.com
15 aclee dhollandhart.com
mamemillenAhollandhart.com
16
CITY OF BOISE
17
18 Ed Jewell
Steven Hubble
19 ejewellg..cityofboise.org
boisecityattorney cacityolboise.org
20 shubble&cityofboise.org
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22 Vdo 41-&4�
23 Peter J. Richardson, ISB#3195
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OF IDAHO POWER

1
2 BEFORE THE
3 IDAHO PUBLIC UTILITIES COMMISSION
4
5 IN THE MATTER OF THE APPLICATION OF Idaho Case No.: IPE-E-07-24
POWER COMPANY FOR AUTHORITY TO
6 INCREASE RATES FOR ELECTRIC SERVICE TO
RECOVER COSTS ASSOCIATED WITH
7 INCREMENTAL CAPITAL INVESTMENTS AND EXHIBIT 301
CERTAIN ONGOING OPERATIONS AND
8 MAINTENANCE EXPENSES.
9
10
INDUSTRIAL CUSTOMERS
I
of
12
IDAHO POWER COMPANY
13
Dr. Don Reading's Statement of Qualificaitons
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EXHIBIT 301 - 1

Don Reading, PhD.
Consulting Economist
Education
B.S., Economics: Utah State University
M.S., Economics: University of Oregon
PhD., Economics: Utah State University
Honors and awards
Omicron Delta Epsilon
NSF Fellowship
Profession and business history
Teaching:
1980-81 Associate Professor, University of Hawaii-Hio
1970-80 Associate and Assistant Professor, Idaho State University
1968-70 Assistant Professor, Middle Tennessee State University
Idaho Public Unities Commission:
1981-86 Economist/Director of Policy and Administration
Ben Johnson Associates, Inc.:
1986 ---- Consulting Economist
1989 ---- Vice President
Private Consulting Economist
2023
Experience
Dr. Reading provides expert testimony concern economic and regulatory issues.
He has testified on more than 40 occasions before utility regulatory commissions in
Alaska, California, Colorado, the District of Columbia, Hawaii, Idaho, Nevada, North
Carolina, North Dakota, Texas, Utah, Wyoming, and Washington.
Dr. Reading has more than 50 years experience in the field of economics. He has
participated in the development of indices reflecting economic trends, GNP growth
rates, foreign exchange markets, the money supply, stock market levels, and
inflation. Ile has analyzed such public policy issues as the minimum wage, federal
spending and taxation, and import/export balances. Dr. Reading was one of seven
economists providing yearly forecasts of statewide personal income to the State of
Idaho for purposes of establishing the state of Idaho budget estimates.
In the field of telecommunications, Dr. Reading has provided expert testimony on
the issues of marginal cost, price elasticity, and measured service. Dr. Reading
prepared a state-specific study of the price elasticity of demand for local telephone
service in Idaho and conducted research for, and directed the preparation
of, a report to the Idaho legislature regarding the status of telecommunications
competition in that state.

Dr. Reading's areas of expertise in the field of electric power include demand
forecasting, long-range planning, price elasticity, marginal and average cost pricing,
production-simulation modeling, and econometric modeling.
Dr. Reading was affiliated with the Climate Impact Group (CIG) at the University
of Washington. His work with the CIG has involved an analysis of it impact of
Global Warming on the hydro power facilities on the Snake River. It also includes an
investigation into water markets in the Northwest and Florida. In addition he has
analyzed the economics of snowmakig for ski area's impacted by Global Warming.
Among Dr. Reading's projects was a FERC hydropower re-licensing study (for
the Skokomish Indian Tribe) and an analysis of Northern States Power's North
Dakota rate design proposals affecting large industrial customers (for J.R. Simplot
Company). Dr. Reading has also performed analysis for the Idaho Governor's
Office of the impact on the Northwest Power Grid of various plans to increase
salmon runs in the Columbia River Basin.
Dr. Reading has prepared econometric forecasts for the Southeast Idaho Council of
Governments and the Revenue Projection Committee of the Idaho State
Legislature. He was also a member of several Northwest Power Planning
Council Statistical Advisory Committees and was vice chairman of the Governor's
Economic Research Council in Idaho
While at Idaho State University, Dr. Reading performed demographic studies using
cohort/survival model and several economic impact studies using input/output
analysis. He has also provided expert testimony in cases concerning loss of income
insulting from wrongful death, injury, or employment discrimination.
Publications
"Energizing Idaho", Idaho Issues Online, Boise State University, Fall 2006.
www. boisestate.edu/history/issuesonline/fa[1006_issues/ ndex.html.
The Economic Impact of the 2001 Salmon Season In Idaho, Idaho Fish and
Wildlife Foundation, April 2003.
The Economic Impact of a Restored Salmon Fishery in Idaho, Idaho Fish and
Wildlife Foundation, April, 1999.
The Economic Impact of Steelhead Fishing and the Return of Salmon Fishing in
Idaho, Idaho Fish and Wildlife Foundation, September, 1997.
A Cost Savings from Nuclear Resources Reform: An Econometric Model (with E.
Ray Canterbery and Ben Johnson) Southern Economic Journal, Spring 1996.
A Visitor Analysis for a Birds of Prey Public Attraction, Peregrine Fund, Inc.,
November, 1988.

Investigation of a Capitalization Rate for Idaho Hydroelectric Projects, Idaho State
Tax Commission, June, 1988.
"Post-PURPA Views," In Proceedings of the NARUC Biennial Regulatory
Conference, 1983.
An Input-Output Analysis of the Impact from Proposed Mining in the Challis Area
(with R. Davies). Public Policy Research Center, Idaho State University, February
1980.
Phosphate and Southeast: A Sociology Economic Analysis (with J. Eyre, et al). Government
Research Institute of Idaho State University and the Southeast Idaho Council of
Governments,August 1975.
Estimating General Fund Revenues of the State of Idaho (with S. Ghazanfar and D. Holley).
Center for Business and Economic Research, Boise State University, June 1975.
"A Note on the Distribution of Federal Expenditures: An Interstate Comparison,
1933-1939 and 1961-1965." The American Economist, 01. XVIII, No.2 (Fall 1974),
pp. 125-128.
"New Deal Activity and the States, 1933-1939." Journal of Economic History, Vol.
XXXII, December 1973, pp. 792-810.
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