20071206Peseau direct.pdf

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December 6, 2007 ~
~
\'"
Via Hand Delivery
Jean Jewell
Idaho Public Utilities Commission
472 W. Washington
P.O. Box 83720
Boise, ID 83720-0074
-0:i~
Ç'-l
Re:
Our File:
In the Matter of the Application of Idaho Power Company for
Authority to Increase its Rates and Charges for Electrc Service to
Electrc Customers in the State of Idaho
Case Number: IPC-E-07-08
4489-29
Dear Jean:
Enclosed for filing please find an original and eight (8) copies of Dennis Peseau's
Testimony in the above entitled matter. One copy has been designated as the reporter's
copy, and a disk containing the testimony in ASCII format is also enclosed.
Thank you for your assistance in this matter.
CEW/tma
cc: Service List (w/enclosures)
S:\CLIENTS\489\29\CEW to Jean Jewell re Direct Testimony ofD Peseau.DOC
cn~bJUóÆQ
--
Conley E. Ward (ISB No. 1683)
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Attorneys for Micron Technology, Inc.
S:\CLIENTS\4489\29\Dire Testimony of Dennis Peseu.DO
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION Case No. IPC-E-07-08
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS RATES
AND CHAGES FOR ELECTRIC SERVICE
TO ELECTRIC CUSTOMERS IN THE
STATE OF IDAHO
DIRECT TESTIMONY
OF
DENNIS E. PESEAU
ON BEHALF OF
MICRON TECHNOLOGY, INC.
rf'l
('.).:co
1 Q.
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PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
My name is Dennis E. Peseau. My business address is Suite 250, 1500 Liberty
3 Street, S.E., Salem, Oregon 97302.
4 Q.
5 A.
BY WHOM AND IN WHAT CAPACITY ARE YOU EMPLOYED?
I am the President of Utility Resources, Inc. ("URI"). URI has consulted on a
6 number of economic, financial and engineering matters for varous private and
7 public entities for more than twenty years.
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PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND WORK
EXPERIENCE.
My resume is attched as Exhibit No. 501.
HAVE YOU PREVIOUSL Y TESTIFIED BEFORE THE IDAHO PUBLIC
UTILITIES COMMISSION?
Yes, on numerous occasions for more than 20 years.
FOR WHOM AR YOU APPEARG IN THIS CASE?
I am appearng on behalf of Micron Technology, Inc ("Micron").
WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY?
Micron has asked me to review Idaho Power Company's application and make
appropriate recommendations to the Commission.
PLEASE SUMMARIZE THE RECOMMENDATIONS YOU WILL BE
MAKIG IN THIS TESTIMONY.
My testimony is divided into three sections. I will first explain why I believe the
Commission should reject Idaho Power's use of a forecasted test year. In the
second section of my testimony I will identify some specific adjustments to Idaho
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Power's test year and revenue requirement. Finally, I will explain why Idaho
Power's cost of service studies are badly flawed, and offer more reasonable cost
of service alternatives.
Idaho Power's Forecasted Test Year
PLEASE EXPLAIN WHAT A TEST YEAR IS AND THE ROLE IT PLAYS IN
PUBLIC UTILITY RATEMAKIG?
Every public service commission in the countr uses the "test year" concept as the
foundation for determining a regulated utility's revenue requirement and rates. The
traditional form of a test year has been succinctly described by the Iowa Utilities
Board as follows:
A rate proceeding before the Board begins with historical
data. This is adjusted for known and measurable changes in
costs not associated with a different level of revenue and
revenues not associated with a different level of cost that
will occur within twelve months of the date of fiing by the
utilty. Typically, an historical test year is the latest calendar
year; however, a test year can be any prior 12-month period
of audited information. In a rate proceeding, the utility files
actual data for the period and proposes adjustments to
revenues, expenses, assets, liabilties, and capital issuaces.
These changes are known as "pro forma adjustments. . ."
Once the Board decides which adjustments are allowed and
the resulting revenue requirement, the utility files new rates
that remain in effect until a new rate case is brought. The
goal in setting rates is to tae the data from the historical test
year and make adjustments to the historical data that more
closely reflect the expected costs and revenues going
forward.
Iowa Utilties Board, Review of Utilty Ratemaking Procedures, Report to
the General Assembly (Januar 2004), P. 6 (hereafter "Iowa Report").
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YOU CHARACTERIZED THE ABOVE QUOTE FROM THE IOWA BOAR
AS A DESCRIPTION OF A "TRAITIONAL" TEST YEAR. ARE OTHER
TYPES OF TEST YEARS USED FOR UTILITY RATEMAG?
Yes. According to the Iowa Report, approximately 30 states use the traditional
test year described above. Iowa Report, P. 8. Other states allow some form of
forecasted results into the test year, although those that do often sta the forecast
process with historical data, and many impose other restrctions on the use of this
data. See Iowa Report, P. 8-9. Another recent study of test year practices by the
Nevada Public Utilities Commission provides fuer details on a state-by-state
basis. See Report to the 74th Session of the Nevada Legislature (May 10, 2006).
Because both the Iowa and Nevada reports contain a detailed discussion of issues
present in this case, I have attached the relevant portions of both to my testimony
as Exhibit Nos. 502 and 503, respectively.
WHERE DOES THE IDAHO COMMISSION FIT IN THIS PICTURE?
The Idaho Commission normally uses the traditional test year. But in at least one
recent case, the Commission authorized the use of a "hybrid" test year, using
approximately 6 months of actual test year data and 6 months of forecasted or
budgeted data, provided the projections can be tested and verified before the close
of the case.
HOW DOES IDAHO POWER'S PROPOSAL IN THIS CASE COMPARE TO
THE IDAHO COMMISSION'S NORMAL TEST YEAR METHODOLOGIES?
Idaho Power's proposal is a radical deparure from anything remotely resembling
this Commission's normal test year practices. First, it has completely discarded
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the use of historical data in favor of a fully forecasted 2007 test year,
supplemented by a fuher forecast for 2008. Furhermore, it has anualized many
of the forecasted 2007 changes and, in addition, it has reached into the 2008
forecast for a number of adjustments that are alleged to be known and measurable.
WHAT DO YOU MEAN WHEN YOU SAY IDAHO POWER "DISCARDED"
THE HISTORICAL DATA?
I mean that, for most accounts, Idaho Power does not include the historical data
even as a staring point for its forecasts.
SO HOW WOULD YOU CHARACTERIZE IDAHO POWER'S PROPOSED
TEST YEAR?
Idaho Power characterizes its proposal as a "full forecast test year 2007."
Testimony of Greg Said, P. 32, L. 23. But it really isn't a test year at all, as most
professionals in this business understand that term.
WHY DO YOU SAY THAT?
To pick just one example, a test year, whether historical or projected, normally
contains a 13 month aray of most rate base items. However, in this case Idaho
Power simply calculated a single average rate base number. See Testimony of
Lori Smith, P. 6, L. 15-22.
In addition, and of far greater importce, Idaho Power's revenues and
costs don't match. In Mr. Said's testimony, Idaho Power's claimed jursdictional
revenue for the 2007 test year is $681,765,526. But as Mr. Said acknowledges, if
Idaho Power's proposed rates go into effect on Janua 1,2008, those rates would
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produce anual revenues of $695,423,270, roughly $14,000,000 more than its
claimed revenue requirement. Testimony of Greg Said, P. 34, L. 7-19.
DOES THAT MEAN IDAHO POWER WOULD BE OVEREARING FROM
THE FIRST DA Y ITS RATES WENT INTO EFFECT?
If you assume average costs apply to the entire 2007 year, as Idaho Power did in
the case of its rate base, and fuher assume that no change on Januar 1, 2008
could possibly be great enough to raise anual costs by $14,000,000 in a single
day, the answer has to be "Yes."
But we need not make any assumptions whatever to determine that Idaho
Power's proposed test year violates one of the most important principles of
ratemakng, that test year cost and revenues must match. Again I quote the Iowa
Board:
The fudamental principle in determining rates is the matching
principle. Unless there is a matching of costs and revenues, the
test year is not a proper one for fixing just and reasonable rates.
The inclusion of costs without matching revenues may produce
excessive rates. The inclusion of revenues without matching costs
may deny the utilty reasonable rates. The relationship between
costs and revenues for the test period used, whether historical or
projected, and the validity of that relationship, constitutes one of
the most vital steps in the determination of just and reasonable
rates.
Exhibit No. 502, P. 6 (emphasis added). Idaho Power's testimony contains not a
word of justification for this clear mismatch, presumably because it is simply
indefensible.
HOW DOES THE COMPANY ATTEMPT TO JUSTIFY ITS DEPARTURE
FROM PAST TEST YEAR PRACTICES?
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The Company's basic arguent for the use of a forecasted test year is that
"regulatory lag" will otherwse produce an inevitable revenue shortfall for Idaho
Power. The essence of this argument is sumarzed by the following quote from
the Company's CEO, Mr. Keen:
It is not fair nor reasonable to determine a utility's revenue
requirement based on historical data in a period when
prices are increasing or the utility's embedded costs are far
below the utilty's incremental costs. . . As a result, it is
highly unlikely that the Company will ear the retur
authorized by the Commission.
Testimony of Lamont Keen, P. 10, L. 6-22.
DO YOU FIN THIS ARGUMENT FOR A FORECASTED TEST YEAR
PERSUASIVE?
No, I don't. In the first place, nothing can justify the violation of the fudamental
test year matching principle. If the Commission were to accept Idaho Power's
proposal in this regard, it would be an unprecedented depare from fudamental
regulatory principles that would very likely produce excessive rates from the
outset.
Second, even ifIdaho Power's forecasted test year were properly
constructed, the implicit assertion that it is necessar because regulatory lag
inevitably produces a revenue shortfall is demonstrably untrue.
Finally, concerns about regulatory lag are not new-utilties have been
makng similar arguments thoughout my career in this business. But the Idaho
Commission has neverteless consistently refused to allow the use of a fully
projected test year, paricularly one based largely on budgeted numbers, primarly
because forecasting introduces a host of intractable problems. These problems
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fall under three general headings: (1) forecasts of this type are inherently
inaccurate and uneliable, (2) they are difficult if not impossible to verify, and (3)
their use in ratemaking creates a perverse set of incentives and temptations for the
utility and a structual bias in the ratemaking process.
WHY DO YOU DISAGREE WITH IDAHO POWER'S "IMPLICIT
ASSERTION" ABOUT THE EFFECT OF REGULATORY LAG?
Idaho Power is arguing that a differential between embedded and incremental
costs, coupled with system growth and general inflation, will invarably produce a
revenue shortfall as a result of regulatory lag. The fudamental flaw in this
arguent is that it cherr picks the data by focusing only on factors that tend to
increase revenue requirements. Idaho Power's argument would be correct if it
was preceded by the caveat "all other things being equal." But all other things are
never equal or static for a complex economic entity like Idaho Power.
Whle it is true that system load growth and general inflation tend to
increase costs, other prevailng trends decrease them. These countervailing
factors include such items as labor productivity gains, efficiency improvements,
and greater economies of scale. Other major cost inputs, the most notable of
which are interest rates and natural gas prices, move in unpredictable ways, and
they can either increase or decrease costs significantly. In short, regulatory lag is
like financial leverage-it can work both ways. Whether it helps or hurs a utilty,
or has no effect, depends on the circumstances.
To his credit, Mr. Gale is the only Idaho Power witness to acknowledge
ths fact. As Mr. Gale points out, "The impact of regulatory lag is dependent on
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the sitution-if costs are not going up faster than rates, then the utilty is not
hared and may even be helped by lag." But Mr. Gale then goes on to allege that
"Idaho Power is not in that sitution and wil not likely be for the foreseeable
future." Testimony of John R. Gale, P. 11, L. 19-24.
DO YOU DISAGREE WITH MR. GALE'S VIEWS ABOUT THE
"FORSEEABLE FUTURE?"
I am not in a position to either agree or disagree because the simple fact is that, as
I will demonstrate in detail later in my testimony, neither he nor I can possibly
make a confident prediction about the effect of regulatory lag in the futue. But
before I turn to that subject it is important to point out that the historical record
shows that there have been long periods of time in recent years when regulatory
lag did not produce a revenue shortfall for Idaho Power, notwithstading the
presence of continuing system growth, general inflation, and an
embedded/incremental cost differentiaL.
PLEASE DESCRIBE THE HISTORICAL EVIDENCE YOU JUST
REFERENCED.
If we look back over the last 15 years, we see that nearly a full decade passed
without a rate case prior to Idaho Power's 2003 filing. A vista and Pacificorp
experienced a similarly long hiatus between rate cases durng roughly the same
time frame. In Pacificorp's case, this respite can be parially attbuted to agreed
upon merger and acquisition related rate freezes. But, to the best of my
knowledge, neither A vista nor Idaho Power were under similar constraints.
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WHAT CONCLUSIONS DO YOU DRAW FROM THIS TEN YEAR
SUSPENSION IN RATE CASES?
Investor owned utilities are for-profit institutions, and neither Idaho Power nor
A vista has shown any reluctance to engage in frequent rate cases when they
believed they had a revenue shortfall, either before or after the 1994-2003 decade.
Therefore, I conclude that these companes generally believed they were earing a
fair retur during ths approximately 10 year time period, notwithstading the
very long lag after the initial rate determination.
WAS THAT BECAUSE THERE WAS NO INFLATION DURIG THAT TIME
FRAME?
No. My Exhibit No. 504 is a three page Value Line sumary of the history of
selected economic benchmarks from 1920 through 2005. As you can see, the
Consumer Price Index showed general inflation durng the 90s holding relatively
steady at an anual rate of a little less that 3%, very near the curent CPI rate
today.
MAYBE IDAHO POWER WASN'T EXPERIENCING ANY GROWTH THEN,
OR PERHAPS ITS INCREMENTAL COSTS WERE NOT IN EXCESS OF
EMBEDDED COSTS.
The answer to both implicit questions is "No" and "No." My Exhbit No. 505 is
the curent Value Line report for IDACORP. According to Value Line, Idaho
Power's book value per share steadily increased throughout the 1990s, as did
capital spending per share in most years. This indicates that Idaho Power was
growing at a fairly steady pace durng that period.
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In addition, just based on my experience in this industr and in following
Idaho Power over that time frame, I can say with complete confdence that its
incremental capital costs also exceeded embedded costs then, just as they do now.
SO WHY DIDN'T THE LONG REGULATORY LAG BETWEEN THE
SETTING OF RATES IN THE EARLY 90S AND THE GENERAL RATE
CASE FILED IN 2003 PRODUCE REVENUE DEFICIENCIES?
I couldn't say without underting a complex and lengthy study. I suspect the
persistent decline in capital costs and fuel prices from the highs of the early
1980s, together with productivity and effciency improvements, the adoption of
anual power cost adjustments, and other factors, all played a part. But my point
is that history shows that for roughly two-thirds ofthe last 15 years, regulatory lag
was benign from the utility's point of view. It also shows that neither system
growth, general inflation, nor a differential between embedded and incremental
costs means that regulatory lag will inevitably produce a revenue requirement
shortfalL. Idaho Power's presumed cause and effect relationship between these
items simply doesn't exist.
WOULD YOU PLEASE EXPLAIN THE DIFFICULTY IN MAKIG
ACCURATE FINANCIAL FORECASTS?
First of all, it is important to carefully explain what is really at issue here. There
is undeniably a place for forecasts in ratemaking. Idaho Power's anual power
cost adjustment (PCA) provides a perfect example. In the PCA proceedings,
power supply costs are forecasted using a carefully constrcted and agreed upon
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model, based on projected stream flows provided by an independent third par.
At the end of the year, these predictions are, in effect, "tred up" to actual results.
Similarly, many pro forma changes that are anualized durng the test
year, and "known and measurable" changes that occur after the close of the test
year, are often a form of forecasting. Even if they don't occur exactly as forecast,
there is nevertheless a very high degree of certainty about the probability of the
forecasted event and its likely magnitude. The classic example is a nearly
finished generating unit that is scheduled to come on line afer the close of the test
year.
These "forecasts" stand on a very different footing than the forecasts
Idaho Power is using in this case, where it is attempting to project future costs and
revenues in myriad accounts. By definition, these across-the-board forecasts are
either "unown" or "uneasurable" or both. Viewed in this light, the audacity
of Idaho Power's contention should give everyone involved in this case pause.
After all, it taes considerable hubris to even contend that one can predict the
unown future.
ARE THERE ANY STUDIES ON THE RELIABILITY OF FORECASTED
TEST YEARS LIKE THE ONE IDAHO POWER IS PROPOSING?
To the best of my knowledge, there are no extat studies that attempt to determine
the accuracy of utilities' forecasted test years, which is rather strange since
someone who purorts to divine the future would normally be asked to prove he
could do so. But there is a wealth of information about the accuracy of financial
forecasts in an analogous sitution-the case of Wall Street analysts who produce
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earngs forecasts for the companies they cover. The endeavor here is very
similar to the kind of piece by piece forecasted test year Idaho Power is presenting
in this case and we have many, many studies testing the accuracy of their
forecasts.
BEFORE WE TURN TO THE RESULTS OF THOSE STUDIES, PLEASE
EXPLAIN WHY YOU REGAR ANALYSTS' FORECASTS AS
ANALAGOUS TO A FORECASTED TEST YEAR.
The task of a Wall Street analyst is very like that of a utility attempting to
forecast its futue test year. On the one hand, all interested parties have access to
the historical record contained in quarerly and anual reports, plus certin known
and measurable changes that must be reported by law, which are roughly
analogous to the traditional test year information. The Wall Street analysts
attempt to add value to this objective, factual record by forecasting companes'
earngs in the future. As in the case of the forecasted test year, the premise of
this industr is that the analysts' forecasts wil provide a more accurate depiction
of the future than could be determined from the factual record alone.
HOW MUCH EFFORT GOES INTO THE PREPARATION OF ANALYSTS'
FORECASTS?
An enormous effort, even by the lavish standards of Wall Street. The analysts
who produce these earings forecasts are some of the brightest and most highly
compensated individuals in the financial world. If it were possible to produce
accurate, reliable financial forecasts in this maner, surely this experienced
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industry staffed by extravagantly paid professionals with blue chip MBAs and
PHDs could do so. i
ENOUGH BACKGROUND, HOW DO THE ANALYSTS FORECASTS
COMPAR TO ACTUAL RESULTS?
Even to a skeptic like myself, the results are shocking. I first became acquainted
with this data via David Dreman's book, Contrarian Investment Strategies: The
Next Generation (Simon & Schuster, 1998) (hereafter "Dreman"). Dreman stas
by reviewing the largest, and longest ruing, data set available at the time of
publication, a review of 94,251 consensus analyst forecasts from 1973-1996. The
study was limited to companies with at least 4 covering analysts, was for the
coming quarer only, and the analysts could revise their projections up to two
weeks before the close of the quaer. The results?
"The average error for the sample was a whopping 44% anually;" with a
median margin of error of 42%. Dreman, P. 91. I should stress that this doesn't
mean that 44% of the forecasts erred; it means that the average forecast missed
the mark by 44%! Dreman fuher found there was only a few percentage points
difference between the rate of under-estimates and over-estimates, and not much
varation of results based on the industr sector of the covered company.
Thinkng that perhaps this result could not possibly apply if confned to
just the largest and most stable companies, Dreman conducted another study
eliminating the smaller companies from the 1000 company sample, which would
perhaps be more comparable to a utilty forecast. This improved the analysts'
1 Well informed followers ofthis industr would rightly point out that analysts famously tend to be overly
optimistic in their buy/sell recommendations for a variety of reasons. But this is a separate issue from their
earings projections, which they have every incentive to make as accurate as possible.
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odds, but the average margin of error was stil an astonishing 23% for these bluest
of blue chips.
AS YOU POINTED OUT, THESE RESULTS APPLIED TO QUARTER-
AHEAD FORECASTS. IN THIS CASE WE AR DEALING WITH IDAHO
POWER'S LATE 2006 FORECASTS FOR 2007 AND 2008. WHAT DOES
DREMAN'S REVIEW HAVE TO SAY ABOUT LONGER FORECASTS?
Not unexpectedly, the longer forecasts were even less accurate. The odds of
forecasts for each of the following 4 quaers fallng within 10% (which
coincidentally is the amount of Idaho Power's requested increase in this case ) of
actuals were 21 to 1 against, and for predicting all 4 quaers within a plus or
minus varance of 5% they were an astounding 130 to I! As the time horizon is
lengthened or the tolerable varation range is narowed, the odds of a forecasting
error increase exponentially. Dreman, P. 112.
MAYBE COMPANY MANAGEMENT OR INSIDERS LIKE THOSE WHO
PREPARD IDAHO POWER'S FORECASTS CAN DO BETTER.
A reasonable question, but there is no help for Idaho Power's case there. In the
late 60's and 70's, researchers tested this proposition in 11 studies, and Dreman
sumarzes their results at page 99. This was a paricularly good period for all
forecasters, in that the average error was low by historical stadards. The mean
analysts' error was 16.6% and the mean management error was only a slightly
better 14.5%. But in only one study and that was for a single year, did
management beat the parameters of this rate increase request, albeit by the
smallest of margins, with an average error of 10.1 %.
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HOW DO YOU EXPLAIN THE MAGNITUDE OF THESE FORECASTING
ERRORS?
As it turs out, psychologists have studied the forecasting error problem in
considerable detail, and concluded that there is a consistent, and vast, difference
in forecasting results, depending on whether the forecaster takes what is known as
the "inside view' of forecasting, or the "outside view." Inside view forecasters
treat each problem as unque, paying no attention to history. This
method is the one overwhelmingly used to forecast earings
estimates and stock prices. The analyst or the stock forecaster
focuses entirely on the stock and related aspects such as growth
rates, market share, product development, the general market, the
economic outlook, and a host of other variables.
The "outside view," on the other hand, ignores the multitude of
factors that go into makng the individual forecast, and. . . is
essentially statistical and comparative, and does not attempt to read
the future in any detaiL.
Dreman, P. 110.
Studies comparing the relative success rates of the inside view and the
outside view repeatedly find the outside view much the superior of the two.
Dreman quotes one of the leading researchers in the field (Daniel Kaheman),
sumarzing the findings as follows:
It should be obvious that when both methods are applied with
judgment and skil the outside view is much more likely to yield a
realistic estimate. In general, the future of long and complex
undertakings is simply not foreseeable in detaiL.
Page 110-111. As Dreman elsewhere notes, "These findings apply to many other
fields." Page 1 09.2
2 The Dreman text can't be reproduced in full as an exhibit because of copyrght restrictions. But Micron
has arged to have my copy of the book placed in the Idaho Power discovery room.
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HOW DOES ALL THIS RELATE TO IDAHO POWER'S FORECASTED
TEST YEAR?
Traditional test years tae the "outside view" of forecasting. They rest on
objective historical data, modified only for pro forma adjustments and future
changes that are "known and measurable." While they recognize future changes
that are known with virtual certinty, speculations about the futue play no role in
the process.
Idaho Power's forecasted test year, on the other hand, is a classic example
of the "inside view." It attempts to create from whole cloth forecasts for all the
myriad accounts involved in a complex rate case. These budgets and forecasts
were mostly prepared in late 2006 for a test year that is roughly "centered" in
early 2008. That being so, if Idaho Power's forecast of rate or retu is no more
accurate than Wall Street analysts' earnings estimates, the odds are at least 21 to 1
against this forecast coming within 10% of actual results for all four quarers of
2008.
YOUR SECOND GENERAL CRITICISM OF FORECAST TEST YEARS IS
THAT THEY AR NOT ONL Y INACCURATE AND UNLIABLE BUT
ALSO UNERIFIABLE. WHAT DID YOU MEAN BY THAT COMMENT?
I think the point is rather obvious. Actual recorded results can be audited and
verified. Forecasts canot. I don't mean that forecasts don't have a paper traiL. I
am relatively certin Idaho Power can produce a document of some sort to
support each of its line by line forecasts. But I have already explained why these
forecast documents are likely to be uneliable.
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Actual recorded results stand on a much different footing. They can be
audited and verified. At least within the limitations of GAAP and regulatory
accounting rules, they are a matter of fact. That is why SEC regulations require
companies to issue anual reports based on audited results rather than budgets.
Sarbanes-Oxley now requires the top levels of management to verify, under
penalty oflaw, that those reports are basically tre and correct. Conversely, when
management issues what are called in the trade "forward looking statements,"
they typically come with a legal disclaimer to the effect that they are not
statements of fact and are not to be relied upon for investment decisions.
BUT AS YOU ACKNOWLEDGED EARLIER IN YOUR TESTIMONY,
THERE AR SOME STATES THAT ALLOW FULLY FORECASTED TEST
YEARS. HOW DO THEY DEAL WITH THE VERIFICATION ISSUE?
The roster of states that allow fully forecasted test years is almost exclusively
confined to populous states with very large public service commission staffs, e.g.,
California, New York, Pennsylvania, Ilinois, Michigan, Minnesota, and
Wisconsin. Wisconsin, for instance, has 185 staff members, and almost all of its
auditors are CPAs. Exhibit No. 502, P. 8-9. In addition, Wisconsin requires each
utility to fie a rate case every year, thus providing an opportnity for a continual
tre up and refinement of forecasts. ¡d.
With these kind of resources it might be possible to make forecasted test
years more or less verifiable, if they include historical data and if there are strct
rules and guidelines in place governing the maner in which the forecasts are
prepared. But even if the Idaho Commission had the necessar staff to conduct
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this verification exercise, I am personally very skeptical that it would produce
ratemaking benefits that would remotely justify the costs.
YOUR FINAL OBJECTION TO THE USE OF A PROJECTED TEST YEAR is
THAT IT WILL BIAS RESULTS IN FAVOR OF THE UTILITY. THIS is
SOMETHING OF AN INFLAMMATORY STATEMENT. WHAT is YOUR
EXPLANATION?
First of all, let me make it clear what we are talking about. We are not talking
about Enron style fraud. What I am talking about here is a systemic bias that has
little or nothing to do with fraudulent activities.
WHAT DO YOU MEAN BY THE TERM "SYSTEMIC" BIAS?
This comes in two forms. First, it is obvious that Idao Power's board and
management are primarly responsible to the Company's shareholders. If rates
and ultimately rates of retur are dependent on forecasts, then there is every
incentive for management to overestimate costs and underestimate revenues.
Then it becomes a game of "catch me if you can" for the PUC staff. Ths point
seems so obvious to me that it doesn't require fuher elaboration, but those who
wish to see the argument fleshed out in detail can peruse Exhbit Nos. 502 and
503.
But there is also a second, more subtle type of bias that creeps into the
regulatory process if budgets are used for forecasts. As I pointed out earlier in my
testimony, forecasting of the sort Idaho Power is proposing is an enormously
diffcult undertaking that is almost certin to produce errors. Under normal
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circumstances, if the project is conducted objectively, we would expect those
errors to be symmetrical, i.e., as many underestimates as overestimates.
Unfortunately, the consequences for the forecaster are not symetrcal.
Anyone who has spent any time in or around the corporate world knows that
coming in over budget 50% of the time is not conducive to a long and successful
career. On the other hand, consistently coming in under budget will at least earn
hearty congratulations and maybe a promotion or raise. This means that every
department head submitting a budget/forecast has a personal incentive, quite apart
from that of his or her employer, to estimate costs on the high side.
PLEASE SUMMARIZE YOUR TESTIMONY REGARING IDAHO
POWER'S FORECASTED TEST YEAR.
First, Idaho Power's proposal isn't really a test year at all because it mismatches
revenues and costs. Second, I believe that the use of a forecasted test year like the
one proposed here is almost certain to produce results that are less accurate than
the curent practice, that are inherently biased in favor of the utility, and
essentially unverifiable. I fail to see how any of this is in the public interest.
HAVE YOU PREPARD A TRAITIONAL HISTORIC TEST YEAR AS A
SUBSTITUTE FOR IDAHO POWER'S FORECAST?
The sad fact is there is simply no evidence in the record that would enable me to
do so. Furthermore, even if the record contained the necessary evidence,
untangling and reversing all of Idaho Power's intertwined forecasts would be a
Herculean effort that is beyond the capabilities of any intervenor unless it is
prepared to spend enormous sums.
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SO WHERE DOES THAT LEAVE US?
I truly believe that Idaho Power's forecasted test year should not, and as a
practical matter canot, be used to determine rates that are required by law to be
"just and reasonable." Therefore, unless Staff can construct a more reasonable
and reliable test year based on its audit of the Company, I believe the case should
be dismissed.
Revenue Requirement Adjustments
DO YOU HAVE ANY OTHER COMMENTS ON IDAHO POWER'S
PROPOSED REVENUE REQUIREMENT EIN ADDITION TO YOU
CRITIQUE OF THE FORECASTED TEST YEAR?
Yes. There are several significant changes that should be made to Idaho Power's
forecasted revenue requirement. In Idaho Power's forecasted test year, all
changes from the 2006 year end rate base and all associated expenses such as
depreciation and propert taes are forecasted based on projected plant additions
and retirements. Idaho Power follows these forecasted increases in plant in
service by fuher identifying major plant additions beyond the test period, then
assuming these major plant additions will be in service for the entire forecast, and
finally calculating anualizing adjustments to rate base and expense to
accommodate the longer assumed period in service.
While such anualizing adjustments may be appropriate for an historic test
period, in my opinion they are totally inappropriate for a future test period. When
applied to an historic test period they may reduce regulatory lag; however, when
applied to a future test period they wil probably introduce just the opposite,
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regulatory lead. In any historical test period, additions to rate base will be made
throughout the period. Actual eared retu on rate base wil depend on income
and actul in service dates for rate base additions. Setting rates based on the
assumption that some assets wil be in rate base for the whole period, when in fact
they are not, will likely produce actual rates of retur in excess of the retur rates
were designed to recover.
DO YOU HAVE ANY OTHER ISSUES WITH RESPECT TO THE
ANNALIZING ADJUSTMENTS FOR MAJOR PLANT ADDITIONS?
Yes. Even assuming that such anualizing adjustments are appropriate for a
futue test period, Idaho Power has overstated the magntude of the adjustments.
Idaho Power uses a simple average of year end 2006 and projected year end 2007
rate base for the 2007 test period. This implicitly assumes that all plant additions
occur at mid year and the assets are in service for ~ the test year. An anualizing
adjustment would then accommodate the first six months of the year that the
assets were not in service.
But Idaho Power's anualizing adjustment for major plant additions then
reverts to a 13 month average rate base to make the anualizing adjustments.
Since the major plant additions have a weighted average in service date of late
September, Idaho Power's anualizing adjustment accommodates an additional
9.6 months of service for these additions. In effect, Idaho Power adds more to
rate base than the total capital expenditures on these assets, by assuming they are
in service for 15 months ofa 12 months test period. This is clearly wrong.
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HOW SHOULD THIS BE CORRCTED?
I recommend that, at a minimum, the Commission should disallow the total $44.9
millon in anualizing adjustments and the associated adjustments for
accumulated depreciation, depreciation, property taes and insurance. The net
effect would be to reduce Idaho Power's total system rate base by $43.7 milion
and expenses by approximately $2.5 milion. The effect of this disallowance
would be to reduce Idaho Power's requested rate increase by approximately $8.0
millon.
WHAT CONCERNS DO YOU HAVE WITH RESPECT TO IDAHO POWER'S
FILING CONCERNING SALARY INCREASE ADJUSTMENTS?
I take issue with the Company's request to raise its revenue requirement by
$3,020,719 to account for a 2008 salar structue adjustment (Exhibit 18, page 2).
Again, ths request is outside even its forecasted test year. The request puts other
paries in the impossible position of having to review all other 2008 operating
expense increases and decreases to determine whether or not rates even need to be
adjusted (given load and revenue growth) to collect such expenses. I recommend
that the entire $3 milion request be denied.
DO YOU AGREE WITH IDAHO POWER'S REQUEST TO INCREASE ITS
REVENUE REQUIREMENT TO NORMLIZE IERCO REVENUES?
No. This request appears on page 18 of the testimony of Ms. Lori Smith. The
request is made because IERCO (Idaho Energy Resources) is expecting and
forecasting normalized revenues to IERCO wil be reduced in 2007 and 2008.
Whle 2007 has substatially elapsed at the time this testimony is being written,
DIRECT TESTIMONY OF DENNIS E. PESEAU - 23
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paries are obviously stil unable to assess this prediction in light of other
unspecified changes to 2007 and 2008 revenues and costs. For these reasons, I
recommend that the Commission deny the Company's proposed $2.2 milion
revenue adjustment to account for IERCO.
PLEASE STATE YOUR RESPONSE TO THE COMPANY'S REQUEST FOR
INCREASED EXPENSES TO COVER ITS INCENTIVE PLAN?
Company Exhbit No. 18, page 2 indicates that Idaho Power is requesting 4%
over its normal payroll, or $6,215,289, for incentives that comprise three
components: customer satisfaction, budgeta goals and network reliability. I
oppose two-thrds of this proposed adjustment on the basis that the latter two
components, budgetar goals and network reliabilty, produce benefits that fall
primarly to shareholders. Once rates are set in this case, all budgetar reductions
will increase shareholder profitability. Customer rates will remain the same.
Also, after rates are established in this case, all subsequent gains in network
reliability wil lower power supply expenses and increase shareholder returs,
with no corresponding decrease in rates. I therefore recommend that these
incentive expenses be borne by shareholders. Two-thirds of the request or
$4,145,598 should be disallowed in this case.
Rate Strctue - Cost of Service Issues
PLEASE EXPLAIN WHY YOU REGARD IDAHO POWER'S COST OF
SERVICE STUDIES AS "BADLY FLAWED."
Before I do so I would like to first offer some background information that I hope
wil help to frame the cost of service issues in this case. Idaho Power's cost of
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service witness, Mr. Timothy Tatu, correctly describes the cost of service
process from a technical point of view, but he doesn't explain what's really at
issue, or provide the context of such studies within the regulatory framework.
Consequently, I suspect that this technical discussion is virtally unintellgible to
members of the general public. So I propose to star with some basic priciples of
cost of service, and then gradually hone in on the more diffcult concepts, as well
as the issues in this case.
WOULD YOU PLEASE START BY EXPLAINING THE PURPOSE OF A
COST OF SERVICE STUDY?
All rate cases really consist of two distinct undertakings, and in fact the Idaho
Commission has occasionally divided rate cases into two separate hearngs on
these issues. First, the Commission determines a utility's overall revenue
requirement, i.e., the size of the pie. The next task is to determine what
proportion of that total revenue requirement should be recovered from each rate
group or "customer class," i.e., how the pie should be apportioned among the rate
groups.
These rate groups or customer classes exist because it is a universally
accepted principle of ratemaking that, "It is more expensive to serve some
customers than others." Charles F. Philips, Jr., The Regulation of Public Utilties
(Public Utilties Reports, 1993), P. 435 (hereafter "Philips"). Therefore,
customers are grouped into rate classes with roughly similar cost characteristics,
e.g., a residential class, an industrial class, etc. Very large customers-like
Micron, Simplot, and DOE on the Idaho Power system-are typically each treated
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as a unique customer class unto themselves, known in the trade as "contract
customers. "
The purose of a cost of service study is to allocate an appropriate portion
of the utilty's total revenue requirement to each of these customer classes based
primarly on cost causation principles.
WHY is COST CAUSATION IMPORTANT?
Economists don't always agree on much, but on this issue there is rare unanimity
in the profession. While the Commission can, and sometimes should, consider
factors other than costs, there are two primar reasons for focusing on cost
causation in creating the rate strctue.
The first is "fairness," which basically refers to the idea that customers
should pay their own costs and not someone else's. Furhermore, those who
cause a higher revenue requirement should pay an appropriate share of the costs
they cause, and vice versa.
The second reason, and probably the most important to economists, is the
"effciency" rationale. This is the idea that prices should promote the most
effcient possible use of the utilty system. Thus, those who use the system
primarily when costs are high should pay a rate that reflects those
disproportionately high costs so they will be encouraged to conserve or find
alternative means of meeting their needs. And there is an importt, but out of
favor, counterpoint here as welL. Those who consume in low cost periods should
receive an appropriate price signal to do so when consumption is an economic
plus for all.
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is THERE A SIMILAR AGREEMENT AMONG ECONOMISTS ON THE
PROPER METHOD OF DETERMINING COST CAUSATION?
Only to a degree. Some cost of service issues are relatively non-controversial, but
others are routinely contentious, perhaps none more so than the proper method of
allocating peak and off peak costs.
WHY is THIS ISSUE SO CONTENTIOUS?
Very few practitioners in this field would argue with the general view expressed
in a basic regulatory text:
Customers who use the service during the peak demand period are
more expensive to serve than off-peak users. A basic factor in
determining the size of a utility plant is the peak demand.
Therefore, it costs less to serve those customers who use the
service without burdening the business as a whole by adding to the
peak demand period. Furter, if off-peak usage is increased, the
utilty may obtain a better utilization of its plant throughout the
day, thereby resulting in a larger total output over which fixed
costs may be spread.
Philips, P. 436.
But while there is little arguent about the general principle that on-peak
usage should cost more than off-peak, there are repeated disputes about the
maner of calculating the cost difference between peak and off-peak usage. This
issue is so significant that cost of service methodologies are in fact named for the
maner in which they allocate costs between high load factor and low load factor
customers.
WHAT DO YOU MEAN BY THE TERM "LOAD FACTOR?"
For the utility itself, "load factor" refers to the relationship between the peak load
on the system and the average load. When applied to customers, the term "load
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factor" refers to a customer's consumption related to a utilty's peak sales. A
customer with a high load factor is one who consumes in a nearly steady state,
both daily and anually. A low load factor customer consumes electrcity
unevenly, generally in disproportionate amounts either on the daily or monthly
peaks, or both. In general, a greater allocation of costs to peak periods tends to
benefit high load factor customer classes, while a lesser allocation benefits low
load factor customer classes.
It is importt to point out a common misconception here. If peak costs
are appropriately assigned, high load factor customers don't escape these peak
costs. After all, if a customer is consuming a steady load 24/7, then it is on line
during the peak, and should get an appropriate share of those costs. The benefit to
high load factor customers of a properly designed cost of service study is that they
are also online when costs are low, and therefore should get an appropriate
"credit" in their average rate.
is THERE A SINGLE CORRCT METHOD FOR ALLOCATING PEAK
COSTS BETWEEN HIGH AND LOW LOAD FACTOR CUSTOMERS?
No, because a large component of peak costs consist of what are known in
economics as "joint and common" costs. Most of these joint and common costs
consist of the capital cost of generating plants and transmission facilties that are
used to some degree by all customers throughout the year, both on and off peak.
In the lingo of the cost of service profession, these facilties provide either
"capacity" or "demand" (peak)" and "energy" (off and on peak) services.
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Economic theory alone canot determine the correct method of assignng these
costs to customer classes.
Having said that, however, it is worth noting that many engineers and
economists would argue for assigning the bulk of the capital costs of generation
and transmission plant to customer classes in proportion to their use on the
highest single peak of the year, on the grounds that these facilities are sized to
meet this peak demand. There are, however, some practical problems with this
approach, and most commissions don't weight single peak costs as heavily as
many members of these professions would.
DOES THE IDAHO COMMISSION HAVE AN ESTABLISHED METHOD OF
RESOLVING THESE ISSUES IN IDAHO POWER RATE CASES?
Yes. For roughly 25 years now, the Idaho Commission has used what is known
as the "Weighted 12 Coincident Peak" ("WI2CP") cost of service method to
allocate costs on the Idaho Power Company system. Mr. Tatu's testimony
contains a good description of the implementation of this complex process, but a
simpler explanation of the purose of this cost of service choice would probably
be more helpful to understanding the issues in this case.
With regard to the always controversial issue of allocating generating
plant costs, the Idaho methodology first classifies a percentage of generation plant
to "energy" based on the system load factor, which in this case is approximately
58%. The remaining 42% is classified as a demand cost. Because these demand
costs are caused by the peak load months, Idaho Power weights the sumer
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months by the relatively higher demand costs in these months but then, as I
explain below, erroneously disregards those weights in designng rates.
It is importt to point out that the language employed by cost of service
studies can lead to real confusion here. When we talk about the classification of
generating costs to "energy," we are not talking about actul "energy" costs,
primarily fuel and related items, that var with the amount of energy consumed
and are directly assigned to the varous customer classes based on their actual,
recorded usage. Instead, we are talking about the amount, or percentage, of the
fixed capital costs of generating plants that don't var with usage, but are treated
as if they did for cost of service puroses.
WHEN DID THE IDAHO COMMISSION FIRST ADOPT THE W12CP
METHOD?
The Idaho Commission first adopted the weighted W12CP methodology in 1982
in Case No. U-1006-185. In reviewing the cost of service studies before it, the
Commission found:
We find: For the limited puroses for which we use cost of service
data in allocation of the revenue requirement among the customer
classes, Idaho Power's weighted 12 coincident peak study may be
reasonably used to represent costs. Although there could be
improvements in both W12CP studies presented in this case, the
similarties in the results obtained from both of them, which were
the best cost-of-service studies presented in this case, show that we
may use the Company's W12CP for the next step of the rate
allocation process.
Order No. 17856, P. 13.
In 1987, in Case No. U-I006-265A, the Commission again revisited cost
of service issue in what was probably the most intensive litigation of the issue in
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the history of Idaho rate cases. The following quote from the Commission's final
order provides somethng of the atmosphere of the proceedings:
Idaho Power prepared five cost-of-service studies. A Weighted 12
Coincident Peak (lPCo WI2CP) study, a 12 Coincident Peak
(lPCo 12CP) Study, an Average and Excess Demand (lPCo AED)
study, a Positive Excess Demand (lPCo PED) study, and a
Modified Positive Excess Demand (lPCo MPED) study. In
addition, the City of Boise presented two varations of the
Company's W12CP called Boise I and Boise II. FMC presented a
modified weighted 12 coincident peak (FMC MWI2CP) study and
a 7 coincident peak (FMC 7CP) study. The Staff presented an
alternative weighted 12CP (StaffWI2CP) study and an
unweighted 12CP (StaffUI2CP). The results of those studies are
shown on Table 6 on the following page. For the reasons stated in
the following pages of this Order, we will use the Company's
W12CP as a staring point in our allocation of revenues among the
customer classes.
Order No. 21365. Since the 1982 case, the Idaho Commission has relied
solely or primarly on the W12CP method in every Idaho Power rate case.
WHY DID THE COMMISSION CHOOSE THE W12CP METHOD IN
1982?
In the spectr of possible cost of service methodologies, the W12CP method
assigns less cost to peak periods than most. This made some sense at the time it
was first adopted. In the early 1980s, Idaho Power was stil predominantly a
hydroelectric utility. It had two base load coal plants, Jim Bridger and Valmy, but
no peakng plants analogous to today's gas fired peakers.
Instead it met peak loads with its hydroelectric plants, which could adjust
load almost instantly to meet demand, plus power purchases and exchanges.
These hydroelectric plants were (l) relatively cheap on a dollar per kilowatt of
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capacity basis, (2) more heavily depreciated than more recent plants, and (3) had
varable energy costs close to zero.
The result was that actual peak costs did not greatly exceed, and were
sometimes below, base costs! In this context, the Commission's choice ofa cost
of service methodology that gave relatively little weight to peak costs made
considerable sense.
HAS THE IDAHO COMMISSION CONTINED TO USE THE WEIGHTED
12 CP METHOD IN RECENT CASES?
Yes. In the 1994 rate case, the Commission again endorsed use of the
weighted 12 CP methodology, with very little controversy.
In this case, the Commission was presented with only one cost-of-
service study, a study based on the W12CP method prepared by the
Company, and the IPCo study as modified by Staff. The testimony
in this case almost universally support the use of a W12CP
methodology, and thus we find it appropriate and reasonable to
once again utilize the W12CP methodology to establish revenue
requirement for the customer classes.
Order No. 25880, P. 25.
Finally, in the 2003 rate case the Commission again adopted the W12CP
methodology, although it included without comment a variation on this method in
the Order's Appendix:
As we have in most rate cases, the Commission finds the W12CP
cost of service study is the appropriate starting point to allocate
costs to customer classes. . .(W)e find that the W12CP cost of
service results reflect "a reasonable approximation of class
responsibility" and thus provide a measure of relative revenue
responsibility among the customer classes.
Order No. 29505, P. 46-47 (citations omitted).
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In my testimony in this case, I intend to follow this Commission endorsed
method, which is the WI2CP, not an unweighted or average set ofallocators.
However, it is importt to point out that, for reasons which will become apparent
later in my testimony, I believe that after this case is concluded, the Commission
should reexamine the appropriateness of this methodology in the light of changes
on the Idaho Power system.
DOES IDAHO POWER ALSO FOLLOW THE COMMISSION APPROVED
COST OF SERVICE METHOD IN THIS CASE?
Mr. Tatum, Idaho Power's cost of service witness, never quite says so explicitly,
but his testimony clearly implies that his "Base Case Study" follows the
traditional Commission approved methodology. It does not, as I shall
demonstrate later. But he also prepared three other studies that are clearly a
radical deparure from prior practice.
YOU EARLIER STATED THAT ALL FOUR OF THESE COST OF SERVICE
STUDIES AR "BADL Y FLAWED." WOULD YOU PLEASE EXPLAIN
WHAT YOU MEANT BY THAT STATEMENT?
Ths is one of those instances where the view from a distace provides a reality
check on specific results. When I first read Mr. Tatum's testimony and looked at
his sumar exhibit, I knew immediately there was something terrbly wrong
with the results.
HOW COULD YOU REACH THIS CONCLUSION BEFORE EXAMINING
THE DETAILS OF THE STUDIES?
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Because Idaho Power's results in this case are wildly divergent from the results
the W12CP studies have consistently produced over the last 25 years. Durng that
entire period, the cost of service studies in Idaho Power rate cases produced a
repetitive pattern. These studies found that the highest production costs were
incured at times of system peak loads. Generally, such studies concluded that the
residential class' rates have been about right; that is, the residential rates have
been set to approximately collect the class's cost of service. Small general service
rates were generally slightly low. Large general service and industral rates,
including Micron, were typically found to be somewhat, to considerably, too high,
while the irrgation class rates have historically been far below the cost of serving
this class.
Even more tellng, however, is the fact that all of Mr. Tatum's four cost of
service studies would have us conclude that it is the Company's nonsumer
months' that are causing the adverse peak load growth on Idaho Power's system.
This is the implied conclusion because the cost allocators actully used in these
studies allocate most of the capacity and energy costs to periods other than the
sumer.
HAVE RECENT RATE CASES CONFIRMED THE GENERAL
RELATIONSHIPS YOU JUST DESCRIBED?
Yes. The 2005 Idaho Power rate case was settled without a specific Commission
decision on cost of service. But in the last litigated case in 2003, the Commission
found the cost of service study results to be entirely consistent with the
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longstanding historical results, as is apparent from the ultimate decision on rate
design:
By this Order, we authorize Idaho Power to increase its Idaho
revenues by $25,327,533, or approximately 5.2%. As a result,
electric base rates for specific classes will be increased on average
by the following percentages: Residential 5.98%; Small General
Service 5.97%; Large General Service 1.98%; Industrial 2.41%;
and Irrgation 13.95%."
Order No. 29505, P. 1. I note that residential and small general service classes
received an increase slightly greater than the overall average of 5.2%, industral
customers received a rate increase less than half of the overall average, and
irrigation received an increase of almost 2.5 times the overall average. The three
contract customers, Micron, Simplot, and DOE, received increases at or below
those of the other industrial customers. A properly conducted cost of service
study today would reach conclusions consistent with the 2003 results, as I wil
show below.
HOW DO THE 2003 COST OF SERVICE RESULTS COMPARE TO IDAHO
POWER'S COST OF SERVICE RESULTS IN THIS CASE?
With no explanation or justification for a striking change in results, Idaho Power's
cost of service studies suggest that the longstanding relationship between
customer class's respective costs of service has been suddenly and dramatically
reversed. For example, instead of industrial classes and contract customers
receiving one-half of the average rate increase as before, Idaho Power in this case
contends that Schedule 19 and the special contract customers should receive a rate
increase equivalent to roughly 200% to 350% of the average increase if they are
to be brought to full cost of service. These results, when compared with the
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decades old traditional relationship of industrals' rates to cost of service are
simply not credible.
is THERE A WAY TO CLARIFY THIS DRAATIC SHIFT IN RESULTS IN
A CONCISE FASHION?
Yes. The following table sumarzes the shift in a simple, straightforward
maner. Rather than attempt to explain relative percentage increases in rates from
the varous studies, I instead present each study's "Retu Index." Colum 2
shows the Retur Index for each of the customer classes as determined by the
Commission in the 2003 rate case. Colum 3 shows the Idaho Power cost of
service results in this case.
A Retu Index of "1 " indicates that a rate class is paying rates that closely
approximate its cost of service. A Retur Index below (above) "1" indicates that
curent rates of a respective customer class are below (above) cost of service. The
relative distance from the unity value of i indicates the percentage varation of
rates from cost of service, i.e, a value of 1.1 means that rates are 1 0% above cost
of service.
RETURN INDEXES
2003 COMMISSION vs. 2007 COMPANY PROPOSAL
Class Commission 2003 Index Idaho Power
2007 Base Case
Residential (l)1.11 1.32
General Services (7)1.11 .82
General Services (9)1.25 1.04
Industral (19)1.21 .82
Irrgation (24)0.17 .30
Micron 1.38 .58
DOE 1.18 .64
Simplot 1.48 .66
Sources: Pages 1 and 2, Appendix 2, Order No. 29505
Company Exhibit No. 43, pages 1 and 2 - IPC-E-07-08
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1 Q.WHT DOES THIS TABLE SHOW?
2 A.Only four years ago, the Commission determined the Retur Indexes under the
3 "Commission 2003 Index." As evidenced by the Retu Indexes that exceed
4 unity, all major customer rate classes except the irrgation class were paying more
5 than their respective cost of service. The.l 7 contribution of the irrgation class
6 was remarkably smalL. The higher load factor rate classes (general service,
7 industral, and the contract customers) were paying rates much higher than their
8 respective costs of service.
9 The changes Idaho Power made to its costs of service study in this case
10 inexplicably tu these results upside down. Note in the right most colum in the
11 table that the proposed study purorts to show that now the high load factor
12 classes, paricularly the contract customers, have inexplicably fallen well below
13 unity. This, of course, is the reason Idaho Power is arguing for above average rate
14 increases for its high load factor customers in this case.
15 Q.WHT CONCLUSIONS DO YOU DRAW FROM THIS RETURN INDEX
16 ANALYSIS?
17 A.First, a cost of service shift of this magnitude in a mere four years is
18 unprecedented in my decades of experience with cost of service studies.If the
19 underlying cost of service study is properly conducted, these results could only be
20 justified by a recent and enormous change in either customer usage patterns or the
21 natue of Idaho Power's production and delivery system.
22 Q.IS THERE IN FACT ANY EVIDENCE OF SUCH A CHANGE?
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Other than the general increase in fuel costs, most of the changes that have
occured in the past four years ru the other way, i.e., they would suggest a
relative cost shift from high load factor customers (industrials and contract
customers) to low load factor customers (primarly residential and irrgation
customers), rather than the other way around as Idaho Power's results suggest.
WOULD YOU PLEASE DESCRIBE THE SYSTEM CHANGES YOU JUST
REFERRD TO?
First, with respect to customer usage, it is quite clear that the high load factor
customers are not growing appreciably. There appears to have been some modest
growth in industrial load, but the contract customers' consumption is essentially
unchanged from four years ago. Consequently, a change in these customers'
usage canot account for huge swing in cost of service results.
CAN IDAHO POWER'S COST OF SERVICE RESULTS BE EXPLAINED BY
CHANGES TO IDAHO POWER'S SYSTEM?
No. By far the most important change to Idaho Power's system in recent years is
the Company's worsening sumer peak demands, relative to demand at other
times of the year. Mr. Tatu succinctly sumarzes the situation in his
testimony:
In recent years, the Company's system peak has grown at a much
faster pace than average demand. With a comparson of Figues 4-
1 and 4-2 on pages 39 and 40 ofthe 2006 IRP, which I have
included in my workpapers, it is clear that this trend is expected to
continue into the future."
Testimony of Timothy Tatum, P. 13, L. 8-12.
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In effect, Idaho Power's load factor is deteriorating and is expected to
continue doing so for the foreseeable futue. Once again, this circumstace
suggests that the low load factor customers' Retu Index should be deteriorating,
rather than radically improving, as Idaho Power suggests.
PERHAPS MR. TATUM IS MISTAKEN IN HIS ANALYSIS OF THE
DETERIORATING LOAD FACTOR. WHT IS THE CHANCE OF THAT?
None whatsoever. First of all, since the 1994 rate case, Idaho Power's load factor
has steadily dropped from 68% to 58% today, and this decline, as I wil explain
later, appears to be accelerating.
Second, Idaho Power's engineering departent has essentially confirmed
his analysis, and mine, with actions that speak louder than words. Over the last
few years, Idaho Power has added single cycle natural gas combustion tubines to
its resource mix without adding any signficant intermediate (combined cycle gas
plants) or base load plants (e.g., coal plants).
Single cycle gas plants are, in effect, a utility engineer's response to
disproportionate peak load growt. Of all the possible generating plants, they
have the lowest capital costs. But they also have, by far, the highest fuel cost
because they are relatively ineffcient. So, in general, they are only added when
the engineers are tryng to cope with extraordinar growth in peak loads or
something of a "needle peak."
YOU HAVE NOW EXPLAINED WHY YOU KNEW IMMEDIATELY THAT
IDAHO POWER'S COST OF SERVICE STUDIES COULDN'T POSSIBLY BE
RIGHT. WHERE DID THESE STUDIES GO WRONG?
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First, and foremost, Idaho Power's attempt at constructing a future test year, then
incorporating its unsubstatiated forecast of future costs into its cost of service
model, has been done in a maner that completely inverts its prior rate design
results dating back to at least the early 1980s. As I just explained, the huge
changes to the cost burden and recommended rates to customer classes are not
due to any attibutable or identifiable changes to any customer class' usage
characteristics, or to generation, transmission and distribution makeup, but largely
due to the use, or more correctly, the misuse of a forecasted test year.
HOW DOES IDAHO POWER'S FORECASTED TEST YEAR UNERMINE
ITS COST OF SERVICE RESULTS?
In two ways. The first is relatively simple. In what is presumably an effort to
maximize its revenue requirement, Idaho Power forecasts energy prices that are
both very high and disproportionate to other cost increases. This has the effect of
increasing the relative cost burden on high load factor customers.
I have previously critiqued the forecasted test year in general, and I wil
not repeat that discussion here. Suffice it to say, the use of forecasts in a cost of
service study is subject to all the defects of a forecasted test year. Moreover, it is
completely unecessar because, even if the Commission decided to accept Idaho
Power's regulatory lag argument and use the forecasts for revenue requirement
purposes, it would stil be preferable to use verifiable, historic results to apportion
the revenue requirement between customer classes. Unfortately, Idaho Power
hasn't provided the data that would make that possible.
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YOU SAID THERE AR TWO WAYS THE USE OF A FORCASTED TEST
YEAR SKEWS COST OF SERVICE RESULTS. 'WHAT is THE SECOND?
The second problem is a little more complicated and more diffcult to explain.
The problem arses from the fact that Idaho Power's forecasted cost of service
studies tend to ignore the tremendous monthly and seasonal variation in capacity
and energy costs that actually occur on Idaho Power's system. Instead, Idaho
Power's cost of service studies assume, for the most par, that these costs are
constant throughout the year. This results in a severe misallocation of high peak
demand costs by "averaging" these costs into low cost seasons. It is also at odds
with everyhing we know about the historical operation of Idaho Power's system,
or for that matter, any other utilty system I am familiar with.
HAS THE COMMISSION EVER SANCTIONED THIS TYPE OF COST
AVERAGING IN THE PAST?
No. All recent cases have used the costs Idaho POWI~r'S engineers determined for
the Company's power supply planing model for cost allocations. Company
witness Greg Said again uses this model to calculate the monthly power costs that
form the basis for the Company's requested increasi~ in revenue requirement, but
this time the Company ignores these results in three of its four cost of service
studies, and minimizes the importance of these systi~m costs in a fourh study.
Remarkably, this valuable monthly power cost variation information is
largely ignored within the Company's proposed cost of service study without a
word of explanation for the deparre from prior practices. This is indefensible,
DIRECT TESTIMONY OF DENNIS E. PESEAU - 41
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1 given the magnitude of the cost of service shifts involved, as demonstrated in the
2 following graphs.
3 Graph NO.1 compares Idaho Power's power supply model's varable or
4 marginal energy costs with the average varable or marginal costs contained in its
5 unweighted allocators. Graph NO.2 compares the combined marginal monthly
6 energy and capacity costs for the model and the annual average marginal monthly
7 energy and capacity costs.
Monthly Implied Energy Costs
140.00
120.00
100.00
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80.00
60.00
40.00
20.00
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J F M A M J J A S 0 N D
Month
-- Marginal Cost Weight
-- Nonwighted
8
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Monthly Implied Power Supply Costs
180.00
160.00
140.00
120.00
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100.00
80.00
60.00
40.00
20.00
0.00
J F M A M J J A S 0 N 0
Month
-- Me Power Supply Weight
-- Non Weighted
1
2 These graphs show that, by Idaho Power's own power supply model
3 estimates, monthly energy costs range from a low of $55/mwh in May to a high of
4 $128 in July, a range of over 232%. Similarly, total monthly power supply costs
5 var from $55/mwh in April to a high of$155 in the month of July. This seasonal
6 cost information is crucial in a cost of service study in order to ensure that rates in
7 effect reflect costs allocated to these seasons.
8 But in its proposed cost of service studies, Idaho Power chooses to assume
9 that monthly power supply costs do not vary month-to-month, as is shown in each
10 of the above graphs as a horizontal line, when it averages this with a truly
11 weighted allocator. The Company's study is misleading because it claims to use
12 the historical method of computing the WI2CP, when in fact it does not. Instead,
13 the Company uses a modified allocator that averages out seasonal cost
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differences. Choosing entirely new inputs for the model is not a legitimate "Base
Case" scenario.
AR THERE ANY OTHER DEFECTS IN THE IDAHO POWER COST OF
SERVICE STUDIES?
Yes. As Mr. Tatum explains in his testimony at pages 25-27, he weighted anua
capacity costs based on monthly peak hour deficits identified in the Company's
2006 Integrated Resource Plan ("IRP"). The months with projected deficits
include, reasonably enough, the months of June-August and, less reasonably,
December. But the other two identified deficit months are May and September.
Assigning a disproportionate share of capacity costs to these months is
nonsensical on its face.
Anyone at all familiarty with Idaho Power's system will immediately
recognize that May and September are both off-peak months. In fact, as the
graphs I produced above show, April and May are typically the lowest cost
months of the year on the Idaho Power system by a substantial margin. Yet Idaho
Power's cost of service studies treat Mayas a high cost, peak month. This
misidentification of peak months is a very serious and consequential error.
HOW DOES THIS ERROR OCCUR?
The problem is that IRP identified load deficiencies and off system purchases are
not reasonable or appropriate substitutes for actual system peaks. Deficiencies
can occur for a variety of reasons, not the least of which is scheduled plant
maintenance. For most Northwest utilities, spring is the optimal time to tae
plants down for maintenance because power demands are low and hydropower
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generation is relatively high, making replacement power relatively (and
sometimes very) cheap. The fall months are, of course, the next best time to tae
plants down. Somewhat similar considerations apply to power exchanges and a
host of other factors.
HOW DOES THIS WEIGHTING ERROR AFFECT THE COST OF SERVICE
RESULTS?
It completely corrpts the results, and once again the result is an erroneous
transfer of costs from on-peak to off-peak.
PLEASE SUMMARZE THE CONSEQUENCES OF IDAHO POWER'S COST
OF SERVICE ERRORS THAT DILUTE ITS ACTUAL SEASONAL COST
DIFFERENCES.
There are two chief consequences. First, high load factor customers are allocated
a larger share of costs than they actually cause the power system to incur.
Conversely, low load factor customers are charged too little. This is not only
unfair; it is also terribly inefficient because it creates cross subsidies between rate
classes.
A corollar to this consequence is the undesirable effect that the
misallocation has on the valuable conservation and load management programs in
place and being developed here in Idaho for everyone's benefit. By proposing to
set rates that undercharge sumer peak costs and overcharge durng low cost
seasons, the proposed rates act in direct contradiction to responsible efforts to
conserve energy when it is most costly. In the longer-term, costs of service will
DIRECT TESTIMONY OF DENNIS E. PESEAU - 45
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be higher for all customers because peak loads will grow faster that average
energy consumption.
DO THE IDAHO POWER SYSTEM PLANNRS RECOGNIZE THIS RISK?
Yes. The perils of promoting on-peak load growth are discussed on page 1 of Mr.
Greg Said's workpapers, from which I quote an excerpt:
Efct of Load Growth. Peak load in the Idaho Power Company service
territory is growing twce as fast as the anua energy requirement. Going
forward, then, this growth wil lead to higher ramp rate requirements in the
sumertime and less available hydro capacity for managing the system.
The cost of reserves would then likely increase, which could increase the
integration cost for wind.
Page 1 (emphasis added).
DO THESE "COST AVERAGING" ERRORS OCCUR IN ALL FOUR IDAHO
POWER STUDIES?
Yes, and even without the errors I have previously described, and some others I
am about to explain, it renders all four studies completely unusable, in my
opInion.
ARE THERE ADDITIONAL ERRORS IN THE STUDIES OTHER THAN THE
"BASE CASE" IDAHO POWER STUDY?
Yes. As to the unweighted 12CP method, I propose to give that short shrift. It is
very much beyond the norms for cost of service studies, and I suspect it is only
inserted into Idaho Power's list of studies in an attempt to make the other studies
look more reasonable by comparson. My prepared testimony is already too long
to deal with a methodology the Commission has consistently rejected since 1987,
but I wil be more than happy to answer questions about it.
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PLEASE EXPLAIN WHAT is WRONG WITH THE OTHER TWO IDAHO
POWER METHODOLOGIES.
Let's begin with Mr. Tatum's "preferred" methodology, which he labels
3CP/Energy. Mr. Tatum's reasoning in support of this method goes something
like this-Idaho Power's natural gas peakers were built to serve peak load in the
three sumer months, so I will classify their entire fixed costs to demand. Ergo,
the remaining base load and intermediate plants weren't built to serve peak load,
and therefore all their remaining fixed costs, in addition to the 58% already
classified to energy on the basis of load factor, should also be classified as energy
costs.
Stated this way, the error here becomes readily apparent. The fact that
Idaho Power's gas peakers were built primarly to serve peak capacity demands
does not in any way disprove the basic premise of all cost of service studies,
which is that all generating plants are built to meet both capacity and energy
needs. In other words, you can't leap from the obvious trism that peakers are
primarly for peak load, to the supposition that other plants don't serve peaks too.
WOULD YOU PLEASE EXPLAIN THIS IN A LITTLE MORE DETAIL?
Let's deal with the theory first. Earlier in my testimony I explained there is an
extensive body of academic literatue demonstrating that the discipline of
economics canot determine a single correct theoretical allocation of joint and
common costs, such as the fixed capital costs of generating plants. These plants
all serve both demand and energy needs, but a proper allocation of costs between
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these classifications can only be determined by factors or considerations other
than economic theory.
But what economic theory can tell us, is that there are two, and only two,
allocations that are certainly wrong. These are to classify 100% of any plant's
fixed costs to either demand or energy, which of course is what Mr. Tatu has
done in his testimony by classifying the overwhelming majority of Idaho Power's
generating resources 100% to energy.
BUT THIS IS JUST THEORY. DOES IT HOLD UP IN THE REAL WORLD?
Yes. Let me ilustrate with a simple hypotheticaL. Let us suppose a very hot July
afternoon, which is typical for Idaho Power's system peak. Let us further suppose
that Idaho Power's system generating resources are exactly suffcient to meet this
two or three hour peak. For the puroses of this simple hypothetical, I wil ignore
a number of real world complications, such as the possibility of cheaper
purchased power, the need for spinning reserves, etc.
In this case, with all of Idaho Power's generating resources ruing at ful
capacity, which plants are supplying capacity and which are supplying energy?
The answer is they are all supplying both. In a plant engineer's terms, Idaho
Power is using the entirety of its "resource stack" to meet this peak demand. This
is no less true of the base load coal plants than it is of the gas fired peakers. And
without all the plants ruing simultaneously on peak, the system would
experience a brown out or black out even though not all the plants would
necessarily be required to meet the total energy load for the entirety of that same
peak day.
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1 My simple hypothetical peak load scenaro was created to demonstrate the
2 fallacy of Idaho Power's approach. But the real world operation ofa utility
3 system is so much more complex, and the same point emerges even more clearly.
4 In Idaho Power's case, its dispatchable resource stack generally consists of, in
5 ascending order of varable costs, several units on the hydro system, the four units
6 of the Jim Bridger coal plant, the Valmy coal plant's two units, and the gas fired
7 peakers. Each plant and each unit has unique operating and cost characteristics,
8 leading to an almost infnite number of possible operating scenaros.
9 By way of ilustration, let us assume we are looking over the shoulders of
10 the Idaho Power's dispatchers on a warm but not torrd June morning. The hydro
11 system is runnng at medium load for the season but with some available
12 additional capacity, Jim Bridger is ruing full out, one Valmy unit and the
13 peakers are off. But the dispatcher knows these resources will be insuffcient to
14 meet the coming afternoon peak load. If the coming peak is apt to be small, and
15 of short duration, maybe the dispatcher sacrifices a little water and meets it with
16 hydro facilities. On the other hand if temperatures are expected to continue
17 soarng though the next day, maybe the dispatcher fires up another Valmy unit,
18 paricularly if any excess power over peak needs can be sold to other utilties. On
19 the other hand, if it is a Friday maybe the dispatcher brings on a peaker, knowing
20 that loads will fall on the weekend, and it can then be shut down again and its
21 high fuel costs terminated. I could postulate many other scenaros, but I think the
22 point is made. All plants are used, both in theory and in fact, to provide both
23 capacity and energy.
DIRECT TESTIMONY OF DENNIS E. PESEAU - 49
IPUC Case No. IPC-E-07-0S
1 Q.
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HOW DO THESE ERRORS IN MR. TATUM'S PREFERRD
METHODOLOGY AFFECT THE CUSTOMER CLASS RATES?
They erroneously shift an enormous amount of costs from low load factor peak
customers to high load factor customers, over and above those costs shifted by the
"average cost" assumption and other errors I described earlier.
DOES MR. TATUM'S OTHER OPTION, THE "3 CPI12 CP" METHOD SHIFT
COSTS IN THE SAME WAY?
The effect on high load factor customers in this case is less dramatic, but there is a
shift nonetheless. In Micron's case, the effect is relatively small, and ifIdaho
Power's next peaker is a combined cycle unit with higher fixed costs than the
existing turbines, Idaho Power's 3 CP/12 CP method could actuly benefit
Micron. But even though the 3 CP/12 CP proposal might benefit Micron in the
long ru, I strongly urge its rejection.
WHY WOULD YOU TAKE THIS POSITION?
Quite apar from the fact that the methodology canot be squaed with sound cost
of service logic and theory, the attempt to pick and choose plants that will be
assigned to demand and energy in different proportions, as Mr. Tatu does, is apt
to lead to complete chaos in futue proceedings, as each pary tries to claim a
disproportionate share of low cost plants for its own individual load profie.
The irony is that if these are the new ground rules, which Mr. Tatum's
testimony suggests, then Micron could fare very well indeed. Because the flp
side of Mr. Tatum's argument, and one that is much more defensible, is we should
assign only base load plants to high load factor customers like Micron, and they
DIRECT TESTIMONY OF DENNIS E. PESEAU - 50
IPUC Case No. IPC-E-07-0S
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should not be responsible for any peakng costs. That implies a huge rate
decrease for Micron and other high load factor customers.
PLEASE SUMMARZE YOUR FINDINGS REGARDING THE IDAHO
POWER COST OF SERVICE STUDIES.
I have not addressed the unweighted 12 CP method, other that to note it is very
extreme and was rejected by the Commission long ago. What Idaho Power calls
the "Base Case" is anything but, primarly because of the use of very high
forecasted energy costs and the "averaging away" of very real on peak energy
costs to off peak periods. The remaining two studies are so fraught with logical
and practical problems as to be both useless, and, like Idaho Power's mishandled
Base Case, potentially dangerous.
HOW COULD A COST OF SERVICE STUDY BE "POTENTIALLY
DANGEROUS?"
Leaving aside the "scientific" merits of varous cost of service methodologies, it
is very obvious that adopting any of Idaho Power's proposed cost of service
methodologies would allocate seasonal costs opposite to their actul seasonal
incurence.
As I explained earlier, there was a rational basis for the Commission's
original decision 25 years ago to choose a cost of service methodology that
minimized the influence of peak costs. But this is no longer Idaho Power's
situation, and hasn't been for some time, as we can see in the steady decline in
Idaho Power's load factor from 68% in 1994 to 58% a dozen years later. All of us
who paricipate in these cases, including myself, have been too slow to recognze
DIRECT TESTIMONY OF DENNIS E. PESEAU - 51
IPUC Case No. IPC-E-07-0S
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this dramatic change. Peaking costs are now driving costs higher for everyone, to
the detriment of all. So we should be looking to adapt our cost of service to
recognize these changes, rather than vice versa. To adopt any ofIdaho Power's
proposed methodologies would fuher de-emphasize peak usage and fuher
promote the costly growth in sumer peak demand.
The disproportionate increase in peak demand usage of recent years has
argubly been exacerbated by a cost of service methodology that increasingly
underestimated sumer peak costs. These underestimated sumer rates, under
any reasonable interpretation of economic principles, parially caused additional
sumer peak consumption, to the point that the sumer peak is now growing
twice as fast as average consumption.
Under these circumstaces, it is not surprising that Idaho Power's system
peak is growing faster than its average demand. The cost of service study choice
is helping drive this disparty. Now Idaho Power is proposing to shift a huge
amount of costs, not on peak as any rational proposal would suggest, but off peak!
This will certainly exacerbate the problem. This promotion of peak usage is
doubly troubling when customers are, at the same time, paying for conservation
and demand side management programs.
AT LEAST THAT MAY BE BENEFICIAL TO IDAHO POWER IN THAT IT
MAKES REVENUES GROW.
Not in the least. Underpricing peak growth makes it much more likely that Mr.
Gale's revenue requirement shortfall forecast we discussed earlier wil come tre.
That is, regulatory lag will become a self fulfillng prophecy. The shareholders
DIRECT TESTIMONY OF DENNIS E. PESEAU - 52
IPUC Case No. IPC-E-07-0S
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are hur, just as the ratepayers are hur, by the acceleration of peak costs because
those costs are less likely to be recovered by average cost based rates. The result
is a revenue shortfall for shareholders and more rate cases for ratepayers.
HAVE YOU CONDUCTED A COST OF SERVICE STUDY THAT
ATTEMPTS TO REMOVE SOME OF THE EFFECTS OF IDAHO POWER'S
FUTURE TEST YEAR ASSUMPTIONS AND SEASONAL UNWEIGHTINGS?
I have made an attempt to do so that I believe fairly portrays the present cost of
service. But I want to stress that because the Company has not provided data on a
normalized and anualized basis in this case, no par can complete a traditional
cost of service study.
WHAT THEN DID YOU USE FOR DATA IN PREPARIG YOUR COST OF
SERVICE STUDY?
Due to the maner in which Idaho Power constructed the future test year,
historical data were available in its fiing and responses to data requests, but not
the corresponding normalizing, anualizing and varous regulatory adjustments
necessar to conduct our cost of service study.
Therefore, I was forced to use as the basis of revenues and expenses the
2007 data used in Idaho Power's study. To capture the true sumer and
nonsumer large capacity and energy cost differences, I calculated the summer
period peak costs using montWy weighted costs. The peak sumer months were
established as June, July and August by calculating the probabilties that monthly
peak loads (over the last recorded 10 years) were within 5% of Idaho Power's
DIRECT TESTIMONY OF DENNIS E. PESEAU - 53
IPUC Case No. IPC-E-07-0S
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anual system peak load. This roughly corresponds to the Company's pre-2003
capacity and energy weights that were computed using loss of load probabilities.
I made two other adjustments. Within the cost of service model, income
taes were allocated on the basis of taxable income of each rate schedule. Lastly,
the cost of service model classified cogeneration and small power production
("CSPP") purchases made by the Company into capacity and energy as reflected
by Idaho Power's system load factor.
PLEASE EXPLAIN THE REASONS FOR THESE CHANGES.
The monthly capacity and energy weights allow the cost of service model to
correctly reflect the high sumer peak load costs and help dampen the severe and
costly high rates of growth of the Company's sumer peak loads.
Income taxes can be apportioned in either of two ways in the cost of
service model: on either taxable income of each rate schedule, or on allocated
rate base. In my opinion it is more appropriate to allocate income taes on the
basis of taable income.
Finally, CSPP purchases in the aggregate provide the Idaho Power system
with both valuable capacity and energy, and in fact their rates are based on this
assumed provision of capacity and energy. For cost of service puroses, it is
appropriate to estimate these values with the system load factor.
PLEASE BRIEFLY SUMMARIZE THE RESULTS OF YOUR COST OF
SERVICE STUDY.
The full cost of service study and its results are contained in my Exhibit No. 506.
But, as I explained above, the convenient way to compare my study with others is
DIRECT TESTIMONY OF DENNIS E. PESEAU - 54
IPUC Case No. IPC-E-07-0S
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1 with the varous customer class's retur Indexes. The following table compares
2 the results of my study with those adopted by this Commission in 2003 and the
3
4 Q.
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11 Q.
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14 A.
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four proposed Idaho Power cost studies:
Retu Indexes Peseau /2003 Tatu Base Tatu Tatu Tatum
Micron Case Unwt.3CP/12CP 3CP/Ave
Residential (1)1.4 1.1 1.32 1.2 1.28 1.38
Gen Service (7).83 1.1 .82 .81 .82 .84
Gen Service (9)1.1 1.2 1.04 1.0 1.04 1.01
Industrial (19)1.1 1.2 .82 .74 .81 .68
Irrgation (24).06 .17 .30 .77 .42 .38
Micron (SC).97 1.4 .58 .47 .56 .32
DOE 1.29 1.2 .64 .37 .56 .41
Simplot 1.16 1.5 .66 .54 .62 .40
WHAT DOES THIS COMPARISON SHOW?
My cost of service study in this case, in contrast to Idaho Power's four cost of
service studies, is generally much more consistent with results found to be valid
by the Commission in the 2003 general rate case. Although the data in the present
case is not as verifiable as it might be, general recoinendations can be made
with respect to the allocation of any increase in revenue requirement to customer
classes.
HOW DO YOU PROPOSE THAT THIS COMMISSION ALLOCATE
REVENUE REQUIREMENT TO THE V AROUS RATE CLASSES IN THE
ABSENCE OF MORE PRECISE COST OF SERVICE DATA?
I believe that my proposed study generally apportions revenue requirement among
customer classes fairly. Referrng to both the "Peseaulicron" and the
"Commission 2003" colums in the table, all rate classes with the exception of the
Schedule 24 irrigation class, are nearly at or above respective cost of service.
DIRECT TESTIMONY OF DENNIS E. PESEAU - 55
IPUC Case No. IPC-E-07-0S
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These rate classes should be treated consistently with each other in terms of any
change in rates in this case. On the other hand, both of these studies, and Idaho
Power's as well, conclude that the irrigation class rates are far below cost of
service. Given the complexity of these cost of service issues, and the
compounded problems caused by introducing the estimates and projections of a
future test year, the Commission may wish to defer technical cost of service
findings to another venue. In the meantime, a fair and reasonable allocation of the
revenue requirement would be to set all rate classes, except for the irrgation
class, at an equal percentage increase or decrease, depending on the
Commission's ordered revenue change.
This equal percentage change to all non-irrgation rates would be
determined by that level of change necessar, after increasing the irrgation
class's rates by something greater than the average increase. I suggest an increase
of twce the system average, but I recognize this is a matter in which the
Commission wil have to exercise its judgment.
DO YOU HAVE ANY OTHER RECOMMENDATIONS TO MA IN THIS
CASE?
First, I want to reiterate my previous recommendation that the case be dismissed
if the forecasted test year canot be corrected. Second, Idaho Power's
accelerating peak load growth and deteriorating load factor are sufciently
alarming that I think the case for proactive Commission intervention of some sort
is overwhelming. Accordingly, I recommend that the Commission direct its Staff
to undertake an investigation of the problem and possible solutions. That
DIRECT TESTIMONY OF DENNIS E. PESEAU - 56
IPUC Case No. IPC-E-07-0S
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1 investigation should include the consideration of new load control and demand
2 side management solutions and a reconsideration ofthe W12CP cost of service
3 methodology and other rate design possibilities. After the Staff issues its report,
4 other interested paries should be given an opportunty to comment and make
5 fuher suggestions.
6 I want to stress, however, that any proactive response canot be expected
7 to succeed if it has to overcome the headwinds posed by the irrational cost of
8 service shift and ratemaking policies Idaho Power is proposing in this case.
9 Furhermore, it would be grossly unfair to ask high load factor customers to both
10 subsidize peak growt via the rate structure, while simultaneously subsidizing
11 programs that attempt to curb that growth.
12 Q.DOES THIS CONCLUDE YOUR TESTIMONY?
13 A.Yes.
DIRECT TESTIMONY OF DENNIS E. PESEAU - 57
IPUC Case No. IPC-E-07-0S
e
CERTIFICATE OF SERVICE
e
I HEREBY CERTIFY that on this 6th day of December, 2007, I caused to be served a
true and correct copy of the foregoing by the method indicated below, and addressed to the
following:
Jean Jewell
Idaho Public Utilities Commission
472 W. Washington Street
P.O. Box 83720
Boise, ID 83720-0074
Baron L. Kline
Monica B. Moen
Idaho Power Company
P.O. Box 70
Boise, ID 83707
email: bkline§idahopower.com
JohnR. Gale
Vice President Regulatory Affairs
Idaho Power Company
P.O. Box 70
Boise, ID 83707
email: rgale§idahopower.com
U.S. Mail
X Hand Delivered
Overnght Mail
Facsimile
E-Mail
U.S. Mail
i Hand Delivered
Overnght Mail
Facsimile
E-Mail
U.S. Mail
X Hand Delivered
Overnight Mail
Facsimile
E-Mail
Peter J. Richardson
Richardson & O'Lear
515 N. 2ih Street
Boise,ID 83702
email: peter§richardsonandolear.com
ïU.S.Mail
Hand Delivered
Overnight Mail
Facsimile
E-Mail
Eric L. Olsen
Racine, Olson, Nye, Budge & Bailey
Charered
P.O. Box 1391
201 E. Center
Pocatello, Idaho 83204-1391
email: rcb§racinelaw.net
elo§racinelaw.net
Anthony Yanel
29814 Lake Road
Bay Vilage, Ohio 44140
email: yanel§attbi.com
DIRECT TESTIMONY OF DENNIS E. PESEAU - 58
IPUC Case No. IPC-E-07-08
A U.S. Mail
Hand Delivered
Overnght Mail
Facsimile
E-Mail
à U.S. Mail
Hand Delivered
Overnght Mail
Facsimile
E-Mail
.
Dr. Don Reading
6070 Hil Road
Boise, Idaho 83703
email: dreadingcmmindspring.com
LotH. Cooke
United States DOE
1000 Independence Ave. SW
Washington, DC 20585
Weldon Stutzman
Donovan Walker
Idaho Public Utilities Commission
P.O. Box 83720
Boise, Idaho 83720-0074
Michael Kurz
Boehm, Kurtz & Lowr
36 E. Seventh Street, Suite 1510
Cincinnati, OH 45202
Dale Swan
Exeter Associates
5565 Sterrett Place, Suite 310
Columbia, MD 21044
Dennis Peseau
Utility Resources, Inc.
1500 Libert Street, Suite 250
Salem, OR 97302
DIRECT TESTIMONY OF DENNIS E. PESEAU - S9
IPUC Case No. IPC-E-07-0S
x U.S. Mail
Hand Delivered
Overnight Mail
Facsimile
E-Mail
i Waa Beli¥efetl \).S. mfh (Overnight Mail
Facsimile
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'X Hmid Deliveied \,. ~ .MAil
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\J.~.t1/H\\ )
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STATEMENT OF OCCUPATIONAL AND
EDUCATIONAL HISTORY AND QUALIFICATIONS
DENNIS E. PESEAU
Dr. Peseau has conducted economic and financial studies for regulated
industries for the past thirt-five years. In 1972, he was employed by Southern
California Edison Company as Associate Economic Analyst, and later as Economic
Analyst. His responsibilties included review of financial testimony, incremental cost
studies, rate design, econometric estimation of demand elasticities and various areas
in the field of energy and economic growth. Also, he was asked by Edison Electrical
Institute to study and evaluate several prominent energy models as part of the Ad
Hoc Committee on Economic Growth and Energy Pricing.
From 1974 to 1978, Dr. Peseau was employed by the Public Utilty
Commissioner of Oregon as Senior Economist. There he conducted a number of
economic and financial studies and prepared testimony pertaining to public utilties.
In 1978 Dr. Peseau established the Northwest offce of Zinder
Companies, Inc. He has since submitted testimony on economic and financial
matters before state regulatory commissions in Alaska, California, Idaho, Maryland,
Minnesota, Montana, Nevada, Washington, Wyoming, the District of Columbia, the
Bonnevile Power Administration and the Public Utilties Board of Alberta on over one
hundred occasions. He has conducted marginal cost and rate design studies and
prepared testimony on these matters in Alaska, California, Idaho, Maryland,
Minnesota, Nevada, Oregon, Washington and in the District of Columbia. He has
EXHlBIT NO. 501, P., 1 013
Case No.: IPC-E-Q7-De
D. Pesau, Micron
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also conducted cost and rate studies regarding PURPA issues in the states of
Alaska, California, Idaho, Montana, Nevada, New York, Washington, and
Washington, D.C.
Dr. Peseau holds the B.A., M.A. and Ph.D. degrees in economics.
He has co-authored a book in the field of industrial organization entitled,
Size. Profits and Executive Compensation in the Large Corporation, which devotes
a chapter to regulated industries.
Dr. Peseau has published articles in the following professional journals:
Review of Economics and Statistics, Atlantic Economic Journal, Journal of Financial
Management, and Journal of Regional Science. His articles have been read before
the Econometric Society. the Western Economic Association, the Financial
Management Association, the Regional Science Association and universities in the
United Kingdom as well as in the United States.
He has guest lectured on marginal costing methods in seminars in New
Jersey and California for the Center of Professional Advancement. He has also
guest lectured on cost of capital for the public utilty industry before the Pacific Coast
Gas and Electric Association, and for the Executive Seminar at the Colgate Darden
Graduate School of Business, University of Virginia.
Dr. Peseau and his firm have partcipated with and been members of the
American Economic Association, the American Financial Association. the Western
Economic Association, the Atlantic Economic Association and the Financial
EXHIBIT NO. 501, P., 2 of 3
Case No.: IPC-E-U7-Q
D. Peseau, Micon
,
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eManagement Association. He was formerly a member of the Staff Subcommittee on
Economics of the National Association of Regulatory Utilty Commissioners.
Dr. Peseau has been President of Utilit Resources, Inc. since 1985.
i
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I
EXHIBIT NO. 501, P., 3 of 3
Case No.: lPC-E-D7-o
D. Peseau, Micron
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REVIEW OF UTILITY
RATEMAKING PROCEDURES
Report to the Iowa General Assembly
January 2004
Iowa Utilties Board
Diane Munns
Mark O. Lambert
Ellott G. Smith
EXHIBIT NO. 502
Case No.: IPC-E-07-D8
D. Peseau, Micron
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REVIEW OF UTILITY RATEMAKING PROCEDURES
Report to the Iowa General Assembly
Table of Contents
I. Executive Summary............................................................. .... ...1
II. Introduction.. ........ .................. ..... ... ......... .... ..... .... .... ....... ..........4
II. General Rate Regulation Proposals.. ...... ..... ........ ....... .... .... ..........6
1. Option of a Future Test Year.................................................................7
2. Deferred Expenses and Revenues Outside the Test Year........................13
3. Government-Mandated Costs Outside a Rate Case.................................14
4. Use of Single-Issue Ratemaking. ..................................................... .....16
5. Adjustments to Year-End Data.............................................................17
6. Temporary Rate Implementation..........................................................18
7. Interest Rates on Refunds...................................................................20
8. Electronic Delivery of Proposed Rate Increase Notices...... ............ .........22
9. Notification Within 30 Days of Filng a Proposed Rate Increase.............. ..23
10. Rates for a Fixed Period......................................................................24
IV. Telecommunications Proposals. .... ....... ..... ... ..... ... ......... .... .........26
11. Initial Rates When Entering Price Regulation.........................................27
12. Initial Access Rates When Entering Price Regulation..............................28
13. More Frequent Modifications of Price Plans.................................. .........29
14. 60-Day Extensions for Good Cause......................................................30
15. Economic Development....... ............................................................. ..31
16. Bond Requirements......................................................................... ...32
17. Annual Price Increases for Non-Basic Services......................................33
18. TSLRIC Price Floor.............................................................................33
19. Individual Exchange Pricing Flexibilty..................................................35
20. Allow Increases in Access Rates............ ........................................... ...36
21. Sale of Exchanges......... ............ ......... ........................... ............... ......37
22. Classified Directory Advertising...... ......... ............ ............... .................38
V. Energy Effciency Proposals.... .... ..... .......... ... ..... .......... ...... ... .....39
23. Exempt Industry from Energy Efficiency Programs and Costs............. ....39
24. Establish a Statewide Administrator for Energy Efficiency Programs... ....42
25. Require all Utilties to Conform to the Same Standards for Energy...........43
Effciency Plans
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I. EXECUTIVE SUMMARY
Background
Senate File 458, passed during the 2003 Legislative Session, directs the Utilties
Board (Board) to review current ratemaking procedures and report its findings to
the Legislature by January 5, 2004. The law requires two standards to be
applied to the review of the proposed changes: the cost effectiveness of the
proposal and the degree of accuracy of matching rates (revenues) with costs.
Interested persons were invited to file proposals for legislative change to
ratemaking procedures. The Board identified 25 of these proposals for review.
Following is a brief summary of the Board's findings.
General Rate Regulation Proposals
Ten proposals were considered that relate to rate of return regulation. The
electric and gas investor-owned utilities in Iowa are rate regulated. The three
largest telecommunications companies are price regulated, but retain the option
of returning to rate regulation.
Most of the ten proposals are already available under Iowa law or are allowed in
appropriate situations. For example, one proposal is the option of using a future
test year to set rates. A future test year is based on estimates or forecasted data
rather than on the relationship between historical costs and revenues. However,
Iowa currently uses a hybrid approach that considers both historical and
projected data for use in setting rates.
In recent years the Legislature has made several major changes in law that
require the Board to consider projected data when setting rates. In the 2001
Session utilties were allowed to seek advanced ratemaking principles for new
electric generation. A provision was also included for utilties to present a plan
and budget for addressing emissions for generating facilties fueled by coal and
allows the reasonable costs of implementing the emissions plan to be included in
rates. In 2003 the Legislature directed the Board to consider capital
infrastructure costs that would not produce significant additional revenues and
would be in service within nine months after the conclusion of the test year.
Capital cost changes that would occur within nine months after the conclusion of
the test year and are associated with new generating plant for which the Board
granted advanced ratemaking treatment are also allowed under the new law.
These changes were made to spur new investment and mitigate risk to the
utilties.
The two standards set by the legislature in Senate File 458 were applied to the
option of a future test year. The Board found that adding this option would
significantly increase the costs of ratemaking during the transition and probably
in the long-term. The Board also found that use of a future test year over the
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current hybrid approach would not necessarily provide rates that more accurately
reflect a utiity's cost of providing service.
Other proposals relating to general rate regulation that are already available
under current law or have been allowed in specific circumstances are deferred
accounting, automatic adjustments of rates outside a rate case, single-issue
ratemaking, year-end adjustments, and electronic delivery of proposed rate
increases.
Implementing temporary rates within ten days and reducing the interest rate on
refunds are not found to be in the best interests of ratepayers. Both the current
gO-day review period and the existing interest rate on refunds protect the
customer from excessive temporary rates while giving the utilty rate relief until
the final rates are decided.
The Board did not come to a conclusion on the proposal for customer notification
within 30 days after the filing of a proposed rate increase. Some potential
postage savings could be achieved, because the utilty could send a rate case
notice as part of the regular biling. However, this would mean some customers
would receive the notice before others, which could cause confusion.
The final proposal in this category is to allow for a ratemaking plan that would
establish rates for a fixed period of time. The Board has approved multiyear
ratemaking plans iA the past based on a settlement among the parties to a
general rate proceeding. This has provided rate predictabilty and has protected
customers. The Board, however, believes that the current method of negotiating
a multiyear plan with the parties is preferable to allowing the utilty to propose a
plan without the agreement of the other parties.
Telecommunications Proposals
Because the three largest local exchange carriers are price regulated, their
prices do not directly reflect costs. Therefore, the legislative standard that a
proposal should result in rates that more accurately reflect a utilty's cost of
providing service does not apply to the telecommunications proposals. The
Board applied the second standard, cost effectiveness, to the proposals and
found that some of them would increase regulatory costs without offsetting
benefits. For example, decreasing the interval for allowed price plan
modifications from three years to two years would tend to increase the
associated regulatory costs. Likewise, the proposal to shorten the time available
to conduct price regulation modification proceedings would result in a more
concentrated procedural schedule and an increase in the associated costs for the
Board and all parties. It also poses the risk of a flawed decision due to an
incomplete record.
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Several other proposals would delete provisions required for a company to enter
price regulation. These include the requirement for a telecommunications carrier
that is changing from traditional rate regulation to price regulation to either
reduce its basic communications service rates by three percent or to establish
new rates through a rate case. Another proposal would delete the requirement
that access service rates be reduced when a company enters price regulation.
While all existing rate-regulated carriers have opted for price regulation, new
rate-regulated carriers might be created (by exceeding the 15,000 line threshold
for regulation) through growth or sale of exchanges. In addition, a price
regulated carrer may return to rate regulation and then decide at some future
time to re-enter price regulation. Therefore, the requirements proposed to be
deleted might serve a purpose in the future and do no harm by remaining in the
law.
Energy Effciency Proposals
Three of the proposals relate to energy effciency. The first recommendation is
that customers with an aggregated electric peak load of greater than two
megawatts (MW) be exempt from energy effciency participation and cost
recovery on a voluntary basis. This proposal does not pass the cost
effectiveness standard because the reduction of energy effciency funding from
large industrial customers would diminish future energy effciency savings. It
also has the potential to increase future utilty rates by reducing cost effective
energy effciency, thus forcing utilties to pass through to ratepayers the costs of
acquiring additional energy resources.
The second proposal would establish a single, statewide administrator for energy
effciency programs. The Board found this proposal would require a
transformation of energy effciency programs in Iowa and is outside the purview
of Senate File 458's directive to review ratemaking procedures.
Finally, a proposal was suggested that the Board be given the authority for
approval and oversight of the energy effciency plans of municipal and
cooperative utilties. Current law only requires that these utilties file plans with
the Board. This proposal does not strictly apply to ratemaking methods and,
therefore, does not fi into the framework of this review.
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II. INTRODUCTION
The Iowa Utilties Board (Board) has prepared the following report in response to
the mandate of the General Assembly as set out in Acts of the 80th General
Assembly, 2003 Session, Senate File 458, Section 150. The General Assembly
directed the Board as follows:
The utilties board shall initiate and coordinate a
review of current ratemaking procedures to determine
whether different procedures would be cost-effective
and would result in rates that more accurately reflect
a utilty's cost of providing service to its customers in
Iowa. The board shall allow the consumer advocate
division of the department of justice, the rate-
regulated utilties, and other interested persons to
participate in its review. The board shall report the
results of its review to the general assembly, with
recommendations as appropriate, on or before
January 5, 2004.
On July 14, 2003, the Board issued an order initiating an inquiry, identified as
Docket No. NOI-03-2. Interested persons were invited to file, by July 25, 2003,
proposals for changes to ratemaking procedures, with the primary focus on
changes that would require legislative action. After review of the submitted
proposals, the Board issued an order on September 2, 2003, which identified
ratemaking procedures for consideration and established a procedural schedule.
The participants were asked to file comments by September 15, 2003, and reply
comments by October 3,2003. Three workshops were held on November 7,
2003, for further discussion and to give participants an opportunity to respond to
questions by Board staff. The three separate workshops addressed: (1)
proposals involving all rate-regulated utilties, (2) proposals affecting only
telecommunications utilties, and (3) energy efficiency proposals. Additional
comments subsequent to the workshop were allowed by November 14, 2003.
Participants filing information in the inquiry included the Consumer Advocate,
Division of the Department of Justice (Consumer Advocate), MidAmerican
Energy Company (MidAmerican), Owest Corporation (Owest), Interstate Power
and Light Company (IPL), Iowa Telecommunications Services, Inc., d/b/a Iowa
Telecom (Iowa Telecom), Ag Processing, Inc. (Ag Processing), and Aquila, Inc.,
d/b/a Aquila Networks (Aquila). Atmos Energy Corporation, Deere & Company,
and the Iowa Consumers Coalition expressed interest in and followed the
proceedings. Agri Industrial Plastics, HON Industries Inc., IPSCO Steel Inc.,Alcoa Mil Products, Box USA, Curries and Graham, Elkem Carbon, General
Mils, Griffn Pipe Products Co., Griffin Wheel Company, Lehigh Cement Co.,
Nestle Purina, North Star Steel, Penford Products, PMS Industries, Inc.,
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Progressive Foundry, and Quaker Foods & Beverages joined with Ag Processing
in addressing the energy efficiency proposals.
The Legislature gave the Board two standards to apply to the proposed changes:
the cost effectiveness of the proposal and the degree of accuracy of matching
rates (revenues) with costs. These two standards have been applied to each of
the proposed changes. This report examines the identified proposals,
summarizes the comments of the participants, and reaches conclusions under
the standards given.
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II. GENERAL RATE REGULATION PROPOSALS
Description of Current Iowa Ratemaking Practices for Electric and Gas
Iowa currently uses a hybrid approach that considers both historical and
projected data for use in setting rates. A rate proceeding before the Board
begins with historical data. This is adjusted for known and measurable changes
in costs not associated with a different level of revenue and revenues not
associated with a different level of cost that wil occur within twelve months from
the date of filing by the utility. Typically, an historical test year is the latest
calendar year; however, a test year can be any prior 12-month period of audited
information. In a rate proceeding, the utility files actual data for the historical test
year and proposes adjustments to revenues, expenses, assets, liabilties, and
capital issuances. These changes are known as "pro forma adjustments." The
Board may also consider other proposed changes under its authority in Iowa
Code § 476.33(4) to "consider other evidence." Once the Board decides which
adjustments are allowed and the resulting revenue requirement, the utilty files
new rates that remain in effect until a new case is brought. The goal in setting
rates is to take the data from the historical test year and make adjustments to the
historical data that more closely reflect the expected costs and revenues going
forward.
The fundamental principle in determining rates is the matching principle. Unless
there is a matching of costs and revenues, the test year is not a proper one for
fixing just and reasonable rates. The inclusion of costs without matching
revenues may produce excessive rates. The inclusion of revenues without
matching costs may deny the utilty reasonable rates. The relationship between
costs and revenues for the test period used, whether historical or projected, and
the validity of that relationship, constitutes one of the most vital steps in the
determination of just and reasonable rates.
Although the Iowa statute has an historical test year as its base, the Board is not
restricted from looking beyond the test year in appropriate situations. The statute
expressly grants the Board the authority to consider other evidence, and the Iowa
Supreme Court has affrmed the Board's interpretation that this provision allows it
to consider adjustments that are outside the test year. Proposed adjustments
are considered on a case-by-case basis to ensure they meet the requirements
and concerns of the matching principle.
In the past several sessions, the Iowa Legislature has implemented several
major changes that look beyond the historical test year in the setting of rates. A
2001 law allows utilities to seek advanced ratemaking principles related to major
capital investments in generating facilties. Utilties may seek binding regulatory
assurances related to the treatment of these investments in future rates. Utilties
may also present a plan and budget for addressing emissions from rate-
regulated electric power generating facilties that are fueled by coaL. The law
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requires the reasonable costs of implementing the plan to be included in rates.
Finally, during the 2003 Session, the Legislature required the Board to consider
capital infrastructure costs that wil be in service within nine months after the
conclusion of the test year and wil not produce significant additional revenues.
Capital cost changes that wil occur within nine months after the conclusion of the
test year and are associated with new generating plant for which the Board
granted advanced ratemaking treatment are also allowed under the new law.
These changes were made by the Legislature to spur investment in generation,
mitigate risk associated with environmental requirements, and mitigate regulatory
lag with respect to major capital additions and cost of capitaL. In each case, they
require the Board to consider projected data when setting rates.
Two other aspects of Iowa's ratemaking approach require discussion in order to
understand proposals for change. Utilties are able to implement rate increases
that are consistent with previously accepted regulatory principles within three
months of a rate filing. These temporary rates give relief to the utilty during the
pendency of the 10-month ratemaking process. If final rates are lower than those
collected during the proceeding, refunds are made with interest set at a statutory
leveL. Iowa's statute also allows for the automatic adjustment of rates in certain
circumstances. These adjustments have historically been used to flow through
the cost of purchased gas and the cost of power purchases, among other things.
1. Option of a Future Test Year
a. Description of the Proposal
IPL proposes the option of using a future or projected test year to determine
rates. This method is based not upon the relationship between historical costs
and revenues, but rather on estimates or forecasted data. All the components
that would be considered when determining rates, including the revenues,
expenses, rate base, working capital, and capital structure, are based on
estimates and projections.
IPL's specific proposal would limit the use of projected data to a two-year period
and would allow the utilty to choose whether it would use an historical period or
a projected, forecasted period for setting rates. IPL, Iowa Telecom, Aquila, and
MidAmerican support an optional future test year as long as the option to choose
either a historical or future test year is allowed. Consumer Advocate, Ag
Processing, and Qwest argue against the option of a future test year.
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b. Review of Other States
Survey results filed by Consumer Advocate 1 indicate that 30 states use historical
test periods, seven states use future test periods, eight allow utilty choice, and
six use a hybrid form. IPL responded with the results from three different
surveys2 that categorize the test periods in slightly different ways, making strct
comparisons diffcult. 3 However, approximately 30 states continue to employ the
historical test period. Other states use a variety of alternatives ranging from
utilty choice, hybrids/partially forecasted, to fully forecasted test years.
Of the closest Midwestern states, South Dakota, Missouri, Indiana, and Kansas
use historical test periods. Minnesota and Illnois allow utilty choice of historical
and future test periods. Wisconsin requires a future test year.
Ilinois has the option of a future test year, but requires an independent audit of
projections to explore the link between actual data, assumptions, and projections.
Illnois also has a significant number of rules that apply specifically to a filing
based on a future test year. Companies that choose the option of a future test
year must also file information to support an historical test year. The
appropriateness of either an historical or future test year might be an issue of
controversy in any particular case. According to Ilinois staff most companies
prefer the historical test year because they find these requirements to be
burdensome.
Minnesota also allows the option of a forecasted test year. However, its
Commission does not allow the forecasted test year to reach out very far. For
example, if a case is filed December 31,2003, the company might use a 2004
test year. By the time the 10-month process ends, the end of the forecasted test
year is close. In this example, the Commission would not allow a 2005 test year.
Wisconsin mandates a future test year for large utilities. Wisconsin staff states
their regulatory approach is very hands on and requires frequent audits. Major
energy utilties in Wisconsin file a rate case every year unless they are under a
rate freeze. Wisconsin staff also notes a strong auditing or accounting
1 Taken from Consumer Advocate Witness Brosch's Attchment MLB-3 entitled, "Survey of State
PUC Test Period Approaches as of September 2003."
2 The three surveys are:
· Regulatory Research Report, Table entitled "Regulatory Practices Test Period/Rate
Base/Statutory Case Lag Summary of All 50 States plus the District of Columbia," 2003.
· Deloitte & Touche, "Questar: State Commissions Test Year Survey," 2000.
· NARUC, Table entitled "Type of Test Year Used in determining Rates: Electc and Gas
Utilties," Compilation of Utilty Regulatory Policy 1995-1996.
3 For example, of the three surveys provided by IPL, one identified six states as using future test
year periods (similar to Consumer Advocate's finding), but the other two identied twice that
many.
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background is required to effectively review a forecasted test year and most of its
auditors are CPAs. In addition, a larger staff is required to review a future test
year; the Wisconsin Commission has 185 staff, double the number for the Board
and Consumer Advocate combined.
Both Illnois and Minnesota require that future test year filings also include
historical period data so that comparisons can be made between the estimated
data proposed for the projected test period and actual data from the historical
test period. Wisconsin, which requires future test year filings, also requires
annual reports of a utilty's costs and revenues to allow the Commission to
continually review and assess the reasonableness of a utilty's forecasts.
c. Is the Proposal Cost Effective?
IPL states that a projected test year would not significantly increase the cost of
utilty ratemaking. It suggests that the only additional cost is the hiring of
consultants well versed in capital budgeting, a short-lived expense until the
Board and Consumer Advocate staff are trained in this area. Furthermore, while
new issues would arise from using a projected test year, many issues argued
today would disappear. As for IPL's own costs, it already does forecasting and is
comfortable with its abilty to project items such as customer levels and usage,
fuel costs, and capital expenditures.
At the same time, IPL acknowledges that more frequent or annual rate reviews
may be necessary because of the lack of annualization adjustments in a
projected test year. Based on the company's experience, a future test year
regulatory approach is more active and requires frequent audits. IPL also states
that weather normalization, a necessary element in a future test-year case, would
require additional staff expertise. IPL's sister-company, Wisconsin Power and
Light Company, normalizes revenues for weather based on a regression model
and analysis. In Iowa, weather normalization is routinely used in natural gas
proceedings. However, though utilties advocated the use of weather
normalization for electric cases in the 1980s, normalization was never approved
and it has not been a component in more recent electric cases. Thus, both the
Board and Consumer Advocate would need to acquire expertise in this area.
Finally, the company agrees that Consumer Advocate would need new skils to
evaluate projected versus historical data in a rate case4 because it is unlikely
these skils could be found in an outside auditing firm.
MidAmerican acknowledges that the cost of preparing a case with a proposed
future test period would be greater because data for an historical period must be
filed at the same time. However, to the extent the use of the forecast test period
4 Since the mathematics related to thermodynamics are well known and much natural gas usage
is heating related, normalization is a relatively simple procedure for natural gas. Though
electrcity usage related to heating and cooling can be fairly predictable, usage of electrcity for
other purposes is far less predictable. making normalization much more complex for electncity.
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better reflects the cost of providing service during the period in which the rates
are in effect, some future rate case proceedings and costs may be avoided. The
company argues that the rates based on the forecasted data already include any
increase in costs that may occur when the rates are in effect, and so a utilty
should not have to file another rate case until it has moved beyond the
forecasted period.
Consumer Advocate believes the future test-year option would dramatically
increase the cost of utilty ratemaking in Iowa. Both the cost of a proceeding and
number of proceedings would increase. Consumer Advocate's expert states that
future test years are inherently more diffcult to prepare, document, investigate,
and verify, causing the utilty, the consumer representatives, and the regulatory
agency to invest more resources in the process of regulation. There also would
be new issues related to the use of projections, such as adjustments for inflation
and calculations of productivity.
Ag Processing's main concern is that the use of future test years wil add
litigation costs to the point where industry's involvement in the process is
precluded. In addition, use of future test years wil cause an increase in rate
case-related workloads for Board members, Board staff, and Consumer
Advocate.
Thus, it is evident there is no consensus among the participants on the cost
effectiveness of this proposaL. The information filed shows there would be
transition costs as staffng levels and skils are changed to accommodate for an
additional ratemaking method. The review of other states indicates a need for
additional staff including economists, statisticians, auditors, and CPAs. A
number of rulemakings would be necessary. Litigation would probably increase
with a new approach to ratemaking. It appears from the record there would be
long-term costs associated with the change for a number of reasons:
· Frequency of rate cases may increase, especially if a future test-year
approach similar to Wisconsin's is used.
· If the company files a future test-year option, other parties to the case may
file the historical test-year option. This would necessitate evaluation of
simultaneous historical and future rate cases, increasing the work, the cost,
and the time required for the proceeding.
· A more active auditing role seems essentiaL.
· New issues appear likely with a future test-year filing.
· Additional costs are associated with a possible independent audit. 5
Sin Ilinois Commerce Commission Docket No. 92-0357, MidAmerican used some elements of a
future test year and required the services of an independent auditor. The cost of that audit was
$132,000.
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d. Would the Proposal Result in Rates That More Accurately
Reflect a Utilty's Cost of Providing Service?
IPL believes that a projected test year provides a better matching of rates with
costs and revenues that wil occur at the time those rates wil be in effect. This
would benefit customers because changes in costs are included in rates sooner,
allowing customers to receive better pricing signals and lessening differences
between current customers and future customers. The company asserts that a
projected test year benefis the utilty by providing for full regulatory assurance
and up-front guidance on planned expenditures. Under a future test year, the
Board would provide proactive input into capital investment decisions and other
expenditures before those decisions are implemented. Under the current
standard, the Board is limited to defining public policy through the denial of costs
that have already been incurred.
IPL contends that costs and revenues in an historical test year are as much as
two years old before rates are finalized. IPL questions the value of auditable
data and the assumption of a constant historical relationship between revenues
and costs, especially during times of major capital investment.
The company also asserts that a projected test year benefits the utilty by
potentially reducing the cost of capitaL. It states that the financial community
prefers a regulatory structure that allows a projected test period because there is
less risk that prudent capital expenditures wil not be recovered in rates. Less
risk to the stockholders may mean improved ratings that may result in reducing
the cost of capitaL.
MidAmerican states there is little difference between a future test period and an
historical test period that reflects appropriate post test-year adjustments. At the
same time it argues that two fundamental points need to be kept in mind: (1)
ratemaking exists to determine the reasonableness of rates that wil apply
sometime in the future, after the rate filing has been made, and (2) there is no
inherent reason why historical data from the company's books and records more
accurately reflects what wil happen in the future than forecasts wil.
However, Consumer Advocate disagrees that a future test year would result in
rates that more accurately reflect a utilty's cost of providing service. Further, the
Consumer Advocate states it is impossible to know if a forecast is accurate until
the forecast period has passed. It also argues that what is important in
establishing accurate rates is the relationship between revenues and costs. As
long as a recent and internally consistent historical test year is used, the
revenue/cost relationship wil generally be representative of ongoing conditions
and the revenue requirement wil be accurate for the period when rates are in
effect. Consumer Advocate also believes that the mere potential to reduce
regulatory lag with a future test-year option is not worth the risk of reducing or
eliminating the critical incentive the current system provides Iowa utilties to
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operate effciently. Regulatory lag tends to replace some of the effciency
incentives that are otherwise blunted by cost-of-service regulation. It also
rewards or punishes a utilty in the short run by attributing cost and revenue
changes to shareholders between rate cases. Consumer Advocate adds that
notwithstanding IPL's assertion concerning the staleness of historical data, the
use of a future test year wil increase the probabilty of inaccuracy, excess profits,
and excessive rates. Further, a future test year relies heavily on utility
management's expectations, and it is likely that management wil err on the high
side when estimating future costs and on the low side when estimating future
revenues.
Consumer Advocate believes giving the utilty the option of a future test year
invites abuse of the regulatory process. It would mean that utilty companies
would submit the type of filing most beneficial to shareholders at any given point
in time. Making an option available allows gaming of the system to the
advantage of the part that is granted the option to choose.
Ag Processing states that a future test-year filing does not necessarily reflect a
more accurate cost of service. It believes there are more appropriate ways to
match revenues and costs and send price signals to customers.
The Board has the authority to allow additional evidence into the record after the
initial filing. In a situation where only part of a proposed adjustment is known at
the time of filing, additional updates have been allowed up through the date of
the hearing. The Board also is able to consider other evidence outside the test
period. Recently, the Board allowed year-end rate-base adjustments for major
plant additions and considered several changes to capital structure that occurred
after the test year. It also indicated a willngness to consider alternatives to the
thirteen-month average capital structure.
In addition, the Legislature has recently enacted provisions that address the
desire for regulatory input into capital investment decisions, regulatory risk
related to environmental requirements, and regulatory lag. Iowa Code § 476.53,
enacted in 2001, provides for advanced ratemaking principles for new generation
and transmission projects. Both IPL and MidAmerican have requested and
received advanced ratemaking principles that are binding on future ratemaking.
These advanced ratemaking principles have led to the following capital
investment in Iowa:
· IPL's 568 MW natural gas-fueled generation plant in Mason City
· MidAmerican Energy's 540 MW natural gas-fueled generation plant in
Pleasant Hil
· MidAmerican Energy's 900 MW coal-fueled generation plant in Council
Bluffs
· MidAmerican Energy's 310 MW wind energy facilty in northwest Iowa
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Iowa Code section 476.6(25) allows utiliies to look to the future with respect to
emission controls on coal-fired generating plants. Utilties are required to
develop a plan and budget designed to meet environmental requirements. The
Board then must include the reasonable costs of implementing the plan in rates.
Amendments to Iowa Code § 476.33 enacted during the 2003 Session allow the
Board to consider capital infrastructure investments in service within nine months
after the conclusion of the test year and cost-of-epital changes that occur in that
time period for new generating plants, thus lessening regulatory lag related to
large investments.
Since these statutory provisions allow for future costs of large investments to be
considered in a rate case, a future test year would provide little additional benefit.
e. Conclusion
The Board concludes the implementation of the future test-year option would
significantly increase costs of ratemaking during the transition and probably in
the long-term. It also finds use of a future test year over the current hybrid
approach will not necessarily provide rates that more accurately reflect a utilty's
cost of providing service. Iowa's hybrid approach allows for consideration of
evidence outside the historical test year. The implementation of two new laws
allowing regulatory assurances for capital investment decisions and for
environmental improvements; and the abilty to consider capital investments and
cost of capital changes after the test period alleviate the major concerns raised
by IPL.
2. Deferred Expenses and Revenues Occurring Outside the Test Year
a. Description of the Proposal
IPL proposes that deferred accounting would be a useful procedure to support afuture test-year case. Large abnormal expenses and revenues occurring outside
a test year could be accounted for in a deferred account and reflected in the
utilty's next rate case.
Consumer Advocate argues that deferred accounting is just a variation of piecemeal, or
single-issue, ratemaking. Single-issue ratemaking occurs when a cost or revenue item
is considered without considering other costs and revenues. Not generally accepted,
single-issue ratemaking can lead to an improper matching of costs and revenues, and
potentially unjust and unreasonable rates. Consumer Advocate states the inclusion of
costs without matching revenues wil produce excessive rates; the inclusion of revenues
without the matching costs wil deny the utilty reasonable rates. It adds that the
relationship between costs and revenues is an important component in the
determination of just and reasonable rates. If deferred accounting is used appropriately
and is properly matched to other costs of providing service, it need not result in single-
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issue ratemaking. However, deferred accounting can distort the revenue requirement if
other offsetting cost savings or revenue increases are ignored.
b. Is the Proposal Cost Effective?
Allowing the use of deferred accounting in a rate case would not have a
significant financial impact on the cost of the rate proceeding since the Board has
current authority to allow deferred accounting.
c. Would the Proposal Result in Rates That More Accurately
Reflect a Utilty's Cost of Providing Service?
If the costs in a deferred account are properly matched against related cost
reductions and revenues, they could result in rates that more closely reflect the
cost of providing service. Since a utilty controls the information concerning
these accounts, there is the potential that this matching may not occur.
d. Conclusion
Deferred accounting is available under current law. Utilties may request
accounting rulings from the Board. However, rulings made outside a rate case
are only advisory, not binding, when considered in a future rate case. The utilty
may account for costs and revenues in a deferred account but the Board retains
the authority to determine whether the costs and revenues wil be allowed in
rates, and under what terms and conditions.
3. Government-Mandated Costs Outside a Rate Case
a. Description of the Proposal
MidAmerican proposed that government-mandated expenditures should be
recovered through an automatic adjustment rather than through a rate case.
These are non-fuel items such as capital projects for the relocation or
improvement of any facilties when the expense of these items are verifiable or
mandated by a government entity or are outside of the control of the utilty's
management. Mandated expenses could also include emission control
equipment, manufactured gas plant remediation, or expenses related to
upgrading facilties to thwart terrorism attacks. MidAmerican says the automatic
adjustment mechanism is particularly appropriate in situations where it is
desirable to obtain a better matching of costs and revenues in a specified period
than could be accomplished by infrequent rate cases.
Aquila believes that government-mandated expenditures should be recovered
through an automatic adjustment including expedited recovery for mandated non-
fuel expenses and those required by the Offce of Homeland Security.
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Consumer Advocate argues that government-mandated costs should not be
automatic because they are not volatile and may be offset by other cost changes
that are not verifiable. Furthermore, automatic recovery provides no incentive to
minimize costs. Consumer Advocate believes the Board currently has the
authority to provide for automatic adjustment clauses.
b. Is the Proposal Cost Effective?
Although Iowa law allows for automatic rate adjustments, the types of expenses
discussed in this proposal have not been allowed. The Board would have to
approve any new automatic adjustment. The cost involved would be the
additional time necessary to establish the automatic adjustment and to verify that
reasonable accounting was used for all of the major elements of the proposed
government-mandated expenditure.
c. Would the Proposal Result in Rates That More Accurately
Reflect a Utilty's Cost of Providing Service?
An automatic adjustment would allow a utilty to recover the cost of government-
mandated items in a timelier manner and without the necessity for a rate case;
however, it may also allow for piecemeal ratemaking if consideration of matching
cost and revenue changes do not take place.
d. Conclusion
Iowa law already allows for the automatic adjustment of rates outside a rate case.
For example, the Board currently allows automatic adjustment of electric rates for
fuel-related costs. These fuel costs are beyond direct control of management, are
subject to sudden significant changes in level, are an important factor in
determining costs, and are readily, precisely, and continually segregated in
accounts. Automatic recovery is also allowed for energy effciency expenditures.
All amounts recovered through automatic adjustments are subject to prudence
reviews.
The types of expenses discussed in this proposal have not been historically
allowed to be collected through an automatic adjustment mechanism. Any
automatic adjustment mechanism for government-mandated costs would need to
meet similar criteria as fuel-related costs and meet the requirements of the
matching principle to ensure just and reasonable rates.
It should be noted that when a utilty has voluntarily agreed to forego rate
increases for a period of years, allowance of new automatic recovery for
expenses incurred during this period would change the conditions under which
the agreement was reached. Any new automatic adjustments should not be
implemented during such a period.
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4. Use of Single-Issue Ratemaking
a. Description of the Proposal
MidAmerican proposes that rate adjustments producing small amounts of
revenue should be allowed outside of a general rate proceeding.
b. Is the Proposal Cost Effective?
If a utilty were allowed to file for a rate increase based upon a single cost item,
there would likely be an increase in filings and the regulatory costs would
increase. Some, if not most, of these single-issue ratemaking filings could
become time-consuming contested cases and would place an additional burden
on Board, Consumer Advocate, and third-part resources. There may be a
decrease in general rate cases since there would be allowances for rate recovery
between rate cases.
c. Would the Proposal Result in Rates That More Accurately
Reflect a Utilty's Cost of Providing Service?
The proposal does not provide for the proper matching of costs and revenues
that is essential in setting just and reasonable rates. For the filing to result in
rates that more accurately reflect a utilty's cost of providing service, any
corresponding cost savings or additional revenue would have to be reviewed for
possible offset. Allowing the costs to be recovered without the offsetting
revenues or reduction in costs would not accurately reflect the cost of providing
service. Rates are best established in a general ratemaking proceeding where
all the costs and revenues can be reviewed. If a utilty is allowed to file for rate
relief every time an increase in costs occurs, rates wil likely be higher than underexisting procedures.
d. Conclusion
This proposal would allow a utilty to file for rate increases without having to give
consideration to offsetting decreases in costs or increases in revenue in violation
of the matching principle. The Board has allowed single-issue ratemaking
outside of a general rate case in specific cases. However, single-issue
ratemaking should be a rare occurrence and not become an accepted way of
setting rates.
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5. Adjustments to Year.End Data
a. Description of the Proposal
IPL proposes changes to require the Board to consider data that wil become
known and measurable within twelve months from the commencement of the
proceeding. The proposal would require that any pro forma adjustments be
made using a year-end test year, rather than a thirteen-month average test year.
b. Is the Proposal Cost Effective?
The proposed statutory changes would make it mandatory for the Board to
consider all post test-year changes, not just changes that exist at the
commencement of the proceeding. As previously stated, the Board has the
abilty (and has used it) to adjust historical test year data beyond known and
measurable changes related to data that exists as of the date the proceeding is
filed regarding known and measurable changes in costs not associated with a
different level of revenue and revenues not associated with a different level of
cost, that wil occur within twelve months from the date of filing by the utilty. The
authority to do so exists in Iowa Code § 476.33(4), which states the Board's
abilty to "consider other evidence". In recent proceedings, the Board has
considered these types of issues under its current statutory authority. Therefore,
the resources needed to review a rate case in the context of the statutory
changes would be similar to the resources needed currently. Given the Board's
use of already existing authority, the benefis of changing the statutory language
are not obvious.
c. Would the Proposal Result in Rates That More Accurately
Reflect a Utilty's Cost of Providing Service?
The use of a year-end rate base and capital structure could reduce regulatory lag
to some degree by allowing full rate treatment for items that were placed in
service late in the test year. Potentially, this could make rates better reflect the
costs of the utilty.
Consumer Advocate states that an annualized, or year-end, test period is
somewhat more conducive to known and measurable changes beyond the test
year end and does have the effect of eliminating up to six months of regulatory
lag. However, Consumer Advocate believes there is no advantage to the use of
either the average or year-end-annualized test period approach that cannot also
be achieved with known and measurable changes routinely considered by the
Board under existing ratemaking procedures. It points out that the average test
year reduces the dependence on only a single data point, which could be
distorted by unusual accounting entnes or one-time transactions. Also, by using
the average approach, the income statement presentation is simplified.
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Customer levels, employee levels, depreciation, propert taxes, and other costs
do not need to be adjusted to reflect year-end annualized numbers.
With respect to the capital structure, a thirteen-month average capital structure
for determining rates helps to eliminate distortions caused by issuance of new
preferred stock and long-term debt, equity infusions, security retirements, and
fluctuations in retained earnings. Further, if a year-end test year were used, any
of these one-time events could distort the capital structure, making the capital
ratios unrepresentative. The thirteen-month average capital structure averages
these potential events over several months to provide a better match between
capital structure, rate base, revenues, and expenses.
Any capital issued outside the test year is not normally included in the capital
structure because it would violate the matching principle. The thirteen-month
average capital structure supports the thirteen-month rate base. By using data
for only one point in time, the utilty could include an equity infusion in the month
of December such that the rates are set using a capital structure with a higher
common equity ratio. Common equity is the most expensive source of capital
available. Therefore, the customers' rates would support a higher overall cost of
capital than rates determined using an average capital structure.
d. Conclusion
The current statute already allows the Board to consider year-end evidence. Any
proposal to use a year-end test year, annualize single items, or approve
appropriate pro forma adjustments is reviewed and considered on a case-by-
case basis by the Board to ensure compliance with the matching principle.
6. Temporary Rate Implementation
a. Description of the Proposal
IPL proposes to modify the way in which temporary rates are implemented.
First, it proposes to eliminate language requiring the Board to apply previously
established regulatory principles in determining the appropriate level of
temporary rate relief. Second, IPL proposes to reduce the time frame for
implementation from 90 days to 10 days.
In addition, IPL argues that since its proposal would eliminate three months of
review for temporary rates, the ten-month period allowed to reach a final decision
should be reduced to seven months.
MidAmerican agrees with IPL's proposal but argues the utilty should have the
option of implementing temporary rates immediately or using the existing
temporary rate procedures.
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Consumer Advocate argues that if temporary rates are implemented
immediately, without review, the ten-month time frame should be extended to
allow for additional review of the final rates.
b. Is the Proposal Cost Effective?
Implementing temporary rates within 10 days, rather than allowing 90 days for
review and approval, would probably not add costs to the rate proceeding.
However, the ultimate issues to be decided in the case would remain. Most of
the costs that would be saved by eliminating analysis and approval of temporary
rates would be shifted to the remainder of the case. Therefore, it would not likely
be cost effective, or even possible, to shorten the schedule in the manner
proposed. The proposal to shorten the schedule appears to proceed from the
assumption that temporary rate review requires a significant part of the first 90
days, but experience has shown that review of temporary rates actually requires
very little in the way of Board resources.
c. Would the Proposal Result in Rates That More Accurately
Reflect a Utilty's Cost of Providing Service?
The current statute allows 90 days for implementation of temporary rate
increases. Increases based on established regulatory principles are allowed. If
the utilty seeks recovery for expenditures that have been denied in the past or
are new, it must wait until the Board has approved the expense before it can
recover these expenses in rates. IPL proposes to eliminate the requirement in
the statute that past Board precedent is used in determining an appropriate
increase for temporary rates. Instead, the entire increase sought by the utilty
could be implemented in temporary rates. Consumer Advocate argues there
must be some reasonable constraint on temporary rates. If temporary rates are
put into effect without any regulatory review, utilties could use ratepayers as a
source for instant rate relief when cash flows are below desired levels.
Consumer Advocate contends that refunds with interest at the end of a case are
not a suffcient remedy for customers who may have diffculty paying their utilty
bils even before the rate increases.
Eliminating the use of previously established regulatory principles when setting
temporary rates would probably make temporary rates less, rather than more,
accurate. The use of previously established regulatory principles results in
temporary rates that are based on prior Board decisions and are therefore likely
to bear a reasonable relationship to the final rates. Removal of this factor would
mean potentially unlimited temporary rates that would have no relationship to
actual costs.
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d. Conclusion
IPL's initial proposal removes the requirement that temporary rate increases be
based on previously established past Board precedent. It also would implement
temporary rates in 10 days rather than the current gO-day period for review and
approvaL. In the workshop IPL indicated a wilingness to use past Board
precedent in order to implement temporary rates without Board review. The
Board believes that the current requirements, past precedent and a gO-day
review period provide a balance that gives the utilty expedited rate relief while
the case progresses. It also protects the customer from excessive temporary
rate increases.
Because IPL's proposal would essentially eliminate three months of the review
process, it also proposes to reduce the current ten-month rate case review period
to seven months. Even if review of temporary rates is removed, other issues
requiring a full ten-month proceeding remain. Verification of company figures
and calculations often require the full time period.
Finally, if the statutory method is modified to allow implementation of temporary
rates within 10 days, the current interest rate should be retained. (See the next
issue.) The relatively high interest rate serves as a constraint on the utility to
discourage it from using the ratepayers as a source of funds during the pendency
of the proceeding.
7. Interest Rates on Refunds
a. Description of the Proposal
Iowa Telecom proposes to reduce the interest rate on refunds. The current rate
is two percentage points above the 24-month consumer loan rate. MidAmerican
states the rate should: (1) not be so high that it works to prevent utilities from
seeking needed rate relief, (2) be high enough to discourage utility use of
excessive temporary rate relief for financing purposes, and (3) adequately
reimburse customers for the use of their money. MidAmerican encourages the
Board to consider using a public utilty bond yield as representative of the utilty's
credit quality. This long-term rate has a built-in penalty. Short-term financing
would be used as a source of funds during the period that temporary rates are in
effect. Since short-term rates are cheaper than long-term sources, the utilty
would pay a "penalty" if the utilty were required to make refunds to the
customers. The customers would receive a return higher than any other
investment option of the same duration and recover their opportunity cost of
lending funds to the utilty.
Consumer Advocate opposes any change to the interest rate on refunds. It
argues that to reduce the current average commercial bank rates to money
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market account rates would be unfair. Many customers have outstanding credit
card balances, bank loans, and mortgages at higher rates of interest such that
their cost of money would likely be higher than money market rates of retum. It
is Consumer Advocate's position that the current rate is more indicative of the
opportunity cost of capital for ratepayers. Also, utilties may be overly aggressive
in temporary rate requests if extremely low interest rates are used. This would
make customers involuntary investors in the utility. The interest rate should be at
or above the average consumets marginal cost of capitaL.
IPL proposes to implement temporary rates immediately without Board review
and approval and did not propose any change to the current rate. Qwest also
agrees that no change is needed.
b. Is the Proposal Cost Effective?
Changing the refund interest rate has no cost implications for implementation. It
would simply require looking to a different indicator to set the rate.
c. Would the Proposal Result in Rates That More Accurately
Reflect a Utilty's Cost of Providing Service?
The interest rate is not intended to reflect a utilty's cost of providing service. It is
intended to partially or fully compensate the consumer for the use of money
during the pendency of a rate case. It may also provide a deterrent to collecting
excessive temporary rates. The 24-month consumer loan rate is a borrowing
rate, not an investment rate. Based on August 2003 data, this rate was 11.95
percent, slightly lower than the Credit Card Plan (All Accounts) rate of 12.49
percent for the same time period. After adding the additional two percent, as
required in Iowa Code, the refund rate exceeds the credit card plan rate. The
high refund rate that results from this formula suggests that it is used to protect
the customers from the utilty charging excessive temporary rates. If excessive
temporary rates were in effect, a customer may be forced to either use funds that
would have been used to reduce other debt obligations such as credit cards or to
borrow funds to pay the bil. This assumption seems consistent with the position
held by the Consumer Advocate. If a refund were necessary, the consumers
would more likely receive their opportunity cost of money, providing better
protection than if a lower rate were used.
MidAmerican suggests that the existing rate is excessively punitive and should
be lower. MidAmerican argues that the public utilty bond yield is more
representative of the utilty's credit quality. It also claims that the customer would
eam a higher retum than for any other investment for that duration. However,
the concem may not be with recovering a customer's opportunity cost of
investment, but instead with covering customers' potential borrowing rates.
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Most Iowa utilties have bond ratings in the range of A to Caa. Using August data
from the Merchant Bond Record, the yields for an "A" rating and a "Baa" rating
ranged from 6.78 percent to 7.08 percent. The recommended bond utilty rate is
almost half of the current consumer rate. Refunds would be based on the
individual rating of each utilty.
d. Conclusion
The proposed change is neutral with respect to cost-effectiveness but would not
tend to produce more accurate rates. The existing rate is set at a high level to
protect customers from paying excessive temporary rates. If the utilty wishes to
avoid paying this rate on potential refunds, it should only request reasonable
rates when it files for temporary relief. As discussed previously, IPL is proposing
a statutory change that would allow it to collect temporary rates immediately
without Board review. If this change were allowed, the need for maintaining the
current refund rate is even greater.
8. Electronic Delivery of Proposed Rate Increase Notices
a. Description of the Proposal
MidAmerican proposes a statutory change to allow for electronic delivery
of proposed rate increase notices.
b. Is the Proposal Cost Effective?
The comments lack suffcient information to conclude that electronic delivery of
customer notices meets the cost-effectiveness criterion. Electronic delivery
potentially reduces notice costs. However, the utilities that commented on this
proposal indicated that their systems currently are not set up for electronic
delivery of customer notices. No comments estimated the start-up or program
change costs and ongoing expenses. Qwests comments concerning the use of
radio and television indicate that "electronic" may be too broad a term, but no
alternative term was offered.
c. Would the Proposal Result in Rates That More Accurately
Reflect a Utilty's Cost of Providing Service?
The form of notice does not significantly affect costs recovered as part of the rate
proceeding.
d. Conclusion
By the conclusion of the inquiry, MidAmerican indicated that Iowa law may
already allow for the electronic delivery of rate notices. Qwest and MidAmerican
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encouraged the Board to allow for electronic delivery and allow parties to work
out details in the future as technologies develop.
9. Notification Within 30 Days of Filng of a Proposed Rate Increase
a. Description of the Proposal
MidAmerican proposes to change the notice period from no more than 62 days
prior to filing to within 30 days after the filing. The utilty would then be able to
work with the Board to include preliminary public comment hearing dates and
locations on the notice of proposed rate increase filings. The practical effect of
the change may not be very great; however, under current law, most utilties
send the notice the day before they file the rate case. Under the proposed
change, they would be able to delay the notice by two or three days and then
include the notice in the regular bils to customers.
b. Is the Proposal Cost Effective?
The change would not incur additional costs and might allow utilties to avoid the
postage expenses associated with mailng separate rate case notices. It could
be beneficial, as the Board might have the opportunity to set up preliminary dates
and locations for public comment hearings and work with the utilty to list the
dates and locations in the notice of proposed rate increase to its customers.
However, that can be accomplished with the existing process as welL.
c. Would the Proposal Result in Rates That More Accurately
Reflect a Utilty's Cost of Providing Service?
The time frame for rendering the notice does not playa role in the costs that are
considered as part of the rate proceeding.
d. Conclusion
The statute currently requires rate-regulated utilities to provide notice of a
proposed rate increase within sixty-two days prior to the time the application for
the increase is filed with the Board. The proposed change would potentially
allow utilties to save postage costs, because they could send a rate case notice
as a part of the regular billng cycle. However, this would mean different
customers would receive the notice at different times, which could cause
customer confusion. Thus, it is diffcult to say if the proposed change would be
an improvement.
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10. Rates for a Fixed Period
a. Description of the Proposal
MidAmerican proposes to establish a mechanism that would allow filing
and approval of a ratemaking plan that would establish rates for a fixed
period of time. While Consumer Advocate has agreed to such multiyear
plans in the past, it opposes the Board having the authority to approve
such a plan over its objection.
b. Is the Proposal Cost Effective?
This proposal may be a more cost-effective method of ratemaking since it would
set rates for a certain period of time. A review of the rate cases filed since 19816
shows that rate cases are often filed at three-or four-year intervals. Allowing a
utilty the option of filing a multiyear ratemaking plan could fi this pattern.
Both the utilty and Consumer Advocate would be precluded from bringing cases
during this time. That could result in savings if a rate case would otherwise have
been filed. But the savings only exist if a rate case would otherwise have been
brought, Le., rates need to be changed.
A multiyear rate filing would be subject to the same analysis with respect to costs
of review as was discussed in the future test year filing. The utilty, the Board,
Consumer Advocate, and interveners would be required to consider data
concerning an historical test year as well as data concerning a future period.
This future data would be very similar to data to support a future test year.
MidAmerican has suggested that other alternative ratemaking procedures might
be proposed to determine the rates under a multiyear rate plan. Any alternative
ratemaking procedures could increase the cost and complexity of a ratemaking
proceeding.
c. Would the Proposal Result in Rates That More Accurately
Reflect a Utiltys Cost of Providing Service?
MidAmerican argues that allowing for multiyear ratemaking would provide rate
predictabilty for businesses, government, and other Iowa consumers. However,
the predictabilty of rates does not necessarily mean that the rates accurately
reflect a utilty's cost of service. In periods of high inflation and increasing costs,
it is likely a utilty would make annual filings, and in times of low inflation and
declining costs, the utilty would file a multiyear plan. Consumer Advocate would
then be precluded from filing a rate reduction case. While there may be public
policy objectives achieved through multiyear plans that are mutually beneficial to
6 Attchment A to Consumer Advocate's Reply Comments filed October 3,2003.
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the utilty and to its customers, more accurately reflecting a utilty's cost of
providing service is not a primary goal or a likely result.
d. Conclusion
This proposal would make a statutory change to allow the utilty to propose and
the Board to approve a multiyear rate plan. There have been several periods
when multiyear agreements have been approved by the Board based upon a
settlement among the parties to a general rate proceeding. This method of
setting rates for a period of time has provided rate predictabilty and has
protected consumers. MidAmerican has recognized that current procedures
have worked to its benefit as well as the benefit of customers. The current
procedures in which the parties negotiate a multiyear plan and bring it to the
Board for its approval is a better method of developing rates that are set for a
fixed period.
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KE C. GUIN
. Guvor
STAn OF NEVADA
PUBLIC UTITI COMMSSION OF NEVADA
i 150 Ea William Sir
Ca Cjtý, Nev 89701.3109
Potia (775) 68107 · Fax [phone] .
Sta(775) 68101 · Fax [phone] .
htt://pue.stte.nv.us .
,
RURA NEAD
557 W. Silv Str No. 20SEJ, Nevad 89)
(75) 738-4914 . Fix (775) 778-68 -.. ..... ../I
SOU NEVAD OFFJ101 Co CC Dr., Sui 2S
Us Veg Nead 89109
(102) 4861210 . Fax [phone]
'May 10,2006
Loren Ma1ewich
Dir of the Legislatve Coun Buu401 S. Ca Str
Caron City, Nevad 89701-4747
RE: The Public Utities Commiion of Nevada's Report to the 74'" SesiOD of the
Nevada Legilature OD A1tematies to the mstorieal Test Year Metodology
Used by Publie Utiti in Nevada .
De Mr. Maewch:
Secon 7 of Nevada Senate Bil 238 ('sa 238"), pa at the 73M Session of th Nevad
Legisle, dite the Public' Utities Common of Nevad (the "PUeN to exlore
altetives to the historica test year methodology curtly us in Nevada for gener ra
aplications filed by public utties. The PUCN conduc an inesgaon ino th ma withthe assistace of the Reguatry Opons Sta of the PUCN, th Bur of Coer .
Protecon, public utlities operang in Nevada and other inte pares. Addtionaly, the
. PUCN held a worksop in th ma to prvide all inteed paes an opport pr
their .comments and suggestons.
sa 238 di the PUCN to submit a wr rert of its fidigs and reention to the
. Diector of the Legislative Counl Buru for trmitt to the 74th Seson of th Nevad
Legila no late th Octobe t, 200. Pu to ths ditive, the PUCN ha' dr a
report contag its fings an remmendtions atthed heo.
Should you have any questons or conc plea conta my Admve Attorney,
Cassaa Cordova, at (1 2) 486-7233.
Enclos
Ca Citei71) 68100
CONSUMEDMSlO:La Veg-(02) 4826 0d Am-l-6, Ex 681~
EXHIBIT NO. 503
Case No.: IPC-E-07-D
D. Peseau, Micron
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. '. ...~ .-.
REPORT TO THE 74TI SESSION OF TH NEVADA LEGISLATU:
ALTERNATIVES TO TH HISTORICAL TEST YEAR METHODOLOGY FOR
SETTING PUBLIC UTILITY RATES IN NEVADA
Public Utilties Commssion of Nevada
May 10,2006
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TABLE OF CONTENTS
I.NEVADA SENATE BILL 238 1
II.HISTORICAL TEST YEAR 2
III.METHOD USED BY COMMISSION TO GATHER COMMENS AND DATA 4iv.ALTERNATIVE RATEMAlNG METIODOLOGIES USED IN OTIR
JURISDICTIONS 5
V.ALTERNATIVE RATEMAG METHODOLOGIES" TO TI HISTORICAL
TEST YEAR 5
a.Option 1 ~ Futu test year with all elements fuly foreasted to reflect the
"period rates are in effect"6
b.Option 2 - Hybrid test period th sta with the most recent i 2-month
historical data and in whch all major rate cas elements ar adjuste for
"reasonably known and meable" data to reflect the peod rates are
Ineffect 7'
c.Option 3 - Hybrid test peod that sta with the most recent 12-month
historical dat and in which all major rate cas elements ar adjustd for
"reasonably known and meaurle" data up to 7 -month afr the general
rate case fiing date 8
d. Coinission',s Recommendaon: Option 2, Hybrid Test Period 8
VI.DISCUSSION OF THE ALTERNATI RA TEMAG
METHODOLOGIES 9
a.The rate impact on customers and whether the methodology would result
in rates that more accutely reflect the cost of providing serice 9
b.The cost effectiveness of the metodology 11
c.The fisca impact on stte and loc agencies 11
d.The procedurs and mechansms necessa to implerhent the methodologies 12
e.Any other matters the paries deem appropriate 13
i.Rate Indexing 13
Ü. True~Up Process'14
iii. Filng Reguiements 14iv. Telecmmuncaons Caer: Non-Rur Incumbet Lo Exche
Compaes .14
VII.COMMISSION RECOMMNDATIONS 17
VIII.PROPOSED LEGISLATION TO AUTHORI AN ALTERNATIE
RA TEMAG METHODOLOGY: THE HYBRI TEST PERIOD 19
ATIACHMENTS
ATIACHMENT i
ATIACHMENT 2
ATIACHMEN 3
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...1. NEVADA SENATE BILL 238
The Nevada Legislatue passed Nevada Senate Bil ("SB") 238 at its 73id Session: .SB
238 became effective on Jtie 14,2005. Section 7 ofSB 238 directed the Public Utilties
Commission of Nevad ("Commssion") to open an investigatory docket to "...study. exane
and review the varous processes, theories and methodolowes tht may be use to estblish just
and reasonable rates in cases involving genera rate applications filed by public utilities." Over
the past several year there has bee mounting concer that in a rapid growt sta such as
Nevada, the historical test year methodology may not be the most accurte methodology in
deterning genera.l rates. Therefore, the Legislatue specificaly reuested tht the Comnission
open an investgatory docket to explore alteratives to the historica test year methodology used
in Nevada for cass involving genera rate applications fied by public utities.
Pusuant to ths legislative diretive, on July 27, 2005, the Commssion opened
Commission Docket No. 05-7048 to explore alternative'ratemakg methodologies to the
historical test yea methodology for general rate cases. Ths mater was conducte by the
Commssion purt to the Nevada Revised Statutes ("NRS'') and the Nevada Administative
Code ("NAC"), Chapters 233B, 703, ~d 704. SB 238 fuher direted the Commssion to
submit a wrtten reprt of its findings and recommendations to the Director of the Legislative
Counsel Bureau for tranmittl to the 74th Session of the Nevada Legislatue no later th
, October 1, 2006. Ths report is mae pursuat to the Legislative dirtive.
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II. HISTORICAL TEST YEAR
Public utilties are considered natura monopolies afecte with a public interest. A
naturl monopoly works within a specific service area, and generly builds and operates large
expensive 'equipment with lower unt cost at incrsing levels of output to produce and supply
an essential everyday service. Direct competion with a natual monopoly is uneconomical
since it would require duplicate investents in simlarly large expensive equipment. The lack of
competition in the public utility's servce area allows the utility to restrct output, rase prices and
collect monopoly profits. The public interest view of reguation is to protec cusomers agait
these practices for a serice th is essential to everyday life. As a resut, public utilties ar
subjected to regulation, and the role of reguation is to provide a substitute for the economic
contrls of competition in assurng fair prces and adequate seice to cusomers.
In Nevad~ the Public Utilities Commission's mechansm for settg fai prices (rates)
and protecting the customer is baed on a historical te year and is codfied in NRS 704.110(3).
Puuat to ths statute, if a public utility fies a genera rat ca with the Commssion to chage
the rates, the Commission reviews the reorded results of operations for the most ret twelve
(12) months that data wa available. Essentially, the procedur for calculatig rates is.to add up
the varous costs incurd in providing sece durng a reent 12-month period, commonly
referred to as the historical test-year, and divide that by the sales volumes (e.g.. kilowatt hour
"kWhs" or therm). Additionally, a limited updte for known and meaable events tht occur
within six months afr the end of the historical test yea is also permitted. The cost of
providing servce include operating and maitenance expenses, depreciation and amorttion
expenses. ta expense, interest expense and profit. Investors receive a retu on their invesent
via that porton of rates covering interest and profit (cost of equity). Oter thgs being equa, if
the costs of servce increas, rates increase.
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The basic assumption underlying the use of a historical period for settng futue'~ates is
that historica conditions ar sufficiently predictive of likely futue cirumtaces to sere as a
reliable method for predictng futue costs. Historical cost have the added benefit of offerig
ready verification. However, under rapidly changing conditions, like the vas and continuous
growt experienced by Nevada utilities, historica costs ca fail to accurtely predict fue costs
or allow for the timely reovery of new investents. In addition to their rapid grwt Nevada's
public utilities are coping with industr-wide chalenges associated with changing use
chacterstics. changig technologies and changing wholesae market strctues. Ifunt costs
are reasnably const, the use of a historica t~st year is a, viable ratemakg methodology. but
to account for the raid growt and changes curntly being experienced by Nevad's public
utilties using a test yea with historical costs can be chalenging and ineffective.
In today's envionment, timely rates captung new:investments and operating costs are
an importt sour of growt-related revenue for the utlity. The new revenue also allows for
. an imprved capita stctue and lower capita cost. Without revenue tht matches the cost of
providig servces, Nevada's utilities will reui lare amount~ of debt ald equity fi~cings to
build the necessar infrctue to sece its grwt. Ths ficing results in customer rates
that ar much higher due to higher capita costs. A Ïinancially strong public utilty with
investent grade credit is in,the be interst ofèusomers and will ultiately lower a
custoRler's rates over the life of the new investments compar to a utlity with weaker crt
ratings.
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III. METIOD USED BY COMMISSION TO GATIER COMMNTS AND DATA
SB 238 dircted the Commission to conduct its investigation with the help of interested
paries, including the Reguatory Operations Sta oithe Commission ("Sta'), the Conswnets
Advocate and the Buru of Consumer Protection in the ofce of the Attorney Genera ("BCP'j,
each public utity operating in Nevad and all other interested persons. On August 26, 2005,
the Prsiding Offcer commence the investigation by requeing comments frm interested
pares to be filed by October 31, 2005. The Commission received and reviewed comments from
the followig: jointly from Sierra Pacific Power Company and Nevada Power Company (''te
Companes"); Verizon; Utiities, In.; Sprit; Southwest ~ Corpration ("SWG"); Southern
Nevada Water Autority ("SNWA"); Newmont Mining Corpration ("Newmont"); AT&T;
Nevada Rural ILECs; Sta; and the BCP (collectively referrd to herein as "the Commentors").
The Commentors provided the Commssion with suggestions for alterntive ratemag
methodologies and provided inormon on methodologies usd in other jursdictions.
Based 'on these iitiaI comments, the Commssion was able to develop several alterntive
ratemaking methodologies for discussion by the Commentors. On December 15, 2005, the
Commssion issued a second request for comments and Notice of Workshop, scheduled for
Februar 7, 2006, tò'discuss these alternatives. The Commssion reeived and reviewed
comments from the second reuest from the following Commentors: the Companes; SWG;
SNW A; Newmont; AT&T; Nevada Rural ILECs; Sta; and the BCP. At the workshop, the
pares were given an opportty to mae a short presntation of their comments and to provide
the Commssion with any other proposas not discussed in their wrtten comments.
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IV. ALTERNATIVE RATEMAG METHODOLOGIES USED IN OTHR JUSDICTIONS
Many of the Commentors referenced a stdy released by the Nationa Association of
Regulatory Utility Commissioners (''NARUC'') in 1994-1995.1 The stdy showed tht
approximately 24 percent of junsdictions indicated tht they use fuly forecasted test year. In
the West, Californa, Oregon and Uta utilize either a fuly forecased or a 12-month forecas test
year. Californa utlizes a fuly forecas test year for both electrc and gas utiliies. Historic
. data is fied and then updated as much as possible. Oregon,allows all utilities the option of using
either a futue or historic test year. Uta allows its gas and electrc utlities to choose either a
fully forecasted test perod, or some combination of histrical and futue month in the test
period utilizg a 12-month foreas. (See Attchment 1). .
V. ALTERNATIVE RATEMAG METHODOLOGIES TO HISTORICAL TEST YEAR
As discussed above, the Commssion identified several distict alternve ratemang
methodologies, The metodologies differ frm one another in how they incorprate cost levels
from a speified perod int~ rate though the rateakng proces. The Commission chose th
of these options and asked the Commentors to address the merits of each. The firs option .
("Option i") utilies a fuy forecased fue tes year based on esates and foreas, which .
mayor may not be based on a historical test year. The second option ("Option 2") is a hybrd
approach that begins with the historical conditions and then, af the application has been fied,
makes adjustments for all reasonably known and meable data thugh the rate effective
period, which is data tht is not fuly recorded on the utiity's books and records when the
. historica tet year ends, such as new investents and expens chages. The thd option
("Option 3") also begins with historical conditions, but is more restctive than Option 2 becuse
it does not extc:nd into the rate effecve period. For each of thes options, the "period rates ar
in effec" is defined as the first year rates go into effect. For example for rate effective on
Januar i, 2006, the "period ras are in effect" is defined as Janua 1,2006 though Decmbe
31,2006. Each of these oi;ions is discussed in deta below.
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i This stdy has not be upted by NARUC since 1994-1995.
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a. Option 1 - Futue test year with all elements fuly forecate to reflec the ''period
rates are in effect"
A futue test year can be based on the most reent 12-month historica da with
adjustments that estimate and fuly forecas the costs of servce to reflec the period rates are in
effect, or the enti futu test year can be based solely on estmate and forec. Regaress of
its basis, using a futl test year would be the most effective method to account for the impacts
tht rapid inastrctu and load growt ca impose on a utility and its customer. But it is not
without controvery. It is controversial because the us of estimated and forecate data is not
basd on actu, verifiable, auditable information. Inead,. it is comprised of sometimes
subjective estmates and forecasts of futu biling detenninants, revenues, expenses and rate
base. Because these estimates and forecas may be subjective, they may yield the leas accurte
results in tenns of uneaonable rates, which ca be either too high or too low. For instance,
paries to a ratemag procedig have a vested interest to keep rates as high or low as possible.
The closer the cost of servce are to actu verifiable costs the less bias rate will be.
There ar, however, severa advantaes to usin a fuly forecased fu test yea verus
a historical test year. The fi is collectig the expectd costs of service in raes improves the
financial position of the utility, thus lowerg its capita costs. Utilizing a fuly forecas fue
test year also improves the utility's revenue position, which is an importt soure of growt
related revenue for the utilty. Another is economic effciency:2 when utity rate reflect the
costs of service tht are expeted to occur during the period rates are in effect, conser will
more effciently choose how to use the utilty's serces, Le., thugh the purchase of energy-
effcient appliances, though the purchae of products and serces that promote energy
conservation, or by using less energy '(e.g., tug down the therostat).
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i Consistnt wi priciples of economic effciency, price (i.e. rates), should reflect curnt cost insofa as
possible. Cuomers should receive a "corr" price signal and those who cause costs to be incured wiU be
responsible for paying for them. Paying for costs on a curnt basis helps to keep rates predictale and avoids fue
rae shocks when "catch up" payments would otherwse need to be made.
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b. Option 2 - Hybrid test period that sta with the most reent 12-Inonth historica data
and in which all major rate case elements are adjusted for "reasnably known and
meaiible,,3 data to reflect the period rates are in effect
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Ths method is refered to as a hybrid test peod because it is a combination of historica
data and estiated data. Ths is an extremely effective metod to acunt for the impacts that
rapid intrctue and load growt can impose on a utility and its cusomers. The hybrid test
period may be just as effective as a fully fored futue test year. The hybrid test period st
with the most re~nt 12-month histrical data and adjusts it for ''rasonably known and
meaurble" data to reflect the peod rates are in effect. Ägai, ifunt costs are reasnably
constt, the us of a historical test year is a viable rateiakg methodology. However, in
periods of rapid grwt, modifcatons to the historical test year ca enhance its viabilty more
effectively than using a fully foreced futue test year. The desire to us the most recet 12-
month historica data and to allow the utiity a reasnable opportity to collect its ~WTent costs
of seice can be accomplished by adusg the historical data with reasonably known and
measurble new investments and expe changes.
Reasonably knwn and meaurble rate base additions and expense chages ar more
defendable than forecass and can be more eaily calculated th resortng to the foreca used
in a fuly foreced future test year beause they are tyicaly basd on actu auditable data
For example, reVenue requirement impats of major rate base additions, which ar alost
completed when the historica test yea ends but ar not scheduled for commercial operation until
the rate effective peod ar eas to estate. Certn expen chages, such as anual union pay
increes aly approved in a contrct but not scheduled to go into effect until the rate effective
period, ca be calculated with minima controversy. Both of these examples reduc the chace
of reguatory lag and eargs shortalls.
The hybrid test perod accomplishes many of the positive thngs the fully forete
fu test period does, Le., matching curent revenues with load growt to improve fincial
position, which lowers capita cost, without reverting to totally subjective estmates.
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3 "Reasnably MOwn and measble" dat is data that is not fully rerded on the utility's boks and records when
the histoncal te year ends. Therefore, "reasnably known and meaurle" data, alough mosly actual, doe
include minimal estimates.
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c. Option 3 - Hybrid test period that st with the most reent i 2.month historical data
and in which all major rate cas elements are adjusted for "reasonably known and
measurable" data up to 7 -months afer the general rate case fiing date
Ths hybrid test period star with the most recent 12-month histoncal data and adjust it
for "reasnably known and meaurable" data up to 7-month afer the general rate case's filing
date. Ths method is the similar to Option 2, but it is more restrctve because the adjustments to
the historica te yea do not extend into the rate effectve period. As in Option 2, reasnably
known and measurable events reflect actu recorded costs plus minor estmate. Ths method
reflects the same changes the Legislatu made to NR 704.110(4) by SB 238 for gas utlities. It.
may not, however, go far enough in reflecting the cost of sece into the rate effective peod
since it ~ limited to seven month beyond the rate case fiing date. Therefore, its drwback is
that revenues could be lower than requid reducing the source of growt related revenue for the
utlity an impactng the utility's finacial position, thus leadng to higher capita costs and
higher rates for the utility's cusomers.
d. Commission's Recommendation: Option 2, Hybrid Test Period
After analyzng all the options and carfuly reewing the comments received frm
interested pares, the Commssion believes tht Option 2, the hybrid test peod, would most
accurately reflect cost of servce when deterng general rates in times of rapid grwt.
However, the Commssion should not be limited to one meodology when faced with a general
rate case. The mai concern of the Commssion is that cost of service should reflect the costs
incured durng the penod rates are in effect. While the hybnd method may provide the most
accurate reflection of costs in periods of rapid growt the histrica ratemakg metodology is
still the preferred choice when unt cost ar renably constat. Therefore, th Commission
believes tht the hybnd test peod should be added as an alterative to the historica ratemakg
methodology, and the Commssion should be able to choose which metodology is the most
appropriate when considerig a genera rate application from a public utility.
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Vi. DISCUSSION OF TH ALTERNATIVE RA TEMAING METHODOLOGIES
sa 238, section 7(2), directed the Commission to address the followig areas with resct to
each alteative ramang methodology: (i) the rate impact on customers an whether the
methodology would resut in rates tht more accurately reflect the costs of providing service to
those cusomers; (2) the cost effectiveness of using the methodology; (3) the fisca impac on
state and local agencies; (4) the procedures and mechaisms necessa to implement the
methodology; and (5) any other related mattrs that the Commission deems appropriate. The
Commission incted the Commentors to addrss these issues in their wrtten comments. Each
of these areas is discussed in deta below.
a. The rae impact on cusomers an whether the methodology would result in raes that
more accurately reflect the cost of providing servce
Most Commentors agr tht in gener, any rateakg methodology that allows the
utlity to update major costs of serce (plant, revenues, opeatig and capita expenss) beyond
the historical test year would, by design, result in rates that more accurtely reflect the cost of
providing servce as compard to a stct historica test yea with mial adjustments allowed
for changes that occur subsequet to the test period. Ths is parcularly tre in ties of swfty
changing conditions, i.e. high inflation, rapid cusmer and infcte grwt when historical
data generaly is not representative of futur reults. The hybrid test period would provide for
reasonably kno~ and meaurble adjustments to test year historical cost for chages that
would occur thoughout the peod rates are in effect. This would signficatly reuce reguatory
lag and produce rates which generally would be more refl~tive of costs that will be incured
durng the effective rate perod. Either the fuly forected test period or the hybrid test period
will be the most likely ratemakg alterntives to produce fas that will allow reovery of the
costs that would be incurd durng the period rates are in effect.
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It is not possible to quatify with precision what, if any, rate impact there will be on
cusomers when compang and contrasting the thee options, since the facts and cirumstces
are different depending on the test period under consideration when a utility files fòr a change in
generl rates. The elements of the costs of service ar constatly changing. Cornentors noted
that in Nevada at leas for the last several years, signficant growt has caused costs to steadily
increase as utilities insta facilties to serve new customers and the increaed instctu
necessa io contiue to provide safe and reliable servce to existg customer. On the other
hand, there may be instce where a utility is about to implement a new systm or operatig
procedure tht will have a signficant positive impact on the utiity's prouctvity. By using a
ratemakng methodology that considers changes beyond the trtional historical test year, these
projects and other impacted ratemakng elements, whch benefit customer though lower costs,
would be considered as well.
In a trition to a ratemakng metodology that more accurtely matches rate recovery
to cost incured, the Commentors state tht there may initialy be an upward impact on rates to
customer. Th should only occur in the fi tranition to the alterntive methodology.
Thereafer, once a regular rate case cycle and methodology' ar established, rates should not
change any more or less from ca to cas than they would wider the existg methodology, but
rates and costs would be more accurtely matched.
In looking at whether sttes with hybrid test periods have rate levels appreiably different
from states with historical test year, there was no appaent correlation; rates in dierent states
appear to depend far more on intern factors than on test year stdads.
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b. The cost effectiveness of the methodology
The Commentors agre tht general rate cas alterntives tht rely more on historical data
rather than forecasted inormtion are less expensive and easier for utilities to prepare ~d for all
pares to litigate, at least intially. However, the diferences in cost of preparg and processing
a genera rate case, under any of the four metodologies~ would be mini. There would be
transition costs associated with the introduction of a new or alternative ratemag methodology.
For example, the utlity mus develop a new general rate cae model, as well as the related
testimony to support it. Interening paries~ including Sta may also have some costs related to
time spent to review and/or revise methods they employ to .evauate the utilty's filing, for
additiona trnig, or they may underte to develop and employ new analytical technques.
The intial invesent would not be recurg and may not be signficant.
The primar differece between the th alterative ratemakng methodologies, and the
existing ratemang metodology, is the time period the utiity is allowed to consider beyo~d the
historical test year. Commentors agre tht it makes very litte difference, in tes of increasd
cost or time, whether the allowable updated period is five month, seven months, twelve month
or encompases a fuly-forecased test period. Each alternve, regardless of the adjustments
allowed to update the historica te year, will be fuly litigate by the pares involved. As noted
earlier, the use of a ratemakg methodology that more accurtely matches revenue recovery
with cost incurnce wi1l1ea to long-ten benefits for all pares to the ratemakin process.
Inherent in those beefits is increaed effciency and effectveness in the use of scare utlity, the
BCP, and Commission resources.
c. The fiscl impat on stte and loca agencies
The Commentors stte there would be litte, if any, fisca impact on state and local
agenCies on an ongoing basis, regardless of which of the thee alternative ratemakng
methodologies is adopted. Although there could be some mior one-tie llleang cure" and
adnistrative proeedin costs in transitionig to any new ramakng methodology.
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d. The procedures and mechansms necessar to implement the methodologies
Implementation of any of the above-mentioned alterntive ratemakg methodologies
will necessarly increase the level of complexity of rate ca proceedings. However, it is helpfu
that many of the changes needed to implement the proposas ar not entirely new. Commission
Sta the BCP and the Commentors ar familar with forecatig techniques and underlying data
which the Commssion ha relied upon to make decisions. For example, resour plang is
aleady based upon foreased resource options, loads and capita costs. Energy supply plans are
developed with the use of forecate inormtion. Cer raes, for example gas and electrc
utilities' base taff energy rate ("BTER") are already caculated usin forecate sales, fuel and
power prices.
The Commentors state it is highy desirble to set ground rules at the outet regaring
acceptable parameters for a new alterntive to the historical test year to enure that rate
procedings are not deraled by disputes over technques and method. Adjustent mechasms
to reaign rates and costs as needed could also serve to ameliorate concern over the preision of
. forecasted cost and needed utilty revenues. It is essential to estalish general ageement on
these prcesses and on acceptable levels of precision before the fact in order to avert
contentiousness durng the trsition rate cass. In addition, clear guidelines should reduc the
costs of thes proceedings to all conceed. These new proedurs should be addrssed by the
Commission in a futue ruemakng, where the Commssion can adopt, amend, or repea
reguations.
Whle there is an expctation that elimnating the lag between cost causation and
collection will iItially lead to higher rates, the data ar inconclusive regarding rae levels in
futu test yea States compar with historica test yea States. Over time, it should be expecte
tht there will be an iItial bump in rates durng the "catch up" phase followed by a decline frm
what rates would otherwse be as financial markets respond to the more favorable, less risky
regulatory environment by reducing costs of capitaL.
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e. Any other matters the pares dee appropriate
The Cornentors addrssed seera area of concern thugout ths investigatory docket
that should be investigated by the Commission ü the Legislatu adopts an altertive
ratemakg methodology. First, several Commentors suggested that a public utility should be
permitt to use rate indexing whereby a public utility cou~d make periodic adjustents to rates
basd on an approp~ate cost index. Second, one Commentor'proposed that a tre-up process
'should be adopte, which would requi a public utilty to updte reasnably known and
measurable adjusents afer they become actu. Thd. the filing reuirments for genera rate
cases would nee to be modified to provide the Commssion with gudace in detennnig what
data ca be identified as reasnably known and measble. Finlly, Commentors wer
concerned that rate of retu reguation ha become antiquate for competitive
telecmmuncations caers and shOuld be modified so that it encompases the priiple that
competition serves consumers better than reguation. These conces ar more fully descrbe
below.
i. Rate Indexing
Severa Commentors recommended that the Commission should adopt a rat indexig
syste, wlich allows a public utility to make periodc adjustments to rates bas on an
appropriate cost index, such as the effects of infation and effciency gai on opetig and.
maintenace expenses. Rate indexing is usefu when bas rates are set every two-year sin it
keeps the cost of serVce curent with the rate effective period." lbs would require a mium
of adinstrative effort on behalf of the Commission Sta to overe. An adjustment
mechansm, combined with a forecased test year, which bègins the day tht rates are expcted to
become effective, would result in a cost-efficient process of seg rates that should closely
reflect the actul cost of servng customers.
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4 Pusut to NRS 704.110(3), an electrc utilty mus file a general rae application at least every 24 month. The
Commission has drd a Bil Drft Request that would requir a public utility which purchases natul gas for
resaJe to fie a general rate application every 36 months. (Se Atthment 2).
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ii. True-Up Process
Another proposal by one of the Commentors would requie a public utility to update
reasonably known and meaable adjusents afer they become actul. Howevert by adoptig
ths proposat the Commssion would be faced with a signficant increase in the administrtive
effon required to prepare and proess a general rate case. The effort involved in preparg a full
set of trd-up schedulest work papers and testimony would be the near equivalent of filing an
entirely new general rate case. In additiont Sta and other Commentors would have to dedicate
signficant resources to anyze ths "tred-upu inormation. The Companes support ths
processt but SWG does not.
iii. Filng Requiements
One Commentor suggested that prior to the tie an alterntive rateiakg methodology
is available to the utilties. the genera rate cas filing requients, as set fort in NRS 704. i i 0
and NAC 703.2201 though 703.2452t should be reviewed and modified. The curent
reuirements do not addrss the issue of what documents would nee to be. fied in order for the
Commssion to make a determnation of wht can be defied as renably known and
measuble data. nor do they address the procedures and mechanisms the Commssion would be
required to utiliz to mae this determination. This review an modification should also include
the Inster dat request. The curent fiing requements may not be entiely suitable or
appropriate for an alterntive or new ratemakng methodology.
iv. Telecmmuncaons Caer: Non-Rur Incumbent Local Exchage Compaes
A new approach is needed to Common regution of ratemakg th baances th
int of consers and the reguated caer, but at th sae tie is more effcient and
reflectve of a comptive marketlace. Tradtional rate cases for large telecommuncations
carers have beome relics of the pas. Only five stes Stll rate reguate all incumbent loca
exchange caers using tritiona rate-of-ret regulation. Most of the states - includng
Nevada - have adopte some form of price cap reguation. Rate cass ar not pracca for
large integrated telecommuncations companes providing servces and prouct in a
competitive marketplac.
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Today, in Nevada there are tw telecommuncations companes tht were recently
formed as the result of merger. The merger between AT&T and SBC Nevad fOmled AT&T
Nevada. The merger between Sprint and Nextel formed Embarq. Nevad telecommunications
companes, along with their afliates, market and providetradtional voice servce, as weU as,
high speed data servce, voice mail, custm calling featues, dial-up Interet access, DSL
servce, inide wing, satemte TV prgrg, Centrex, customer premses equipment,
PBXs, key systems, 91 i and Enhanced 911 serces, public phones, intre and interstae
long distace servces, Caller-ID, cali center management; voice over inteet protocol
("VoIP"), wiless telephone service, WI internet access, two-way paging, instt wiless
messaing serces, alai and line monitorig, and private networks. Whle a few of thes
seices are stil subject to traditional rate reguation, the pructs and most of the servces
have ben deemed "competitive" or "dereguate" and therefore are no longer subject to rate
regulation. Attemptig to alloca th cost of telephone company equipment and personnel
that provide ths wide varety of product and seces beee reguate versus ungulated is
increasingly more cOmplex, arbitr and unecesa. .
Probably the main disavantae with rate of retU reguation, in the increasingly
complex telecommuncations indus which provides multiple reguated and uneguated
serces over one joint network, is that settng cost-basd prices is increasngly tie-
conswnng and arbitrar.
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"
The presence of competition fuer undennes the:'effectiveness of trditional rate-of-
retu regulation. Loca telephone servce is no longer a "natual monopoly" - there are
competitors. Under the Telecommuncations Act of 1996 ("Telecm Act"), competitive loca
exchange carers ("CLECs") can offer services tht directly compete with the incumbent loc
exchange carers ("lLECs"). As of the end of 2004, the FCC esated that CLECs provide
18.5% of the switched acss lines. Even with the recent changes regardig the availabilty of
Unbundled Network Elements ("UNtl) adopted by the FCC in the Triennal Review
proceedings; CLECs stll have access to the fLECs loca loòp plant to provide a competitive
altemative to its services. In addition to being entitled to cost-ba UNEs, CLECs ar also
entitled to resell the telecommuncatons seice's of the ILEC at a substtial discount. CLECs
in Nevad are not subject to rate reguation. In fact, Nevada (along with thee other sttes)
provides the CLECs with the grst flexibilty, even when compared to sttes that do not
review CLECs' rates. Compeitive caiers in these four sttes are not requied to fie tarffs or
provide notifcation of chages and the rate chages are not normally reviewed by their
respective state commssions.
The Commssion encouragés the Legislat to adopt a new frework for
telecommU1cations basd on the priciple that competition serves consumers beter th
regulation. Ths frework can incorporate a "saety net" to ensure that basic telephone service
remains afordable and available to residents thougout Nevada by reui the continue
availability of both Lifelie sece and a basic servce offering which can be support by
unversl service fuding. Ths approach strkes an appropriate balance be~en ~e need for a
saety ~et and the existnce of competition. In addition, it acknowledges tht one size does not
fit al when it comes to local exchange carers. By the time the 2007 Legislatu addrses
ths proposa, it will be very.approprate to relace PAR reguation with a frework tht
acknowledges the new competitive marketplace whle contiuig to ase the avaiabilty of
Lifeline servce.
The telecommuncations market continues to be reviewed ver closely at the feder
level and as a result dereguation may occur at the federa1evel before states have tie to
effectively put dereguation in place.
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The Commssion reognzes that telecommuncatin,ns will contiue to change in ways
that are drven more by consumer demand th regulation. The Commission also recognzes
tht State regulation of the telecom indust may need to be furter liberaliz in light of
technology, markets and conswner demand. The Commssion stds ready to assist the 2007
Legislatue in any effort to review and update Nevada telecommuncations law.
VB. COMMISSION RECOMMEDATIONS
The Commission reommends the hybrid test period for its energy utiities that st with
the most recent 12-month historical data and adjusts all major costs of seice elements for
reasnably known and measurble data through the rate effecive period. The Commssion
believes ths hybrid test period ha more advantages than either the fuly forecased methodology
i
or the more restctive hybrid methodology, whch adjusts, for 7-months of data to successfuly
deal with unprecedented inastrctue and load growt, chagig use characteristcs, chagig
tehnologies and chaging wholesale maket stctes, which are being imposed on Nevad's
energy utilties and their cusmers. At the same time, ths hybrid approach leverages the
existng ratemaking methodology, providing consumers, reguated utlities and the reguatory
communty with more consistency th the fuly forecaed test year methodology.
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The hybrid approach has an advantage over the fuly forecated methodology becaus it
sta with the i 2-month historica test year and adjusts it with reasonably known and measurable
data, which is bas on specific events whose costs ar veriable and easily estiate into the
rate effective peod, rather than relyig on adjusents tht ar unverifiable and based purly on
foreas. It ha the advantae over the more restctive hybrid approach since it adjusts the i 2-
month historical test year though the rate effective period rather th to a point in tie before
rates become effective. As a result, ths hybrid methodology would produce rates th would
better reflect the actul costs of seice that ar expected to be incured durng the period rates
ar in effect thus improving acurcy and reucing reguatory lag. Reflecting the actu costs of
service in rates would also send an economically corrct prcing sign thus helping cusomers to
effciently choose how to us the utity's services, i.e. thugh the purhase of energy-effcient
appliances, thugh the purhas of prducts and services that promote energy conservation, or
by using less energy (tug down the thermostat). Finally, reflectig curnt costs of sece in
. ras would improve the ficial position of the utility thus lowerng its cost of caita and
improving its soure of grwt related revenues to build its inctue and load.
The Coinission agrees with the Commentors that it is highy desirable to set ground
rues at the outset regarding aceptable pareters for a new alterntive to the historica test year
to ensure tht rate proceedigs ar not derled by disputes over technques and method. It is
essntial to estblish genera agreement on these proceses an on acceptable levels of preision
before the fact in order to avert contentiousness durg the transition rate cass. In addition,
clear guidelines should reduce the cost of these proceedings to all concered. Therefore, the
Commssion believes tht if the hybrid apprach is autori by the Legislatu, the new
procedures would be addressed by the Commission in a fue rulemakg.
The comments regarding rate indexing and tre-up processes are ver helpful to the
Commission. The Commission, however; believes tht if the hybrd approach is adopted,
coupled with the development of the appropriate procedures durng a rulemakng pIus a fuly
litigated rate case filed by the utility will be suffcient. The Commssion also recommends tht
the Legislatue review and updte Nevada telecommunications law.
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VII. PROPOSED LEGISLA nON TO AUTORIE AN ALTERNATIVE RA TEMAG
MElHODOLOGY: THE HYBRID TEST PERIOD
The Commission ha dred a Bil Drft Request ("BPR") encompasing the elements
necessar to implement the hybrid tet period as an alterntive ratemaking methodology. (See
Atthment 3). As discussed above, the main concern of the Commission is that costs of servce
should reflect the cost incured durg the perod rates are in effect. The hybrid test peod
provides the most accurate reflection of costs in periods of rapid grwt, but the historical
ratemakg methodology is preferred when unt costs are reanably constt. Thus~ the
Commission recommends that the Legislatue adopt the hybrid test period as an alternative to the
historical ratemakg methodology, but leave the Commssion with the option to choose which
methodology is the most appropriate when considerg a genera rate application from a public
utilty.
The language used in the BDR permits a public utlity to elect to us the hybrid
methodology ~ but~ if the public utility so elects, it will need to provide the Commssion with the
12-month historical data as well as with data reflecting all expected chages in circumces
which are reasonably known and measurble and which are reasonably forecased to become
effective durg the rate effective period. The Commission can then determine which
methodology, either the historica metodology or the hybrid methodology, most acurtely
reflects the costs of servce that are expected to be incured durng the period rates are in effect.
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ATTACHMENT 1
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TYPE OF TEST YEAR USED IN DETERMG RATES ELECTRIC AND GAS
UTLITIES
AGENCY TEST YEA USED IN DETERMINING RATE
ELECTC GAS
FERC Foreast/istoric 11/Historic 6/
ALABAMPSC 21/Historic 11 14/Historic 1/ 14/
ALASKA PUC Historic Historic
ARONACC Historic Historic
ARKSAS PSC Historic/ar Foreas .Historiclar Foreca
CALIFORNA PUC Full Forecast Full Fore
COLORA PUC Historic 121 Historic 121
CONNCTICUT DPUC Forecast HistoricJore 1/
DELWAR PSC HistcJore 3/HistoricJore 3/
DCPSC HistoricIar Forecat HistoricIar Foreca
FLORIDAPSC Historiclojeeted Hisricljeced
GEORGIAPSC Full Forecas Hitoriclar Foret 4/
HAUAIIPUC Full Forecast Full Forecast
IDAHO PUC HistoriclPar Forest 5/HioricIar Foret 5/
ILLINOISCC Hisoric/curent/futu Historic/cUrt/fu
INIAAURC Hisc Historc
IOWAUB Histric Hisoric
KASASSCC Histoic 7/Histric
KETUCKY PSC HistricJoreast 17/19/HistorcIoret 17/19/
LOUISIANA PSC Historic HistoricMAPUCHistric121Historic 121
MARYLAD PSC HistoricIar Forecast 17/HistoricIar Forecast 171
, MASSACHSETT DPU Histric 1/Historic 11
MICHIGAN PSC Full Fore (lage)lHistorc (small)8/same 81
MINSOTA PUC Full Foreca (large)Iistoric (smwl)8/same 81
MISSISSIPPI PSC Full Forecaisc Full Forecastltoric
MISSOUR PSC Historic Hisoric
MONTANAPSC Historic Hisoric
NEBRASKA PSC PSC bas no jursdiction over energy utilities
NEVADA PUC Historic 13/Hisoric 131
NEW HASHIRE PUC Historic Hisric
NEW JERSEY BPU 21/Paral Forecas 4/Paral Forecas 41
NEW MEXICO PUC Historic Historic or Forecast
NEWYORKPSC Full Forec (lare)Iistoric (small)8J sae 81
NORTH CAROLINA UC Historic 17/Historic 17/
NORTH DAKOTA PSC Par or Full Fore 9/Par or Full Foreas 9/
OHIO PUC Par Forecastlistoric 10/Par Fortlistoric 10/
OKLAHOMACC Historic 20/Historic 20/
OREGON PUC Full Forecastlistoric Full Forecaisoric
PENNSYLVANA PUC Full Forecast (large)lHistoric (sml)8/sae 8/
RHODE ISLAND PUC Historic & Forecat Historic & Foreca 1/
SOUT CAROLINA PSC Historic 17/Historic 17/
SOUTH DAKOTA PUC Historic Historic
TESSEE PSC Historic & Foret Historic & Foreast
TEXAS PUC TEXAS RC Historic Do not regulate.
UTAHPSC HistoriclJ2-mo forecast Historíi:J2-mo forecastVEONTPSB21/Historic Historic
VIRGINA SCC Historic wI pro forma adjs Historic wi pro forma adjs
21
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WASHIGTON UTC
WEST VIRGINIA PSC
WISCONSIN PSC
WYOMINGPSC
VIRGIN ISLANDS PSC
ALBERTAEUB
NOVA SCOTIA UARONTAROEB 211
QUEBECNGB
Historic
Historic 121
Full Forecast (Iare)/istoric (small) 8/
Historic
. HistoricFull Forecast 151
Full ForecasFull Forecas 21
Does not regulate
Historic
Historicsae
Historic
none in jurisdiction
Full Forecast
none in jurisdiction
Full Forecas
Full Forecas
121
8/
FOOTNOTE - TYPE OF TEST YEAR USED IN DETERMING RATES
11 Historic test year is requird to be nonalize thus removig or avergig any unusual occimences and updating
inonntion for known and meable changes. Commission is investigati use of fored tes period;
compaies may fie futu test peod although formal guidelines or regulatons have not yet be adopted
21 For Ontao Hydro's bul power rates, Power Coipration Act preSlpposes fui foreca year.
31 Test yea must be historic. Tes perod used in determin rates ca be historic or prjeced, but no more than
nine months projected.
41 Often when parial foreast is fied, it is updted to act by the time ca is taen under advisement. therbybeming historic te yea. .
51 Commission nonnlly use hist test year with 12-month averge ra ba, but ha depar from ths in
several rate caes by approving use of paral or full foreast test year in approprte circumtances.
61 Generaly, rate incres are base on 12-month historic dat endin not more thn four month prior to fiing
date and adjusd for known changes within nine months after the las month of acl experience.
71 Generally use Historic Test Year, although fuU forecas test year use in a recnt cae. Generaly inequae
utilit budgetig procedures prevent Coinission from actely testing projecd data.
81 Major companes use full forect; smaller utlities permitted to use'historc test yea.
91 Histric te year data mus be submitted as suplemental informaton. Telephone not subjec to ra ofretu
reguation.
101 Use of histoic or paral forec test year is permtted provided thii the test year end.no more than nine month
subseent to the date of the filing of the application for an incre in rates and no less th th months of actl
data is used.
1 II Major electrc rate increases ar based on fore 12-month test period data. Oter incras may be bad onrecent historic da . .
12/ Coinission normally uses historic te yea, but has allowed paally or fully forecased test yea on a limited
basis.
. 131 Historic test yea with six-month update subsequent-expe and capital items must be expenced and
cefied. Revenue, sal expese, depreation expens, and Feder Income Taxes are anualized.
141 New ra concept prescribe for Alabama Power Co. (electric) and Alab Gas Corp. See Alabaa Gas Corp.
Settlement. Docket Nos. 18046 and 18328, Alabam Power Co. Setement. Nos. 18117 and 18416.
Under the Elecc Energy Mareting Act, the price at whicb elecc energy is sold by the thee utiites to the
Alber Electrc Energy Marketing Agency is set on a Full Forecast bais. This price is subject to relroaetve
adjustment on a Histric tes yea basis. Puose of the Agency is to average wholesale electrc rates and roU back to
the utilties at a uniform rate.
Tes year may be hioric or use up to 6 months projected. Test year data may be fu adjusted for known and
measurable chanes occiming within succeeing 12 months. '.
Histric Test yea is requird to be normalizd, thus removing or averging any unusual ocurnces and updtig
information for known and measurable changes.
18/ Regulate ga pipeline cariers and common carer oil pipelines.
19/ Forecated tet yea peitted by 1992 legislatu, new regulations effecive 3/1213 establish rules for filingforeas test year applications. .
1994 legislation reqes the CC to II give eff to known and measurble chages occurg or reaonably cern to
OtçUT within six months of the end of the tet period upon which the rete review is based"
211 Commission did not respond to request for updat information; this daa may not be curnt
22
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ATTACHMENT 2
23
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BILL DRAT REQUEST FOR 3-YEAR GAS RATE CYCLE
EXPLAATION - Maer in Itiillcs is new; matter in stelgb emilh!l materal is matal to be omited.
704.110
3. If a public utility files with the Commission a general rate application. the public utility shall
submit with its application a sttement showig the recorded results of revenues, expenss,
investments and costs of caita for its most recent 12 month for which data wer available
when the application was prepared. Except as otherwse provided in subsection 4, in deteg
whether to approve or disapprove any increasd rates, the Commission shall consider evidence in
support of the increased rates basd upon actual recorded results of operations for the sae 12
month, adjused for increed revenues, any increed investent in facilties, incread
expenses for depreciaton, cern other opertig expenss as approved by the Commssion and
chages in the cost of securties which ar known and are meaable with renable accurcy
at the time of filing and which will become effective with 6 months afer the las month of
those 12 month, but the public utility shall not place into effect any increasd rates until the
chages have been experienced and cefied by the public utilty to the Commssion and the
Commssion has approved the incred rates. The Commsson shall also consder evidence
,supportg expenses for depreciation, calculated on an anua basis, applicable to major
components of the public utilty's plant placed into service during the recorded test period or the
period for certfication as set forth in the application. Adjustments to revenues, operating
expenses and costs of securties must be calculated on an anua basis. With 90 days afer the
date on which the certfication required by this subsection is fied with the Commssion, or
with the period set fort in subsection 2, wmchever tie is longer, the Commission shal make
such order in reference to the increa rates as is requid by ths chapter.
(a) An electc utilty ~l file a gener rate application purt to this subsection at least
once every 24 month basd on the followig schedule:
(1) An electrc utilty that priarly serves less densely populated cowities shall file a
general rate application on or before October 3, 2005, and at lea once every 24 month
thereafter.
(2) An electrc utility tht priarily serves densely populated counties shall file a general
rate application on or before November 15,2006, and at leitt once every 24 month therafer.
(b) A public utlit which purchases natural gas for resale shall fúe a general rate
application pursuant to this subsecton lit least once every 36 months based on the foUowing
schedule:
(1) A public utilit which purchases natural gasfor resale that pririly serves less
densely populated countie shall fie a general rate applicaton on or before November 7, 2008,
and at least once every 36 months thereafter. .
(2) A public utilit which purchases natural gas for resale that prirUy serv densely
populated counties shall fie a general rate applic"ûon on or before Ocober 5, 2009, and øt
least once every 36 months thereafter.
24
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12
(e) "A public utiit which purc/iases natural gas for resale that primarily serves less densely
popultted counties" has the meaning ascribed to it in NBS 704.185.
(f "A public utilty which purchases natural gas for resale that primarily serves densely
popultted counties" has the meaning ascribed to it in NBS 704.185.
704.185
4. As used in this section:
fa) '~public utilit which purchases natural gas for resale that prinurily serves densely
popultted counties" means a utility that, with regard to the provision of purchasing natural
gas for resale, derives more of it annual gross operatng revenue in this State from customers
located in counties whose population is 400,000 or more than it does from customers located
in counties whose population is less than 400,000.
(b) "A public utilit which purchases natural gas for resale that primarily serves les densely
populated counti" means a utilty that, with regard to the proviion of purchasing natural
gas for resale, derives more of its annual gross operating revenue in this State from ClitOme
located in counties whose population is le than 400,000 than it does from customes located
in counti whose populatin is 400,000 01' more.
25
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AT ACHMENT3
. 26
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..
BILL DRA REQUEST FOR PROPOSED RATEMANG METHODOLOGY
EXPLANA nON - Mat in Wcs is ne mat in stretgh emi~d 8!at8Røl is inial to be omitted
704.110
4. In addition to submittg the statement required puruant to subsection 3, a public utilty
whieh plases Datura) gas for fee may submit with its general rate aplication a statement
showig the effects. on an anuaiz basis, of al expected changes in circumces. If such a
statement is filed, it must include all increases and decreases in revenue and expenses which may
occur with 575 ~ays afer the date on which its genera rate application is flIed with the
Commssion if suh expeted chages in cirumstces are reasonably known and ar
measurble with reonable accurcy. If a public utlity submits such a sttement. the public
utility has the burden of proving that the expected changes in circumstces set fort in the
stament ar renably known and are meaurble with renable accurcy. if the
Commission determines that the public utility has met its burden of proof:
(a) The Commission sha11 consider the sttement submittd pursuat to ths subsection and
evidence relevant to the sttement in addition to the statement requied puruant to subsection 3
as evidence in esblishig jus an reanale raes for the public utiity; and
(b) The public utlity is not requied to fie with the Commssion the certification tht would
otherwse be requi purst to subsection 3.
27
e
i
'i
~VALUELINE
~ PUBLISHING, INC.
220 East 42nd Street
New York, New York 10017-5891
Phone: [phone]
Internet: ww.valueline.com
I Dividends Per Share x 30 I
1920 '21 '22 '23 '24 '25 '26 '27 '28 '29 1930 '31 '32 '33 '34 '35 '36 '37 '38 '39 1940 '41 '42 '43 '44 '45 '46 '47 '48 '49 1950 ! '51
9.1 2.1 9.1 8.3 10,9 13,9 11.4 8.7 16.0 19.9 11.0 4,1 -0.5 2.1 3,9 6.3 10,1 11.5 6.0 9.1 10.9 11.6 9.2 9,7 10,1 10.6 13.6 18.8 23,1 23.5 30.7 26,65.8 3.9 4.0 4.5 5,2 5.5 5.5 6.0 9.8 12.8 11.1 8.4 4.6 3.4 3.7 4,6 7.1 8.8 5.0 6.1 7.1 7.6 6.4 6.3 6.6 6.7 7.5 9.2 11.5 12,8 16.1 ~6.348.2 46.4 51.6 55.3 61.0 69.4 75.2 779 84.1 91.3 91.2 86.9 81.8 80.5 80.7 82.5 85.5 88.3 87,1 95.6 98,7 103.0 107.0 113.0 118.3 122.7 131.4 149.1 159.7 170.1 194,2 2p.69.9 34.8 10.2 11.4 9.2 9.6 13.3 20.1 14.2 15,6 21.4 NMF NMF NMF 25.1 18.9 16.1 14.5 22.0 15.7 12.3 10.5 11.6 13.8 14.2 16,1 14.1 9.4 7.8 7.6 7.0 ¡ 9.715.5 18.8 23.5 20.8 19.4 24,2 27.29.0 23,3 24,4 21.2 16.5 14.0 24,6 26.9 26.4 23.0 19,0 26,6 23.4 19.1 16.0 16.8 21.4 21.8 25.4 25.5 19,3 15.6 14.0 13.4 n5,818.9 4.5 17.7 14,9 17.8 20.0 15,1 11.2 19,0 21.8 12.1 4.7 -0.6 2.6 4,8 7.7 11.8 13.0 6.9 9.5 11.11.3 8,6 8,6 8.5 8.6 10.4 12,6 14.13.8 15.8 13.110.1 2.9 9.8 8.8 10,9 10.4 7.5 5.0 7.0 6.4 4.7 3,0 -0.8 2.5 4.0 5.3 6.2 6,9 4.5 6.4 8,1 9.6 8.6 7.2 7,0 6.2 7.1 10.6 12.8 13.1 14,2 10,36.4 5.3 4.2 4.8 5.2 4.1 3,6 3,5 4,3 4.1 4.7 6.1 7.2 4,1 3.7 3,8 4.3 5,3 3.8 4.3 5.2 6,2 6.0 4.7 4.6 3.9 3.9 5.2 6.4 7.1 7.5 6,3--770 NMF -9.4 31,9 27.7 -18.0 -23.4 83.1 24.9 -44.7 -62.9 NMF NMF 85.3 62.1 58.8 14,1 -47.7 51,6 19.9 6.6 -20.8 5.6 3.4 4,9 29.1 37,9 22.7 2.0 30.4 ,13.--32,8 1,5 14.2 14.4 7.2 0.2 9.0 61.6 30.6 -12.7 -24.5 -45.0 -26.7.6 24.3 54.9 24.5 -43,3 22.7 15.5 7.5 -15.7 -1.4.3 1.8 12.1 22.8 24,9 11.2 26.1 1.3.--3.7 11.2 7.2 10.3 13.8 8.4 3,6 8.0 8.6 -0.1 -4.7 -5.9 -1.6 0.2 2.2 3,6 3,3 -1.4 9.8 3,2 4.4 3.9 5.6 4.7 3,7 7.1 13.5 7.1 6.5 14.2 4.3--74.1 NMF -0.7 42,8 33.0 '10.5 -18.5 90.2 31,3 -40.1 -59.9 NMF NMF 89,3 67.4 65,0 21.0 -43.2 58.0 28.0 16.2 -12,2 12.9 10.4 11.36.2 48.5 35.5 15.2 44.6 -3.1--27.5 5.8 19.0 19.6 11.3 3.8 12.5 65.9 347 -8.0 -18.5 -37.8 -22.3 114 28,1 59.3 29.8 -39.5 27.0 20.8 13.7 -9.7 3,1 8.9 5,8 16.0 28.0 31.3 18.3 33.6 7.6
6,1 6.0 5.1 5.1 5,0 4.9 4.7 4.6 4.5 4,8 4.5 4.6 5.0 4,5 4,0 3,6 3.2 3.3 3.2 3.0 2.8 2,8 2,8 2.7 2.7 2.6 2,5 2.6 2,8 2,7 2.6 2.915.6 -10,9 -6.2 1.8 0.4 2.4 0.9 -1.9 -1.2 0.0 -2.7 -8,9 -10,3 -5.2 3.5 2.6 1.0 3.7 -2.0 -1.3 0.7 5.1 10.9 6,0 1.6 2.3 8.5 14.4 7.7 -1.0 1.1 7,9-9.5 16.9 11.3 3.3 4.6 2.5 3.8 6.5 5,7 4.8 7.2 13.5 15.3 9.7 0.5 1.0 2.2 -0.4 5.2 4.3 2,1 -2.3 -8.1 -3.3 1.0.3 -6.0 -11.8 -4.9 3.7 1.5 -5.0
109.9 81.5 103.4 105.4 120.5 159.4 166.6 202.4 300,0 381.1 294.1 194.4 88.8 108,7 110.7 148.4 184,9 194.4 158.4 155,9 152.8 133.6 119,7 145,8 152.5 195.8 212.5 186,9 193.2 20,5 235.5 276.466.8 63.9 78.6 85,8 88.3 115,0 135.2 152.7 191.3 198.7 157.5 73.8 41.2 50.2 85.5 96.7 143.1 113.6 99.0 121.4 111.108.3 92.9 119.3 134.2 151.4 163,1 163.2 165.4 161.6 196.8 239.090.0 73.4 93.2 94.9 99.6 134,5 153.0 175.8 226.0 311.2 236.3 138.6 64.6 83.7 98.3 120,0 162.2 166.132.4 142.7 134.7 121.8 107.2 134.8 143.3 169.8 191.17.6 179.9 179.5 216,3 257,6-19.94 26.12 21.04 13.64 6.91 9.06 9.83 10.59 15.44 15,38 11,46 12.05 11.01 9.83 8.66 11.2 12.47 15.13 17.09 15.16 15.54 15.22 18.40 21.32
91.5 69.6 74.2 85,3 84.9 93,3 97.2 95,1 97,1 103.8 91.76.4 58.6 562 65.9 73.1 83,6 91,8 85.4 91.9 101.2 12l,7 161.6 198.3 219.7 22.2 222.6 244.6 269.7 267.8 294.6 3B9.7
. Average 1920 - 200 inclusive. (A) Excludes net nonrecurring per share loss: 1983, $12.48; 1984, $7.46; 1985, $16.39; 1986, $3,67; 1987, $24,68; 1988, $0.36; 1989, $7.29; 1990, $8.63; 1991, $27.24 ; 199, $132.36; 1993, $32.991994 $1.34; 199, $1
Ii
?
EXHIBIT NO. 50, P. 1 of 3
Case No.: lP-E-07-08
D. Pe, Micron
:¡--'"'~..,'~..,,:;~,;';:~:';'.i'h
I Shaded Areas Indicate Recessions I
:~;Je-
d_~i;--'\7;_,
'51 '52 '63 '64 '55 '56 '57 '58 '59 1960 '61 '62 '63 '64 '65 '66 '67 '68 '76 '77 78
!6.5 24,8 27.2 28.2 35.8 33,3 36,1 28.0 34.3 32.2 31.9 36.41.2 46.4 63.7 57.7 53.9 57.9 57.0 51.0 55,1 67.1 86.2 99.0 75.7 96.7 89.1 112.8 124,5 121.113.7 62.0 84.96.3 15.4 16.1 17.5 21.6 23.0 21,6 20.0 20.7 21.4 22.7 23,3 23.4 312 28.6 31,9 30.2 31.3 33,9 31.5 30.9 32,3 35.3 37.7 37.5 41.4 45.8 48.5 51.0 64.4 56.2 64.1 56.312.6 213.4 244.3 249,0 271.284,8 298.7 311.0 339,0 369.9 385.8 401.0 425.9 417.4 453,3 475.9 476.5 521.1 542.3 573.2 607.6 642.9 690.2 747.0 783.6 798,2 841.8 890.7 859.4 928.5 975,6 881.5 888,2
9.7 10.9 10.1 11.8 12.4 14.8 13,2 17.6 18.4 19.2 21.7 17.6 17.3 18.0 17.0 15.1 16.3 15.7 15.4 14.8 16,1 14.1 10.7 7,7 10,6 10.1 10.0 7.3 6.8 7.3 8.2 14.3 14.05.8 17.6 17.1 19.1 20.5 21.22.0 24.6 30,5 28.9 30.4 27.5 30.5 26.7 31.8 27.4 29,1 28,9 25,9 23.9 28.7 29.4 26.2 20.1 21.4 23.5 19.5 16,9 16.6 16.4 16.6 16.3 21.
3.1 11.6 11.1 11,3 13.2 11.12.1 9.0 10.1 8.7 8.3 9.1 9.7 11.11.8 12.1 11.3 11.10.5 8.9 9,1 10.4 12.5 13,3 9.7 12,1 10.6 12,7 14.5 13,1 11.7 7.0 9.6 '0.3 9.2 9,9 8.4 8.1 6.8 7,6 5.7 5.4 5.2 4.6 5,7 5.8 5.6 5.9 6.6 6,1 6.4 6,5 6,8 6.2 7.1 9.3 13.0 9.4 9,9 10,0 13.8 14.7 13.7 12.2 7.0 7.16.3 5.7 5,8 5,2 4.9 4.7 4,5 4.1 3,3 3.5 3,3 3.6 3.3 3.7 3.1 3.7 3.4 3.5 3,9 4.2 3,5 3.4 3,8 5.0 4.4.2 5.1 5.9 6.0 6.1 6,0 6,1 4.7
3.4 -6.8 9,9 3.5 27.0 -6.8 8,2 -22.5 22,8 -6.1 -0.9 14,2 13.1 12.7 15.6 7.5 -6.6 7.5 -1.5 -10.5 8.0 21.8 28,4 14.9 -23.6 27.8 -7.9 26.6 10.4 -2.1 -6.7 -45.5 37.01.3 -5.6 4.4 8,4 23.5 6.5 -6.0 -7.5 3,7 3.0 6.3 2,6 0,5 33.4 -8.4 11.5 -5.3 3,8 8.2 -7.0 -2.1 4.6 9.5 6.8 -0.7 10,5 10.7 5.8 5,1 6.6 3.4 -3.7 4.04.3 5,3 14.5 1.9.2 4.8 4.9 4,1 9.0 9.1 4.3 3.9 6,2 -2.0 8.6 5.0 0,1 9.4 4.1 5.7 6,0 5.8 7.4 8.2 4.9 1.9 5.5 5,8 -3.5 8.0 5.1 -9.6 0.8
3.1 2,3 19,8 11.9 35,1 -0.1 15.8 -16.8 28.2 -0,9 3.7 19.9 18.9 18.2 21.5 14.1 -0.5 13.9 5.0.-3,7 '14,2 28,9 37,7 28.0 -14,2 37.8 2.1 40.4 25.1 11.6 5,5 -38,5 44.17.6 0.1 10.2 13.7 28.4 11.2 -1.5 -3.4 7.0 6.4 9.6 6.2 3,7 37.2 -5,3 15.1 -1.9 7.3 12,0 -2,8 1.4 8.0 13.3 11.4.0 14.8 15.8 11.8 11.12.7 9.4 2.4 8.8 .
2.9 3,0 3.2 2,9 3.1 3.4 3.9 3.8 4.4 4.4 4.3 4.3 4,3 4.4 4.5 5.1 5,5 6,2 7.0 8.0 7.4 7.2 7.4 8.6 8.8 8.4 8.0 8.7 9,6 11.9 14.2 13.8 12.07.9 2,3 0.8 0.3 -0,3 1.5 3.3 2.7 1.0 1.5 1.1 1,2 1.2 1.3 1.6 3,0 2,8 4.3 5.5 5.8 4.3 3.3 6.2 11.1 9.1 5.7 6.5 7,6 11.3 13,5 10.3 6.1 3.25.0 0.7 2.4 2.6 3.4 1.9 0,6 1.3.4 2.9 3.2 3.1 3.1 3.1 2.9 2.1 2,7 1.9 1.5 2,2 3.1 3.9 1.2 -2.5 -0.3 2.7 1.5 1.1 -1.-1.6 3,9 7.7 8.8
6.4 292.0 293,8 404.4 488.4 521.1 520.8 583.7 679.4 635.5 734.9 726,0 767.2 891.7 969.3 995,2 943.1 985,2 968.9 842.0 950.8 1036 1052 891.7 879.0 1015 999,8 907.7 897.6 100 1024 1071 12879.0 256.4 255.5 279.9 388.2 462.4 419.8 436.9 574.5 566.1 610.3 535,8 646:8 766.1 840.6 744,3 786.4 825.1 769,9 631.2 798.0 889.2 788.3 577.6 632.0 858,7 801.742.1 798,7 759.1 824.0 776.9 10277.6 270.8 276.333.9 442.7 493,0 475.7 491.632.1 618.0 691.5 639.8 714.8 834.0 910.9 873.6 879.1 906.0 876.7 753.2 86,8 949.1 923.9 759.4 802,5 974.9 894,6 820,2 844,4 891.932.9 884.4 1190,32 24,50 24.72 29,72 40.49 46,65 44.42 46.20 57.41 55.85 66.27 62.32 69.86 81.37 88,15 85.18 91.98 98.37 97.77 83.18 98.31 109.1 107.4 82.8 86,18 102.0 98.18 96.12 103.0 118.7 128.119,7 160,5-1372
17 358.6 379,7 381.3 415.1 438.0 461.0 467.3 507.2 526,6 644.8 585,2 617.4 663,0 719.1 787.8 833.6 910,6 982,2 1036 1125 1237 1383 1497 1631 1819 2031 2296 2566 2796 3131 3259 3535
$15.81; 1996, $15.44; 1997, $26,24; 1998, $12.48; 199, $8.01; 2000, $5.71; 2001, $35.50; 200, $33.23; 20, $0.26: 200, $4.43; 2005, $15.23; as detrmined by Value line, Inc. (8) Estmat 1920 -1935. (C) Annual average excludes years wit NMF: 1931
. .
A Long-Term Perspective
Dow Jones Industrial Average, 1920-2005
(Quarterly Price Range)
..
111.1....
....., ..J
/ ìilthp rlfti/ -- ~.'.~ /'II .;.~ ~
I Ear~ingS Per' 8,hare x 151
''-~~A';
;i:?::~¡g"
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c
EXHIBIT NO. 504, P. 2 of 3
Case No.: IPC-E-07-D
D. Pesau, Miron
i'
Ill' I'ì;ljljl'
'1'.11 -- .............II ,. ".e:._l- ./
~ ..... -./ '
I
20000
10000
I
8000
6000
5000 I
4000
J
3000
2000
rget Price Range (15,400 - 20,600)
1000
~';(caÄ;800
J
1
ij,:i:r;'
;;"f
600
500-j;l,L,
\:;:J1UYr:
;,j¡~:)I¡;l 400
Average AnnUalized Rates, 50-Year Summary 300
)JIA, Dividend +PIE Earnings Earnings as Inflation AAA~Corp.ipital Appreciation Ratio Growth % of Price Rate Bond Yield
1.7%17.9 -4.3%6%3.4%5.7%11.2%17.3 8.4%6%2.8%5.6%2.0%18.9 3.3%5%2.6%6.1%9.8%.19.1 5.5%5%2.5%6.6%13.1%16.3 8.9%6%3.0%7.6%10.3%13.7 5.8%7%4.1%7.5%
200
100
80
60
'84 '85 '86 '87 '88 '89 1990 '91 '92 '93 '94 '95 '96 '97 '98 '99 200 2001 20 2003 2004 2005 2008 2009 2010 2011
Legend!O.4 106.2 113.6 160.8 228. 233.9 197.9 100.8 165,8 199.1 262.9 34.2 378.5 420.1 396.3 480.3 500.1 413,9 461. 523.2 614.3 587.6 Earnings
per share (A)10.6 62,0 67.0 71.2 79.5 103,0 103.7 95.18 100.7 99.66 105,7 116.6 131. 136.1 151.1 168,5 172.1 181,1 189.7 210.7 239.7 257.8 Dividendspershare
i6.7 945.0 986,5 1009 1075 1276 1332 1301 1146 1118 1305 1337 1414 1594 1692 1638 1315 2464 2287 2810 3519 3584 Book
Value per share (B)9.8 12.5 15.8 14.1 9.0 10.7 13.4 31,8 19.7 17.7 14.2 13.1 15,2 17.7 21.8 21.8 21.5 24.7 20.0 17.2 16.8 17,9 14.5 Price-Earnings
Ratio (C)9.4 21.4 26.8 31. 25.9 24.4 26.0 30.4 30.9 34.9 35,3 38.6 43.8 54.7 57.1 62,2 62,4 56.4 48.6 42.8 43.0 40.9 26.6 Price'Divdend Rato
3.1 11.2 11.5 15,9 21.2 19.4 15.0 7.6 14.5 17.8 21. 26.0 27.5 27.9 24.1 28.8 33.9 21.9 19.4 20.5 19.4 16.5 13.4% Earned asa % 01
Book Vaue0.2 8.0 6.3 7.1 11. 9.3 7.5 3.2 5.1 5,7 7.0 7.6 6,6 5.6 4.6 4.6. 4,7 4.1 5,0 M 6.0 5.6 7.4% Eamed as a % of Avg, Price
5.1 4.7 3.7 3.1 3,9 4.1 4.0 2.8 3.2 2.9 2.8 2.6 2.3 1. 1.8 1.6 1:6 1. 2.1 2,3 2.3 2.4 4,2% Dividend
Yield1.8 -11.8 7.0 41.S 41.8 2.6 .18.0 -47.4 64.5 20.0 25.3 30.6. 10.3 11,0 -5.7 21.2 ,4.1 .17.2 11.4 13.5 17.4 -4.3 5.3% Earnings
Growt Rate7.6 2.3 8.1 6.2 11. 29.5 0.1 .10.0 14.3 .4.9 5.4 10:3 12,5 3.8 11.0 11,5 2.1 5.2 4.8 11.1 13.8 7,6 4.9% Dividend
Growt Rate3.2 3.1 4.4 2.3 6.5 12.2 5.8 4.3 -14.0 '2,5 16.8 2.5 5,7 12.7 6.1 '3,2 '19,7 87.3 .7.2 22.9 25.2 1.8 5.2% Book
Value Growth Rate2.0 .3.8 13.3 48,7 52,8 11.9 -10.6 -44.3 69.6 25.7 32.3 38.2 18.9 16.6 .1.1 25,8 8.8 '13.2 16.4 19.3 23.4 1.2 12.7% Earn'sas%oIPrice+Earn'sGrowth
2.8 7.0 11.8 9.4 15,6 33.6 4.1 -7,2 17.5 '2,0 8.2 12.9 14,8 5.6 12.8 13.1 3.7 7.0 6.8 13.4 16.1 10.0 9,2% OividendYield.!TlVidendGrowt
2.7 11.4 9.0 9.4 9.7 9.3 9.3 8.8 8.1 7.2 8.0 7.6 7.4 7.3 6.5 7,0 7.6 7." 6.5 5.7 5.6 5.2 5,9% Moody'sAaa Corp, Bond Yield
1.3 3.5 1.9 3.7 4, t 4.8 5.4 4.2 3.0 3.0 2.6 2,8 3.0 2.3 1.6 2.7 3.4 1.6 2.4 1.9 3.3 3.4 3.0% CPI Growt Rate:lnflallon
3.4 7.9 7.1 5.7 5.6 4.5 3.9 4.6 5.1 4.2 5.4 4.8 4.4 5.0 4.9 4.3 4,2 5.5 4.1 3,8 2,3 1.8 3,0% Real L.IAaa Corp. Bond Yield
87 1653 1956 2722 2184 2791 3000 3169 3413 3794 3978 5216 6561 8259 937411497 11723 11338 10634 10454 10855 10941 DJIAHighforYear87 1185 1502 1739 1879 2145 2365 2470 3137 3242 3593 3832 5033 83927539 9121 9796 8236 7285 7524 9750 10012 DJIALowforYer
78 1330 1797 2264 206 2510 2670 2933 3282 3565 3735 4494 5740 7448 8631 10482 10731 10209 9214 900710316 10547 OJIA
Average lor Year1.5 186,8 236.4 287.0 265.9 323.0 334.6 376.2 415.7 451.6 460.4 541.7670.5 873. 1086 1327 1427 1194 994 96 1131 1207 S&P500Avg,for'iear
'.1 159.8 200. 235.9 23,6 281. 262.0 302.2 353.7 420.2 455,1 518,0 621.0 787.6 896.9 971.5 1072 1174 1126 1224 1598 1803 Value
line Avg. lor Year33 4213 4453 4743 5108 5489 5803 5995 638 6657 7072 1398 7817 8304 8747 9268 9817 lU128 10470 10971 1734 12487 Gross Domesti Product (D)
133. (0) Gross National Product lrom: 1920 -1928. Facual materil is obtned Irom sourcs believd to be reliable, but the publisher is not reponsible lor errrs or omissions contined herein. Copyright 20 by Value Une Publishing, Inc.
40
EXHlBIT NO. 50, P. 3 of 3
Case No.: lPG-E-07-Q
D. Peseau, Micron
. '\
EXH,BliNU.505
Case No.: IPC-E-07 -08
D. Peseau, Micron
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28
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TO
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79
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33
OP
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52
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AM
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2
8
7
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(2
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1
9
4
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9
6
)
(5
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9
4
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)
(1
,
2
1
4
,
9
3
8
)
(1
,
9
5
3
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5
7
0
)
39
IN
V
E
S
T
M
E
N
T

T
A
X

C
R
E
D
I
T

A
D
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31

1,5
3
1
,
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8
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64
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8
9
36
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2
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32
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6
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7
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83
1
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9
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0
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40
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46
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9
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41
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4546
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I
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RA
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51
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15

of
78
1
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15
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SU
B
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252627
RE
T
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28
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TO
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79
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OP
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33
OP
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34
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36
TA
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40
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52
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37
RE
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A
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D
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B
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0
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F
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9
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4
4
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5
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39
IN
V
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T
M
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N
T

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A
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D
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31

1,
5
3
1
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9
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-
P
)
(9
-
5
)
(1
5
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(1
9
-
P
)
(2
4
-
S
)
24
0
DE
M
A
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-

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D1
0
0
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0
0
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24
1
DE
M
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-

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24
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n
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0
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24
3
EN
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-

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0
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24
4
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24
5
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N
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0
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0
0
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0
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24
6
0
24
7
TR
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24
8
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M
A
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1
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24
9
DE
M
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-

T
R
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3
0
0
0
0
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D
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-

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5
0
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M
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-

D
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3
5
0
9
0
0
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0
0
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0
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25
2
0
25
3
DI
S
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0
25
4
SU
B
S
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A
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-

G
E
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D2
0
0
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0
0
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25
5
SU
B
S
T
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T
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S

-

D
I
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3
6
0
2
0
0
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25
6
LI
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S

-

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M
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D2
0
0
0
0
0
0
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25
7
LI
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S

-

P
R
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M
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U
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0
0
0
0
0
0
0
0
0
25
8
LIN
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S

-

S
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A
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D
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3
6
4
7
0
0
0
0
0
0
0
0
25
9
LI
N
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T
R
A
N
S

-

P
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M
A
R
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D
E
M
A
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D
D5
0
0
0
0
0
0
0
0
0
26
0
LI
N
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T
R
A
N
S

-

P
R
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M
A
R
Y

C
U
S
T
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O
0
0
0
0
0
0
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26
1
LI
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R
A
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-

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3
6
8
0
0
0
0
0
0
0
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26
2
LI
N
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R
A
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-

S
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C
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N
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D
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M
A
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D6
0
0
0
0
0
0
0
0
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26
3
LI
N
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T
R
A
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S

-

S
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C
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C6
0
0
0
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0
0
0
0
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26
4
LI
N
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S

-

S
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C
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A
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Y

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M
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D
D3
0
0
0
0
0
0
0
0
0
26
5
LI
N
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S

-

S
E
C
O
N
D
A
R
Y

C
U
S
T
O
M
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R
C3
0
0
0
0
0
0
0
0
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26
6
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R
V
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3
6
9
0
0
0
0
0
0
0
0
26
7
ME
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3
7
0
0
0
0
0
0
0
0
0
26
8
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R
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L
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3
7
3
0
0
0
0
0
0
0
0
26
9
IN
S
T
A
L
L

O
N

C
U
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T

P
R
E
M
I
S
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DA
3
7
1
0
0
0
0
0
0
0
0
27
0
0
27
1
CU
S
T
O
M
E
R

A
C
C
O
U
N
T
I
N
G
0
It

M
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R
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A
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CW
9
0
2
0
0
0
0
0
0
0
0
CU
S
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M
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R

A
C
C
O
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N
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9
0
3
0
0
0
0
0
0
0
0
2
U
N
C
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L
L
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C
T
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B
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9
0
4
0
0
0
0
0
0
0
0
27
5
MI
S
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C1
0
0
0
0
0
0
0
0
0
27
6
0
27
7
CO
N
S
U
M
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R

I
N
F
O
R
M
A
T
I
O
N
0
27
8
CU
S
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M
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R

A
S
S
I
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T
C1
0
0
0
0
0
0
0
0
0
27
9
SA
L
E
S

E
X
P
E
N
S
E
CL
0
0
0
0
0
0
0
0
0
28
0
AD
V
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T
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C1
0
0
0
0
0
0
0
0
0
28
1
MI
S
C
CL
0
0
0
0
0
0
0
0
0
28
2
0
28
3
MI
S
C
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L
L
A
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O
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0
28
4
DE
M
A
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D9
9
U
0
0
0
0
0
0
0
0
28
5
EN
E
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E9
9
U
0
0
0
0
0
0
0
0
28
6
CU
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C1
0
0
0
0
0
0
0
0
0
28
7
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V
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2
0
0
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28
8
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1
0
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0
0
0
0
0
0
28
9
SU
B
S
T
A
T
I
O
N

C
I
A
C
CI
A
C
(2
2
,
2
3
6
,
3
3
1
)
(8
3
,
1
8
2
)
(3
6
7
,
4
9
7
)
(9
0
,
5
9
8
)
(1
3
8
,
2
1
8
)
(6
4
)
(6
,
7
2
5
,
0
6
5
)
(6
0
,
2
5
9
)
29
0
Ex
h
i
b
i
t

N
o
.

5
0
6
29
1
TO
T
A
L
S
PA
G
E
2
F
(2
2
,
2
3
6
,
3
3
1
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(8
3
,
1
8
2
)
(3
8
7
,
4
9
7
)
(9
0
,
5
9
8
)
(1
3
8
,
2
1
8
)
(6
4
)
(6
,
7
2
5
,
0
6
5
)
(6
0
,
2
5
9
)
Ca
s
e

N
o
.

I
P
C
-
E
-
0
7
-
0
8
0,

P
e
s
e
a
u
,

M
i
c
r
o
n
23

of

78

23
2
ID
A
H
O

P
O
W
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R

C
O
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P
A
N
Y
PA
G
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2
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23
3
CL
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C
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S
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S
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23
4
TW
E
L
V
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M
O
N
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E
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3
1
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2
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23
5
..

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A
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4
.

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.
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23
6
(I
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(J
)
(K
)
(L
)
(M
)
(N
)
23
7
FU
N
C
T
I
O
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AL
L
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A
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I
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N
TO
T
A
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UN
M
E
T
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R
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D
MU
N
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C
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A
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TR
A
F
F
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SC
SC
SC
23
8
FA
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T
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N
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L
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CO
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R
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DO
E
J
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JR
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P
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23
9
PR
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U
C
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I
O
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(4
0
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(4
1
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(4
2
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24
0
DE
M
A
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D

-

P
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W
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P
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0
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24
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24
2
DE
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n
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24
3
EN
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.

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24
4
EN
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0
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24
5
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o
n
-
S
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0
0
0
0
0
0
0
24
6
24
7
TR
A
N
S
M
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S
S
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0
0
0
0
0
0
0
24
8
DE
M
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S
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P
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Dl
1
0
0
0
0
0
0
0
--
DE
M
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T
R
A
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M
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3
0
0
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DE
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S
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B
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D1
5
0
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0
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D
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3
5
0
9
0
0
0
0
0
0
0
25
2
25
3
DI
S
T
R
I
B
U
T
I
O
N
25
4
SU
B
S
T
A
T
I
O
N
S

-

G
E
N
E
R
A
L
D2
0
0
0
0
0
0
0
0
25
5
SU
B
S
T
A
T
I
O
N
S

-

D
I
R
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C
T
DA
3
6
0
2
0
0
0
0
0
0
0
25
6
LI
N
E
S

-

P
R
I
M
A
R
Y

D
E
M
A
N
D
D2
0
0
0
0
0
0
0
0
25
7
LIN
E
S

-

P
R
I
M
A
R
Y

C
U
S
T
O
M
E
R
C2
0
0
0
0
0
0
0
0
25
8
LIN
E
S

-

S
E
C
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N
D
A
R
Y

D
I
R
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C
T
DA
3
6
4
7
0
0
0
0
0
0
0
25
9
LIN
E

T
R
A
N
S

-

P
R
I
M
A
R
Y

D
E
M
A
N
D
DS
O
0
0
0
0
0
0
0
26
0
LIN
E

T
R
A
N
S

-

P
R
I
M
A
R
Y

C
U
S
T
C5
0
0
0
0
0
0
0
0
26
1
LIN
E

T
R
A
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S

-

S
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C
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N
D

D
I
R
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C
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DA
3
6
8
0
0
0
0
0
0
0
26
2
LIN
E

T
R
A
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S

-

S
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C
O
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D

D
E
M
A
N
D
D6
0
0
0
0
0
0
0
0
26
3
LIN
E

T
R
A
N
S

-

S
E
C
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D

C
U
S
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M
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C6
0
0
0
0
0
0
0
0
26
4
LIN
E
S

-

S
E
C
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N
D
A
R
Y

D
E
M
A
N
D
D3
0
0
0
0
0
0
0
0
26
5
LI
N
E
S

-

S
E
C
O
N
D
A
R
Y

C
U
S
T
O
M
E
R
C3
0
0
0
0
0
0
0
0
26
6
SE
R
V
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C
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CW
3
9
0
0
0
0
0
0
0
26
7
ME
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CW
3
7
0
0
0
0
0
0
0
0
26
8
ST
R
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L
I
G
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DA
3
7
3
0
0
0
0
0
0
0
26
9
IN
S
T
A
L
L

O
N

C
U
S
T

P
R
E
M
I
S
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S
DA
3
7
1
0
0
0
0
0
0
0
27
0
27
1
CU
S
T
O
M
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R

A
C
C
O
U
N
T
I
N
G
,
ME
T
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R

R
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A
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CW
9
0
2
0
0
0
0
0
0
0
CU
S
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O
M
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R

A
C
C
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U
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T
S
CW
9
0
3
0
0
0
0
0
0
0
UN
C
O
L
L
E
C
T
I
B
L
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S
CW
9
0
4
0
0
0
0
0
0
0
27
5
MI
S
C
C1
0
0
0
0
0
0
0
0
27
6
27
7
CO
N
S
U
M
E
R

I
N
F
O
R
M
A
T
I
O
N
27
8
CU
S
T
O
M
E
R

A
S
S
I
S
T
C1
0
0
0
0
0
0
0
0
27
9
SA
L
E
S

E
X
P
E
N
S
E
C1
0
0
0
0
0
0
0
0
28
0
AD
V
E
R
T
I
S
I
N
G
C1
0
0
0
0
0
0
0
0
28
1
MI
S
C
CL
0
0
0
0
0
0
0
0
28
2
28
3
MI
S
C
E
L
L
A
N
E
O
U
S
28
4
DE
M
A
N
D
D9
9
U
0
0
0
0
0
0
0
28
5
EN
E
R
G
Y
E9
9
U
0
0
0
0
0
0
0
28
6
CU
S
T
O
M
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R
C1
0
0
0
0
0
0
0
0
28
7
RE
V
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N
U
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2
0
0
0
0
0
0
0
28
8
OT
H
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R
RO
l
0
0
0
0
0
0
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28
9
SU
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S
T
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T
I
O
N

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I
A
C
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C
(2
2
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2
3
6
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3
3
1

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7
8
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2
6
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8
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0
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2
9
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4
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7
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3
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29
0
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h
i
b
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o
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0
6
29
1
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2
3
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8
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8
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0
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2
9
2
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4
,
6
8
0
,
7
2
3
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s
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o
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E
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0
7
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8
D.

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e
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e
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u
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M
i
c
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n
24

of

78

29
2
ID
A
H
O

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PA
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H
29
3
CL
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4
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29
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6
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(B
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29
7
FU
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A
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29
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DE
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0
31
2
0
31
3
DI
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31
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SU
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31
6
LI
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D2
0
10
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7
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17
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31
7
LI
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0
5,7
9
8
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0
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1
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2
39
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5
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31
8
LI
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31
9
LI
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0
28
1
11
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0
30
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32
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0
15
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32
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32
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LI
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32
5
LI
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S
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7
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4
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5
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32
6
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3
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7
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3
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9
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1
50
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4
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4
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26
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32
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ME
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3
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32
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9
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3
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7
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4
,
3
6
1
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0
33
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0
33
1
CU
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SU
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C
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35
Ex
h
i
b
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t

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o
.

5
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6
35
1
TO
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2
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29
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8
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9
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2
2
8
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6
4
5
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6
6
9
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3
8
8
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2
2
2
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2
9
7
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2
2
8
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7
1
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6
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3
)
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1
2
5
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2
0
7
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2
9
7
Ca
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o
.

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-
0
7
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8
D.

P
e
s
e
a
u
,

M
i
c
r
o
n
25

of
78

29
2
ID
A
H
O

P
O
W
I
:
R

C
O
M
P
A
N
Y
PA
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2
H
29
3
CL
A
S
S

C
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T

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F

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I
:
R
V
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C
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:

S
T
U
D
Y
29
4
TW
I
:
L
V
I
:

M
O
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H
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I
:
N
D
I
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(
Ö

D
I
:
C
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:
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6
1
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R

3
1
,

2
0
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7
29
5
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5
.

C
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l
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l
:
29
6
(I
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(J
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(K
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)
29
7
FU
N
C
T
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N
AL
L
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C
A
T
I
O
N
TO
T
A
L
S
UN
M
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MU
N
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TR
F
F
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SC
SC
SC
29
8
FA
C
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N
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ST

L
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CO
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DO
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N
L
JR
S
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M
P
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MI
C
R
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N
29
9
(4
0
)
(4
1
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)
30
0
DE
M
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-

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30
1
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30
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DE
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30
3
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a
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30
4
EN
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a
0
0
0
0
30
5
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.

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S
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m
m
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0
N
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0
0
0
0
0
0
0
30
6
30
7
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M
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I
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N
0
30
8
DE
M
A
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.

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P
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1
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a
a
a
0
0
0
30
9
DE
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D

-

T
R
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M
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S
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3
0
a
0
0
0
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a
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DE
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A
N
D
.

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U
B
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S
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5
0
0
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0
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0
a
DE
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.

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I
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C
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3
5
0
9
0
0
0
0
0
0
a
31
2
31
3
DI
S
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B
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T
I
O
N
31
4
SU
B
S
T
A
T
I
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S

-

G
E
N
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R
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L
D2
0
0
0
0
0
0
0
0
31
5
SU
B
S
T
A
T
I
O
N
S
.

D
I
R
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C
T
DA
3
6
0
2
0
0
0
0
0
0
0
31
6
LI
N
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S

-

P
R
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M
A
R
Y

D
E
M
A
N
D
D2
0
10
,
2
0
9
,
7
6
7
14
,
5
9
6
18
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5
2
6
2,
3
1
4
0
0
0
31
7
LI
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.

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R
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M
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R
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C
U
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7
9
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0
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1
21
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4
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5
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0
31
8
LI
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M
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29

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78

41
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4
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6
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4
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44
6
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44
7
ME
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8
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44
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45
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45
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2
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3
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4
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0
0
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0
0
45
5
MI
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0
45
6
45
7
CO
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M
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31

of
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47
2
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A
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M
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34

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59
2
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P
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M
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41

of

78

77
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M
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P
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M
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n
49

of
78

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8
9
6
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(5
,
9
4
1
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(1
,
2
1
4
,
9
3
8
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(1
,
9
5
3
,
5
7
0
)
Ca
s
e

N
o
.

I
P
C
-
E
-
0
7
-
0
8
D.

P
e
s
e
a
u
,

M
i
c
r
o
n
51

o
f

7
8
10
7
2
ID
A
H
U

P
U
W
E
R

C
U
M
P
A
N
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PA
G
E
3
H
10
7
3
CL
A
S
S

C
U
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T

U
F

S
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R
V
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C
E

S
T
U
D
Y
10
7
4
TW
E
L
V
E

M
U
N
T
H
l
:

E
N
D
I
N
G

D
E
C
E
M
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3
1
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2
0
0
7
10
7
5
-
T
A
B
L
E

1
8
.

P
R
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T
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10
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10
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7
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N
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I
O
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M
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N
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A
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A
F
F
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C
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SC
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7
8
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CO
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DO
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10
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9
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0
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1
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5
6
5
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5
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6
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7
5
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5
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5
7
7
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10
8
2
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A
N
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7
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3
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3
2
3
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6
7
9
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9
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3
5
2
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10
8
3
EN
E
R
G
Y

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0
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9
1
5
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2
8
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9
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2
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6
6
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1
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9
7
5
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7
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8
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2
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10
8
5
EN
E
R
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m
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9
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8
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9
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10
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7
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8
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7
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7
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2
5
8
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7
7
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9
0
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3
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5
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0
0
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2
3
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9
6
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E
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0
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5
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3
9
2
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2
2
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5
5
0
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9
4
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0
0
0
10
9
7
LI
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E
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5
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2
0
0
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7
9
5
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4
5
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3
8
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0
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0
10
9
8
LI
N
E
S

-

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3
6
4
7
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2
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4
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9
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2
9
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6
4
5
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9
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0
11
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6
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7
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2
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1
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0
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0
11
0
1
LI
N
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R
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3
8
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7
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4
5
0
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0
0
0
0
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8
5
0
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0
11
0
2
LI
N
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T
R
A
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S
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C
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N
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D6
0
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0
2
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0
8
0
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2
5
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(1
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0
4
7
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3
1
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0
0
0
11
0
3
LI
N
E

T
R
A
N
S

-

S
E
C
O
N
D

C
U
S
T
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M
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R
C6
0
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8
5
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1
2
6
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(1
,
0
5
5
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(8
5
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(8
1
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0
0
0
11
0
4
LI
N
E
S

-

S
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C
O
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D
A
R
Y

D
E
M
A
N
D
D3
0
(1
7
4
,
6
6
3
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(3
9
9
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(5
0
6
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(6
3
)
0
0
0
11
0
5
LI
N
E
S

-

S
E
C
O
N
D
A
R
Y

C
U
S
T
O
M
E
R
C3
0
(9
9
,
2
0
0
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(3
8
0
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(3
1
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(2
9
)
0
0
0
11
0
6
SE
R
V
I
C
E
S
CW
3
6
9
(1
7
0
,
9
3
9
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0
0
0
0
(1
9
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0
11
0
7
ME
T
E
R
S
CW
3
7
0
(1
7
7
,
7
5
6
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(2
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(3
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(1
1
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(3
6
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(4
9
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(2
0
9
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11
0
8
ST
R
E
E
T

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I
G
H
T
S
DA
3
7
3
(1
3
,
3
8
2
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0
(1
3
,
3
3
1
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0
0
0
0
11
0
9
IN
S
T
A
L
L

O
N

C
U
S
T

P
R
E
M
I
S
E
S
CW
I
N
S
T
A
L
(8
,
3
5
6
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(2
4
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(2
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(2
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0
0
0
11
1
0
11
1
1
CU
S
T
O
M
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R

A
C
C
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N
T
I
N
G
.
ME
T
E
R

R
E
A
D
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9
0
2
0
0
0
0
0
0
0
CU
S
T
O
M
E
R

A
C
C
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U
N
T
S
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9
0
3
0
0
0
0
0
0
0
UN
C
O
L
L
E
C
T
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B
L
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9
0
4
0
0
0
0
0
0
0
11
1
5
MI
S
C
C1
0
0
0
0
0
0
0
0
11
1
6
11
1
7
CO
N
S
U
M
E
R

I
N
F
O
R
M
A
T
I
O
N
11
1
8
CU
S
T
O
M
E
R

A
S
S
I
S
T
C1
0
0
0
0
0
0
0
0
11
1
9
SA
L
E
S

E
X
P
E
N
S
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C1
0
0
0
0
0
0
0
0
11
2
0
AD
V
E
R
T
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I
N
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C1
0
0
0
0
0
0
0
0
11
2
1
MI
S
C
C1
0
0
0
0
0
0
0
0
11
2
2
11
2
3
MI
S
C
E
L
L
A
N
E
O
U
S
11
2
4
DE
M
A
N
D
D9
9
U
0
0
0
0
0
0
0
11
2
5
EN
E
R
G
Y
E9
9
U
0
0
0
0
0
0
0
11
2
6
CU
S
T
O
M
E
R
C1
0
0
0
0
0
0
0
0
11
2
7
RE
V
E
N
U
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R0
2
0
0
0
0
0
0
0
11
2
8
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H
E
R
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1
0
0
0
0
0
0
0
11
2
9
SU
B
S
T
A
T
I
O
N

C
I
A
C
CI
A
C
0
0
0
0
0
0
0
11
3
0
Ex
h
i
b
i
t

N
o
,

5
0
6
11
3
1
TO
T
A
L
S
PA
G
E
3
H
SC
R
E
W
E
D

UP

(1
3
,
8
4
2
)
(2
2
,
3
4
4
)
(3
,
1
4
0
)
(8
2
,
5
7
3
)
(8
2
,
3
7
4
)
(3
0
2
,
2
6
7
)
Ca
s
e

N
o
,

I
P
C
-
E
-
0
7
-
0
8
D.

P
e
s
e
a
u
,

M
i
c
r
o
n
52

of

78

11
3
2
ID
A
H
O

P
O
W
~
R

C
O
M
P
A
N
Y
PA
G
E

31

11
3
3
CL
A
S
S

C
O
S
T

O
F

S
~
R
V
I
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~

S
T
U
D
Y
11
3
4
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~
L
V
~

M
O
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~
N
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I
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(
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D
~
C
~
M
6
~
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3
1
,

2
0
0
7
11
3
5
..
T
A
B
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1
9

-
I
N
V
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S
T
M
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T
A
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C
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D
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A
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L
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C
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S
11
3
6
(A
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(B
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(C
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(D
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(E
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(F
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(G
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(H
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11
3
7
FU
N
C
T
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AL
L
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C
A
T
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TO
T
A
L
S
GE
N
S
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GE
N
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P
O
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R
IR
R
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A
T
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11
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C
T
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A
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R
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C
O
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LI
G
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PR
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M
A
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SE
C
O
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D
A
R
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11
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9
(1
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(9
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5
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(1
5
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9
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4
-
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11
4
0
DE
M
A
N
D
.

P
O
W
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R

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U
P
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D1
0
33
8
,
1
7
7
0
0
0
0
0
0
0
11
4
1
DE
M
A
N
D

-

S
u
m
m
e
r
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0
S
0
79
,
6
0
7
4,1
4
4
5,0
7
3
50
,
0
4
5
0
27
,
6
1
3
57
,
4
2
5
11
4
2
DE
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A
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D

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N
o
n
-
S
u
m
m
e
r
D1
0
N
S
0
34
,
2
6
7
1,
5
8
4
2,
5
8
7
23
,
8
4
5
0
14
,
4
0
19
,
4
8
7
11
4
3
EN
E
R
G
Y

-

P
O
W
E
R

S
U
P
P
L
Y
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0
40
7
,
8
0
0
0
0
0
0
0
0
0
11
4
4
EN
E
R
G
Y

-

S
u
m
m
e
r
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0
S
0
47
,
9
2
2
2,1
6
9
3,6
1
4
32
,
9
3
9
57
21
,
1
3
7
41
,
8
7
9
11
4
5
EN
E
R
G
Y

-

N
o
n
-
S
u
m
m
e
r
El
0
N
S
0
10
1
,
2
7
8
4,1
0
5
6,
8
6
7
60
,
1
2
8
11
8
41
,
0
5
6
12
,
2
2
1
11
4
6
0
11
4
7
TR
N
S
M
I
S
S
I
O
N
0
11
4
8
DE
M
A
N
D

-

P
O
W
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R

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U
P
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1
0
0
0
0
0
0
0
0
.
DE
M
A
N
D

-

T
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3
27
7
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2
2
5
98
,
9
3
2
4,8
8
0
6,
0
5
4
58
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5
6
2
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(1
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5
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78

11
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T
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11
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11
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PR
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12
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1
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36
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2
4
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3
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3
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16
7
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63
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1
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7
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0
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D.

P
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M
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57

of

78

12
5
2
ID
A
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5
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3
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7
4
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1
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0
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3
6
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2
43
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4
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8
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3
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9
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02
0
3,
2
2
9
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9
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8
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5
0
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7
LI
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.

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1
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1
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6
0
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LI
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3
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27
9
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5
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8
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0
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5
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12
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-

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0
98
5
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5
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2
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0
58
6
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9
7
9
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3
3
20
7
14
5
0
0
0
12
8
6
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R
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3
6
9
37
4
,
3
9
9
0
0
0
0
37
0
12
8
7
ME
T
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3
7
0
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1
7
6
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1
2
1
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32
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28
2
34
0
1,1
9
5
12
8
8
ST
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3
7
3
42
,
4
4
0
0
42
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3
2
7
0
0
0
0
12
8
9
IN
S
T
A
L
L

O
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C
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P
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I
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S
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A
L
6,
4
8
4
0
0
0
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2
0
12
9
0
12
9
1
CU
S
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A
C
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9
0
2
0
0
0
0
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CU
S
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9
0
3
0
0
0
0
0
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0
UN

CO
L
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C
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9
0
4
0
0
0
0
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0
12
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5
MI
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12
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6
12
9
7
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N
S
U
M
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R

I
N
F
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M
A
T
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12
9
8
CU
S
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A
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0
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0
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12
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9
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0
0
0
0
13
0
0
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0
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13
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1
MI
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13
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2
0
13
0
3
MI
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0
13
0
4
DE
M
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D
D9
9
U
0
0
0
0
0
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13
0
5
EN
E
R
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9
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0
0
0
0
0
0
0
13
0
6
CU
S
T
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0
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0
0
0
0
0
0
13
0
7
RE
V
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N
U
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R0
2
0
0
0
0
0
0
0
13
0
8
OT
H
E
R
IN
T
F
U
N
D
0
0
0
0
0
0
0
13
0
9
SU
B
S
T
A
T
I
O
N

C
I
A
C
0
(1
8
9
,
3
3
4
)
13
1
0
EX
h
i
b
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t

N
o
.

5
0
6
13
1
1
TO
T
A
L
S
47
,
0
9
6
,
6
8
0
80
,
0
2
5
10
3
,
0
0
4
15
,
3
0
1
43
8
,
4
8
5
43
3
,
1
2
2
1,5
3
8
,
7
7
7
Ca
s
e

N
o
.

I
P
C
-
E
-
0
7
-
0
8
D.

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M
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59

of

78

1
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C
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C
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60

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(A
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67
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68

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T
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77

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83

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D.

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7
8