20100324Reply Comments.pdf

BARTON L. KLINE
Lead Counsel
bklinecæidahopower.com
March 23, 2010
'..",
VIA HAND DELIVERY
Jean D. Jewell, Secretary
Idaho Public Utilities Commission
472 West Washington Street
P.O. Box 83720
Boise, Idaho 83720-0074
etlDA~POR(I
An IDACORP Company
Re: Case No. IPC-E-10-01
IN THE MATTER OF THE APPLICA TlON OF IDAHO POWER COMPANY
TO ESTABLISH ITS BASE LEVEL FOR NET POWER SUPPL Y EXPENSES
FOR 2010
Dear Ms. Jewell:
Enclosed please find for filing an original and seven (7) copies of Idaho Power
Company's Reply Comments in the above matter.V61~
Barton L. Kline
BLK:csb
Enclosures
P.O. Box 70 (83707)
1221 W. Idaho St.
Boise. ID 83702
f"~:: i~. ';..~, !
BARTON L. KLINE (ISB No. 1526)
LISA D. NORDSTROM (ISB No. 5733)
Idaho Power Company
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
bklinecæidahopower.com
Inordstrorncæidahopower.com
2fJB HM~ 2? PI..\ v 14:19
Attorneys for Idaho Power Company
Street Address for Express Mail:
1221 West Idaho Street
Boise, Idaho 83702
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MA TIER OF THE APPLICATION
OF IDAHO POWER COMPANY TO
ESTABLISH ITS BASE LEVEL FOR NET
POWER SUPPLY EXPENSES FOR 2010.
)
) CASE NO. IPC-E-10-01
)
) REPLY COMMENTS OF IDAHO
) POWER COMPANY
)
COMES NOW Idaho Power Company ("Idaho Power" or the "Company") and
hereby responds to the Comments filed in this case by the Commission Staff ("Staff')
the Industrial Customers of Idaho Power ("ICIP") and the Idaho Irrigation Pumpers
Association, Inc. ("Irrigators"). ICIP and Irrigators are sometimes collectively referred to
as "Intervenors."
i.
BACKGROUND
The Comments of the Staff and ICIP have provided a detailed description of the
procedural background that led to the filing of this case. There is no need to repeat all
REPLY COMMENTS OF IDAHO POWER COMPANY - 1
of that history in these Comments. Idaho Power's intention to file this case was
expressed in the Settlement Stipulation the Commission approved in Case No. IPC-E-
09-30. All of the Parties in this case signed that Stipulation and agreed that the rate
case moratorium approved in Order No. 30978 would not apply to a case such as this
one where the Company is asking to update its Net Power Supply Expenses ("NPSE")
from the currently approved 2008 levels to 2010 levels.
II.
ISSUES TO BE ADDRESSED
For the most part, Staff, Irrigators and ICIP identify the same items as potential
adjustments to the NPSE filed by the Company. Attachment A to Staffs Comments
assigns a value to each of these items based on the differences between the
Company's cost for an item in its 2008 NPSE and the cost of the item in the 2010
NPSE filed in this case. These Comments wil address the items at issue in the order of
the magnitude of their impact on the Company's request in this case.
A. Increased Bridger Coal Costs.
Undoubtedly, the single biggest cause of the increase in NPSE for 2010 is the
fact that the Company is going to have to pay more for the coal it burns to fuel its Jim
Bridger Power Plant ("the Bridger Plant" or "Plant") than it did in 2008.
Idaho Power and PacifiCorp co-own the Bridger Plant, and its associated mining
operation, the Bridger Coal Company ("BCC"). The Plant is run primarily on coal from
the BCC's surface and underground mining operations. Supplemental coal is
purchased from the nearby Black Butte mine ("Black Butte"), which is operated by
Kiewit Mining. The Bridger Plant was designed and constructed as a "mine-mouth"
REPLY COMMENTS OF IDAHO POWER COMPANY - 2
plant, which means it is physically located next to the coal mine that supplies the
majority of its coaL. This arrangement ensures that the Plant has access to a
continuous and reliable supply of coaL. Coal is delivered to the Plant from the BCC
mine by use of a large conveyor belt system that transports and delivers coal directly
from the mining operation into the Plant. This type of mine-mouth plant operation has
several advantages over an operation where the coal is delivered from another location.
First, the mine-mouth operation has the obvious advantage of eliminating the need to
ship coal over long distances in order to supply the generating plant - uSually at great
expense and subject to transportation interruptions. In addition, the mine-mouth
operation avoids the undesirable result of locating the coal-fired generation plant in
close proximity to large population centers, which typically correspond to the large load
centers.
The BCC surface mine commenced commercial operation in August 1974 and
has been producing coal for the Bridger Plant since that time. BCC started producing
coal from its underground mining operations in March 2007. The surface and
underground mines are run as an integrated operation. While the underground mine
provides the majority of the coal to the Bridger Plant, the surface operation provides: (1)
coal critical to the blending process, (2) additional overall mine capacity, (3) flexibility in
running the underground operations, (4) a hedge against increased prices of non-owned
coal, and (5) support for the costs common to both the surface and underground
operations of BCC.
In their Comments on the Bridger Plant coal cost issue, Idaho Staff and
Intervenors all note that the Staff of the Public Utility Commission of Oregon ("OPUC")
REPLY COMMENTS OF IDAHO POWER COMPANY - 3
has filed testimony in a current Company proceeding in Oregon in which the Oregon
Staff recommends a downward adjustment to Bridger Plant coal costs. OPUC Staff
asserts that the costs of the surfaced-mined coal purchased by the Company from BCC
for the Bridger Plant exceeds the cost of coal from the Black Butte mine and therefore
purchases of BCC surface coal violates the OPUC's "lower of cost or market" rule.
OPUC Staff argues that the two companies should have reduced their purchases of
BCC's surface coal - which is more expensive to produce than BCC's underground coal
- and made additional purchases from the Black Butte mine.
In this Idaho case, the Comments of the ICIP make a similar recommendation for
a downward adjustment to the Company's filed Bridger coal expense. The ICIP adopts
the same arguments and cost calculations advanced by the OPUC Staff In the Oregon
case to support its recommendation in this case. Idaho Power has carefully reviewed
the analyses and arguments presented by the OPUC Staff in support of its
recommendation in Oregon. Based on that review, the Company has concluded that
OPUC Staffs recommendation is fundamentally flawed. First, Black Butte does not
have suffcient production capacity to mine enough coal to replace the BCC surface coal
volumes the Plant needs. While Black Butte may have a small amount of additional
capacity to produce coal, that additional coal wil cost more than the savings attributable
to the BCC coal it would replace. Second, OPUC Staff improperly calculated the cost of
BCC's surface coal when it compared the cost of BCC coal to the cost of Black Butte
coaL. The Company's analysis shows that following the OPUC Staffs recommendation
and eliminating purchases of BCC surface coal and replacing that coal with Black Butte
coal would increase the annual cost of coal for the Bridger Plant by approximately $6
REPLY COMMENTS OF IDAHO POWER COMPANY - 4
milion per year. Third, the non-price benefits of the BCC contract to Idaho Power's
customers are substantiaL. These benefits include the use of BCC coal in the blending
process to produce a mixture that allows the most efficient operation of the Bridger
Plant. Availabilty of BCC surface coal adds valuable flexibility for the Plant to use BCC
operations as a hedge against unexpected production decreases at Black Butte and to
provide protection against possible future price increases for non-owned coaL.
These Comments provide support for the Company's conclusion that the OPUC
Staff, and therefore the ICIP, are basing their recommendations for a downward
adjustment to Bridger Coal costs on erroneous analyses. However, the task of
developing and implementing a prudent long-term strategy for providing fuel for a large
coal-fired power plant like the Jim Bridger plant, is complex. To help the Commission
gain a better understanding of the Company's Bridger fuel strategy, Idaho Power has
enclosed with these Comments three attachments. The first attachment is a "white
paper" which has previously been provided to the parties to this case in discovery.
Attachments Nos. 2 and 3 are the reply testimony and exhibits of Greg Said and Tom
Harvey which were filed with the Oregon Public Utility Commission on Wednesday,
March 17, 2010. These three documents provide an in-depth analysis of the reasons
why the OPUC Staffs recommendation (and therefore ICIP's recommendation) for a
downward adjustment in Bridger fuel costs is neith er logical no r in Idaho Power's
customers' best interest fair. These Comments wil make periodic references to specific
portions of those three Attachments. Attachments Nos. 1, 2, and 3 provide detailed,
verifiable evidence exposing the flaws in the OPUC Staffs' position on Bridger coal
costs in the Oregon case and ICIP's similar positions in this case.
REPLY COMMENTS OF IDAHO POWER COMPANY - 5
1. ICIP Erroneously Concludes That Additional, Lower Cost,
Black Butte Coal Is Available.
On page 7 of its Comments, ICIP acknowledges that it has been advised that
". . . the Black Butte coal is either an unavailable replacement or of an unsuitable quality
given the required coal quality and coal blending metrics required by the Bridger plant."
(ICIP Comments, p. 7.) However, ICIP then states that in the Company white paper
(Attachment No.1) Idaho Power has admitted that of lower cost Black
Butte coal is available. Idaho Power has made no such admission.
In its white paper and as Mr. Harvey notes on lines 13 through 17 on page 11 of
his reply testimony (Attachment No.3), even if Kiewit Mining has the capacity to
produce of additional Black Butte coal, there is no evidence that the
additional coal could be obtained at the same price under the existing contract. On the
contrary, the price quoted by Kiewit Mining for that uncommitted production was
substantially higher than the price paid to Kiewit under the existing Black Butte contract.
Kiewit Mining quoted an F.O.B. mine price of. per ton with an adjuster for changes
in diesel fuel costs, and for volumes, such as the above-referenced _ annual
tons, in excess of the new contract price. This price signifcantly exceeds the cost of
BCC coaL. As noted on pages 8-9 of Mr. Harvey's testimony (Attachment No.3), the
decremental cost of BCC surface coal is approximately" per ton. Replacing the
BCC coal as recommended by ICIP would save the Company approximately" per
ton and replacing it would cost at least. per ton. As a result, reducing purchases
from BCC and buying more coal from Black Butte would result in an increase in overall
coal costs. Additional purchases of Black Butte coal are not a viable alternative to
purchases from BCC.
REPLY COMMENTS OF IDAHO POWER COMPANY - 6
2. ICIP Incorrectly Concludes That Less Expensive Coal Is
Available To The Bridger Plant.
OPUC Staff asserts that the "market price" for coal should be equal to the Black
Butte price and that it would be less expensive if the Company were to purchase
"market priced coal" than to continue to purchase from both Bridger Coal Company and
Black Butte. ICIP adopts that same argument that there must be a cheaper alternative.
"Nevertheless it is likely there is a cheaper alternative to continuing to use the now _
very - costly surface-mine from BCC." (ICIP Comments, p. 8.) ICIP's speculation that
there is less expensive coal available is unfounded. In fact, there is no less expensive
market alternative and, overall, BCC coal is the lowest cost resource. In the enclosed
reply testimony of Tom Harvey (Attachment No.3) beginning on line 24 of page 7 and
continuing to line 11 on page 10, Mr. Harvey explains that while BCC's surface coal is
more expensive than its underground coal, the costs associated with any available
replacement coal are higher than the costs that Idaho Power could avoid if the surface
operation ended. As previously noted, BCC's underground and surface mines
constitute one integrated operation. As a result, many of the costs to run the BCC mine
are allocated to the coal produced by both the surface and underground mines. If the
surface mine were shut down, which is the logical implication of ICIP's adjustment,
many of the shared costs would not be avoided but would need to be reallocated to the
cost of the underground coaL. In other words, BCC cannot avoid all of the costs
allocated to the surface coal by shutting down the surface mine. So, for the purposes of
assessing whether there is a lower cost market alternative, the cost of the surface coal
should be considered at the cost BCC could avoid by shutting down the surface mine _
or the decremental cost of the BCC surface coaL. BCC calculated the decremental cost
REPLY COMMENTS OF IDAHO POWER COMPANY - 7
of surface coal based upon its most currently available mine plan. Based on that
analysis, the decremental cost of the surface coal at BCC is _ per ton. In order
to ensure a conservative estimate, the Company rounded this cost up to .. per ton.
The decremental cost analysis estimates that BCC would save approximately. for
every ton of surface coal not mined. That sum would therefore be available to purchase
replacement coaL. The only mine in the relevant market, the Green River Basin, is
Black Butte. Since Black Butte coal wil cost at least .. per ton at the Plant, it is
readily apparent that OPUC Staffs and ICIP's proposal to substitute more Black Butte
coal (if it were available) would be very expensive for customers.
The Company also investigated the possibilty of buying coal from the Power
River Basin ("PRB") in eastern Wyoming, approximately 566 miles from the Plant.
Idaho Power confirmed that the estimated cost to ship coal from the PRB to the Bridger
Plant is around. per ton, which is double the estimated .. per ton cost of the
coal itself. In total, the per ton cost of PRB coal, including transportation is likely to be
at least. per ton F.O.B. plant without adding in the additional costs that would be
incurred for freeze protection and dust suppression. Assuming that significant volumes
of PRB coal could be obtained and shipped to the Plant, use of coal from the mines in
the PRB would require significant capital investment in the Plant because of the
different quality and make-up of the coal compared to the blend of BCC and Black Butte
coal the Plant currently burns. These issues with the Powder River Basin coal make it
uneconomical to consider coal from that region as a possible fuel source for the Plant.
Mr. Harvey's testimony in Attachment No. 3 demonstrates that Idaho Power has
carefully considered all of the alternatives for providing fuel to Jim Bridger and has
REPLY COMMENTS OF IDAHO POWER COMPANY - 8
arrived at and implemented an overall fuel acquisition strategy that provides the lowest
cost for customers.
3. The Commission Should Allow Some Additional Time For
Review of the Company's Coal Acquisition Strategy for the
Bridger Plant.
The Comments of the Staff and the Intervenors all suggest that the issues
relating to Jim Bridger coal costs cannot be finally resolved prior to the Company's April
15, 2010, PCA filing. All three commentors indicate that because of the compressed
schedule for this case, they have been unable to complete their review of this issue.
Staff and the Intervenors suggest that the Commission undertake further review of the
coal cost issue in a subsequent proceeding. (See Staff Comments, p. 4; ICIP
Comments, p. 9; and Irrigators Comments, p, 9.) Idaho Power is confident that further
review of this issue by the Commission wil result in a Commission determination that
Idaho Power has acted prudently in managing its fuel costs for theJirn Bridger plant.
For that reason, the Company would not object to the Commission setting a reasonable
schedule for further proceedings to allow Staff and the Intervenors more time to review
Idaho Powets long-term strategy for acquiring coal for the Jim Bridger Plant.
The question then posed is what is the most appropriate ratemaking treatment
for Bridger coal costs during this additional review period? Idaho Power disagrees with
the position of the ICIP and the Irrigators that until such time as the Commission
completes its review of the Bridger coal cost issues, the Company's coal acquisition
strategy for the Bridger Plant should be treated as imprudent and the Company should
be denied recovery of its increased coal costs in its NPSE. This approach punishes the
REPLY COMMENTS OF IDAHO POWER COMPANY - 9
Company without providing any additional protection to customers. The Commission
Staff proposes a different approach. In its Comments, Staff stated:
Based on the information received to date, Staff has not identified any
justification for adjusting 2010 Bridger coal costs. Consequently, Staff
recommends that for now, Bridger coal costs be allowed at the level
proposed by Idaho Power in its Application, but that the Commission
reserve the right to make adjustments to Bridger coal costs allowed in
base rates in the context of Idaho Power's 2010 PCA filing. The
Company's annual PCA filing is expected to be submitted on April 15,
2010, with a final order due on May 15 in order to accommodate rate
changes that would be effective on June 1. (Staff Comments, p. 4.)
Idaho Power supports Staffs proposed ratemaking treatment because it is the
fair to both the Company and its customers.
ICIP's disagreement with Staffs proposal is based on misunderstanding of how
costs would be allocated between the Company and customers in the PCA if the
Commission were to ultimately conclude that the Company had acted imprudently in its
coal sourcing strategy. On page 11 of its Comments, ICIP argues that:
If the Commission allows these costs (2010 Bridger Coal surface
mining costs) into the base level NPSE for 2010 and then determines
after June. 1, 2010, that they are not prudent expenses, rate payers
would lose the ability to ever recover a refund of 5 percent of the
imprudent costs incurred after June 1 through a future PCA. (ICIP
Comments, p. 11.)
ICIP misunderstands the PCA process. Imprudent costs are not subject to the 95
percent/5 percent sharing. If the Commission were to find that the Company's
acquisition of Bridger Coal Company coal is imprudent, 100 percent of the imprudent
costs would be returned to customers. There is a zero chance that customers wil be
disadvantaged if Idaho Power is permitted to include its proposed 2010 Bridger coal
costs in its base level NPSE during the pendency of the review period. On the other
hand, if the Commission were to adopt ICIP's recommendation and assume today that
REPLY COMMENTS OF IDAHO POWER COMPANY - 10
the Company's decision to buy BCC surface coal was imprudent and exclude the
increased costs of BCC coal from base rates, and then, after all the facts were
presented, determine that the Company had acted prudently, the Company would only
recover 95 percent of its prudent expenses in a future PCA proceeding. This would be
a manifestly unfair and unnecessary result.
In summary, the enclosed Attachments Nos. 1-3 demonstrate that OPUC Staff
(and therefore ICIP) improperly calculated the cost of Bridger Coal Company surface
coal for comparison to alleged market alternatives. When the prices are properly
calculated, the cost the Company wil avoid if it replaces the BCC surface coal with coal
with Black Butte is actually less than it would pay for the replacement coal - assuming
suffcient Black Butte replacement coal could be obtained, which it cannot. Second,
using Black Butte coal as a proxy for the market is not valid because there is not
suffcient Black Butte coal to replace Bridger Coal Company surface coaL. Third, under
any reasonable scenario, it is clear that overall, BCC coal is the lowest cost resource.
Fourth, the non-price benefits of the Bridger Coal Company Contract to Idaho Power's
customers are substantiaL. These non-price benefits include the use of BCCcoal in the
blending process to produce.a blend of . coal that optimizes generation at the Bridger
Plant and the flexibilty to use BCC operations as a hedge against production shortalls
at Black Butte and price increases for non-owned coaL. The evidence presented in
these Comments demonstrates that the substitution of more Black Butte coal for Bridger
Coal Company coal is impractical and wil increase Idaho Power Company's customers'
risks and costs of power over both the short and long terms.
REPLY COMMENTS OF IDAHO POWER COMPANY - 11
4. Idaho Power Purchases from BCC Do Not Raise Any Issue of
Cross-Subsidization.
Idaho Power has an affiliate relationship with a company called Idaho Energy
Resources Company ("IERCO"). IERCO owns a one-third interest in BCC. In 1974,
PacifiCorp and Idaho Power entered into a long-term coal sales agreement with BCC.
Throughout its Comments, ICIP warns that because BCC is affliated with Idaho Power,
the Commission should be particularly vigilant in reviewing Idaho Power's Bridger Plant
coal acquisition strategy. ICIP's concern is not well founded. Since the mid-1970s, the
Commission has been aware of and acknowledged that the transactions between Idaho
Power and BCC pose no risk of cross-subsidization because of the unique manner by
which the Commission addresses IERCO's (the affliate that owns BCC) operations for
ratemaking purposes. Unlike other utilty affliates, for ratemaking purposes, IERCO's
operations are merged with those of Idaho Power. The Oregon PUC summed up the
situation in Order No. 91-566 when it approved the contract between Idaho Power and
BCC as follows:
. . . IERCO's results of operations have been merged, consolidated,
and included with Idaho's for purposes of filing of income tax returns
and for ratemaking purposes, there is no danger of cross-subsidization
between Idaho and IERCO nor is there any danger of Idaho paying in
excess of market value to hire IERCO or its assignees for the coal
purchased. Idaho is paying for its coal the same as if IERCO were not
even involved in this transaction. (OPUC Order No. 91-567 at p. 2.)
(Emphasis added)
While ICIP admits on page 5 of its Comments that there is "little risk" of cross-
subsidization of BCC by Idaho Power and its customers, ICIP argues that this affliate
relationship should stil make the Commission nervous. In fact, on page 12 of its
Comments, ICIP urges the Commission to issue a new order requiring that when Idaho
REPLY COMMENTS OF IDAHO POWER COMPANY - 12
Power's affiliate sells serves or supplies to Idaho Power, the sales be recorded in the
utility's accounts at the affiliates cost or the market rate, whichever is lower. ICIP
asserts that Idaho has no offcial policy on how to charge rate payers for a utilty's
affiliate provided expenses. (ICIP Comments p. 12.) At least with respect to Idaho
Power, ICIP's understanding of Commission policy is in error. In Order No. 30530
issued in Case No. IPC-E-01-08, the Commission approved a Revised Code of Conduct
for Idaho Power, IDACORP, and the Commission Staff that does precisely what ICIP
now requests the Commission to do. Specifically paragraph 8(g) of the Revised Code
of Conduct attachmed to Order No. 30530 provides as follows:
IDACORP and Idaho Power Company commit to use asymmetrical
pricing (i.e., lower of cost or market for transactions to Idaho Power
Company and higher of cost or market for transactions from IdahoPower Company) for affliate charges or costs not covered by
provisions of any cost sharing agreement or Service Level Agreements
(SLA), if a readily identifiable market for the goods, services or assets
exists, and if the transaction involves a cost of more than $100,000.
(Revised Code of Conduct P. 2).
The Company is, and always has, purchased coal for the Bridger Plant at the lower of
cost or market. No new orders or filing requirements are necessary.
VII.
ADJUSTMENT TO PURPA COSTS AND ADJUSTMENTS
TO HOKU. LOADS AND REVENUES
In its Comments, Staff identifies two areas where it recommends downward
adjustments to the Company's proposed NPSE. The first is an adjustment to the
Company's assumption of the level of expense the Company wil incur to purchase
energy from PURPA developers in the future. Idaho Power has signed fourteen new
PURPA contracts, all of which have scheduled operation dates in 2010. Staff argues
REPLY COMMENTS OF IDAHO POWER COMPANY - 13
that prior history indicates that even through PURPA developers agree in their signed
contracts that they wil come on-line at a particular time, they often do not. In its
Comments, Staff recites the history of a large group of PURPA projects that were
originally scheduled to come on-line in 2007. The PURPA developer now indicates
these projects wil come on-line by year-end 2010. While Idaho Power has no
independent knowledge that the PURPA projects it has identified for inclusion in 2010
wil not be on-line in 2010, Idaho Power acknowledges that prior history adds weight to
Staffs recommendation to remove the expected costs of these projects. Because the
Company is allowed to recover 100 percent of costs of PURPA contracts in its annual
PCA filings, the Company does not object to the adjustment recommended by Staff.
The other adjustment Staff proposes is to the Hoku loads and revenues. Staff
proposes downward adjustments to the Company's net power supply expense based on
the uncertainty associated with the amount of Hoku load and revenue in 2010. As it did
with the PURPA contracts, Staff recites the history of the Hoku Energy Sales
Agreement ("ESA") and correctly notes the delays that have been associated with that
ESA. Idaho Power included the Hoku expenses and revenues based on its contract
with Hoku. Idaho Power has no independent knowledge that Hoku wil not perform in
accordance with its contract. That being said, Idaho Power does not disagree with the
Staff that there is uncertainty associated with the Hoku loads and revenues and the
Company is willng to accept Staffs recommended adjustment in NPSE attributable to
the Hoku ESA.
REPLY COMMENTS OF IDAHO POWER COMPANY - 14
VII.
IRRIGATORS' CRITICISMS OF THE
AURORA MODEL ARE NOT WELL FOUNDED
The Irrigators' Comments spent relatively little time addressing the issues that
were the focal point of Staffs and ICIP's comments, i.e., Bridger coal costs, Hoku,
PURPA, etc. Instead the Irrigators focused the majority of their Comments on what they
believe to be errors in the Company's computations of net power supply expenses
attributable to the AURORA power supply economic dispatch modeL. Predictably,
Irrigators characterize the AURORA model as a "black box" and argue that its results
cannot be trusted.
1 Staff also reviewed Idaho Power's NPSE analysis in detail,
including its AURORA results. In general, Staff concluded that the results that Idaho
Power presented from its AURORA analysis were reasonable. On page 7 of its
Comments, Staff stated:
Each change in AURORA input data made by Idaho Power since its
2008 rate case was identified by Staff, its effect on NPSE was
estimated, and its reasonableness considered. Staff performed
multiple AURORA simulations using its own assumptions. Although
Staffs results differ from the Company's due to some of the issues
discussed previously, Staffs results with regard to surplus sales
revenue and non-PURPA purchases are very similar to Idaho Power's
results. Staff believes that the gas prices used by Idaho Power in its
AURORA analysis are reasonable, and agrees that surplus sales
revenue is likely to decline significantly in 2010 and the costs for non-
PURPA purchases wil increase due to more market purchases.
Perhaps one of the reasons the Irrigators' conclusions regarding the
reasonableness of the Company's results differ so dramatically from the Staffs is that
the Irrigators were not permitted to participate in the workshop held on March 2, 2010,
i Idaho Power has been using the AURORA model for more than 10 years. The Commission
Staff has used the AURORA model for almost as long. The model's results have been reviewed and
scrutinized in numerous proceedings. Hopefully, at some point AURORA will lose its "black box" status.
REPLY COMMENTS OF IDAHO POWER COMPANY - 15
in which the Company, the Staff, and the other intervenors discussed some of the
issues the Irrigators' raise in their Comments. Had the Irrigators participated in those
discussions, perhaps their concerns could have been allayed. For example, in their
Comments on pages 4 through 6, the Irrigators compare actual operations of the
Company's gas peaker plants to the operations AURORA modeled results for those
same units. The intent of the comparison is to show that actual generation differs from
the results shown in the Company's AURORA modeling and from that the Irrigators
conclude that the AURORA model must be doing something wrong. However,
Irrigators' Comments fail to recognize that the modeling undertaken in this case is
based on a normalized test period. In their Comments, the Irrigators are comparing
actual monthly generation to a normalized annual test period. This is a classic apples to
oranges comparison. This specific issue was addressed in the March 2, 2010,
workshop and it was pointed out by Staff and the Company that such a comparison
would be flawed and would not provide any valid insight into the reasönableness of the
AURORA results used in computing NPSE.
On page 6 of their Comments, the Irrigators also asserted that there are logic
problems with AURORA. In support of that assertion, they focused on modeled
generation of the Valmy plant .under 1982 hydro conditions and concluded that Valmy
was not economic to operate under those conditions. The Irrigators' erroneous
conclusion comes from a fundamental misunderstanding of the AURORA model. The
AURORA model is an economic dispatch modeL. The Valmy plant is a base load
resource that actually operates close to or near maximum capacity whenever it can. A
coal plant like Valmy is not operated to ramp up and down to meet hourly changes;
REPLY COMMENTS OF IDAHO POWER COMPANY -16
therefore, changes in loads are followed by other resources that are designed to ramp
up and down, such as hydro and/or gas-fired peaking resources. Contrary to the
Irrigators' assertion, during the 1982 hydro condition, Valmy is an economic resource
almost all of the time. Enclosed as Attachment No. 4 is a chart comparing the Valmy
operation and costs against surplus sales' prices during the similar 1982 hydro
condition. As Attachment No. 4 shows, Valmy was an economic resource throughout
the entire period.
In summary, none of the Irrigators' criticisms of the AURORA model are well
founded and certainly do not supply adequate support for the Commission to conclude
that the Company's filed NPSE for 2010 have been over stated.
IX.
CONCLUSION
In this case, Idaho Power is requesting authority to update its NPSE expenses to
2010 levels. There is general agreement among the Parties that Idaho Power should
be allowed to update its NPSE, but the amount of the update is where the Parties'
respective positions diverge.
Idaho Power is wiling to accept a reduced 2010 NPSE increase of $63,701,694
millon as proposed by Commission Staff. (Staff Comments p. 8.) Idaho Power would
not object to the Commission's adoption of Staffs recommendation that Staff and
Intervenors be allowed time to review Idaho Power's Jim Bridger coal costs. Based on
the Company's testimony and exhibits presented in this case, including Attachments
Nos. 1-3 enclosed with these Comments, Idaho Power believes it has made a prima
facie case that it has acted prudently in planning and implementing its fuel procurement
REPLY COMMENTS OF IDAHO POWER COMPANY -17
-c"'_
strategy for the Jim Bridger Power Plant. As such, the Commission should adopt the
Staffs recommendation to allow the Company's 2010 Bridger coal costs to be included
in base and PCA rates, subject to review and potential refund in the 2011 PC A.
Because the Company has made a prima facie case, Idaho Power submits that Staff,
ICIP and the Irrigators carry the burden going forward with the evidence on Bridger Coal
costs. Finally, Idaho Power requests that the Commission reject the other adjustments
to the 2010 NPSE as proposed by ICIP and Irrigators.
Respectfully submitted this 23rd day of March 2010.
(lú-
BARTON L. KLINE
Attorney for Idaho Power Company
"
REPLY COMMENTS OF IDAHO POWER COMPANY -18
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 23rd day of March 2010 I served a true and
correct. copy of the foregoing REPLY COMMENTS OF IDAHO POWER COMPANY
upon the following named parties by the method indicated below, and addressed to the
following:
Commission Staff
Weldon B. Stutzman
Deputy Attorney General
Idaho Public Utilities Commission
472 West Washington
P.O. Box 83720
Boise, Idaho 83720-0074
Industrial Customers of Idaho Power
Peter J. Richardson
Gregory M. Adams
RICHARDSON & O'LEARY
515 North 27th Street
P.O. Box 7218
Boise, Idaho 83702
Dr. Don Reading
6070 Hil Road
Boise, Idaho 83703
Idaho Irrigation Pumpers
Association, Inc.
Eric L. Olsen
RACINE, OLSON, NYE, BUDGE
& BAILEY, CHARTERED
P.O. Box 1391
201 East Center
Pocatello, Idaho 83204-1391
Anthony Yankel
Yankel & Associates, Inc.
29814 Lake Road
Bay Vilage, Ohio 44140
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-l Email Weldon.stutzmancmpuc.idaho.gov
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greg~richardsonandoleary.com
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Barton L. Kline
REPLY COMMENTS OF IDAHO POWER COMPANY -19
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-E-10-01
IDAHO POWER COMPANY
ATTACHMENT NO.1
IS CONFIDENTIAL AND Will BE PROVIDED TO
THOSE WHO HAVE SIGNED THE PROTECTIVE
AGREEMENT
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-E-10-01
IDAHO POWER COMPANY
ATT ACHMENTNO. 2
Idaho Power/200
Witness: Gregory W. Said
BEFORE THE PUBLIC UTILITY COMMISSION
OF OREGON
UE214
IN THE MATTER OF )
IDAHO POWER COMPANY'S )
2010 ANNUAL POWER COST UPDATE )
)
)
)
IDAHO POWER COMPANY
REPLY TESTIMONY
OF
GREGORY W. SAID
March 17, 2010
REDACTED
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Idaho Power/200
Saidl1
Q.
A.
Please state your name and business address.
My name is Gregory W. Said and my business address is 1221 West Idaho
3 Street, Boise, Idaho.
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Q.
A.
Q.
A.
By whom are you employed and in what capacity
I am employed by Idaho Power Company as the Director of State Regulation.
Please describe your educational background.
In May of 1975, I received a Bachelor of Science Degree in Mathematics with
8 honors from Boise State University. In 1999, I attended the Public Utilty Executive Course
9 at the University of Idaho. Over the years I have attended numerous industry conferences
10 and training sessions.
11
12 A.
Q.Please describe your work experience with Idaho Power Company.
I became employed by Idaho Power Company ("Idaho Power" or "Company")
13 in 1980 as an analyst in the Resource Planning Department. In 1985, the Company applied
14 for a general revenue requirement increase. I was the Company witness addressing power
15 supply expenses.
16 In August of 1989, after nine years in the Resource Planning Department, I was
17 offered and I accepted a position in the Company's Rate Department. With the Company's
18 application for a temporary rate increase in 1992, my responsibilties as a witness were
19 expanded. . While I continued to be the Company witness concerning power supply
20 expenses, I also sponsored the Company's rate computations and proposed tariff schedules
21 in that case.
22 Because of my combined Resource Planning and Rate Department experience, I
23 was asked to design a Power Cost Adjustment C'PCA") which would impact customers' rates
24 based upon changes in the Company's net power supply expenses. I presented my
25 recommendations to the Idaho Public utilties Commission in 1992, at which time the
26 Commission established the PCA as an annual adjustment to. the Company's rates. I
REPLY TESTIMONY OF GREGORY W. SAID
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1 sponsored the Company's annual PCA adjustment in each of the years 1996 through 2003.
2 I continue to supervise PCA~related regulatory filngs.
3 After the conclusion of the Company's 2004 general rate case in Oregon, which was
4 based upon a 2003 test year, I worked with the Staff of the Public Utilty Commission of
5 Oregon ("OPUC" or "Commission"), the Citizens' Utilty Board ("CUB") of. Oregon, and the
6 Industrial Customers of Oregon to develop methods to annually adjust the power supply
7 expense related. portion of Oregon rates. These methods include the October update filng
8 of normalized power supply expenses and the March filing of forecasted power supply
9 expenses, which are used in combination to determine the Annual Power Cost Update
10 ("APCU") rate that will go into effct the following June, and also include the February true-
11 up or power cost adjustment mechanism ("PCAM"), Which determines an amount to be
12 added or SUbtracted from the queue of power supply deferrals.
13 In 1996, I was promoted to Director of Revenue Requirement and in 2002 i was
14 promoted to Manager of Revenue Requirement. I have managed the preparation of
15 revenue requirement information for regulatory proceedings in both Idaho and Oregon since
16 1996.
17 In 2008, I was promoted to Director of State Regulation. In that capacity, i was
18 asked by Mr. Ric Gale, Vice President of Regulatory Affairs, to iead. manage, and
19 coordinate the preparation and development of regulatory filngs in Oregon and Idaho. I
20 supervised and coordinated the preparation of testimony in this case and I am the Company
21 witness regarding regulatory policy.
22
23
24
INTRODUCTION
Q.
A.
What is the purpose of your testimony in this case?
My testimony addresses policy issues raised by Staff witness Michael
25 Dougherty with respect to his coal cost adjustment.1 Mr. Doughert proposes a signifcant
26
1 See' Staff/200.
REPLY TESTIMONY OF GREGORY W. SAID
Idaho Power/200
Said/3
1 adjustment of over $15 milion system-wide related to the reasonable and prudel'tly incurred
2 coal costs for the Company's Jim Bridger Plant (the "Bridger Plant' or "Plant"). Mr.
3 Dougherty bases his adjustment on his understanding of the Commission's lower of cost or
4 market ("LCM") rule set forth in OAR 860-027-0048. This rule applies to transactions
5 between a regulated iitility and its affilate. Specifically, Mr. Doughert takeS the position
6 that the surface-mined coal purchased by the. Plant from its afliated mine-the Bridger Coal
7 Company ("BCC')-,is more expensive than market. Therefore Mr. OQugherty recommends
8 that the cost of the surface coal from BCC be replaced for ratemaking purposes with the
9 cost of coal purchased by the Plant from the non..afilated Black Butte Mine ("Black Butte").
10 After a thorough analysis of Mr. Dougherty's reasoning i conciiide that the Commission
11 should reject Mr. Dougherty's proposal for the following reasons:
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(1) Replacement coal for the Bridger Plant is not available and thus there is
not a viable market as defined in the LCMrule;
(2) Staff misapplied the Commission's LCM rule, and a proper application wil
demonstrate that the use of BCC coal results in lower costs for the
Company's customers than "market' alternatives;
(3) Stafff¡ailed to identify any unreasonable or imprudent costs incurred by
Idaho Power or its affliate;
(4) Adoption of Mr. Doughert's adjustment wil create serious policy
concerns with respect to the Company's use of captive mines and long-term
coal contracts that wil ultimately hurt customers; and
(5) Because of the relationship betwen the Bridger Plant and BCC, Mr.
Doughert's interpretation of the Commission's LCM rule should not apply to
this case.
SUMMARY OF STAFF RECOMMENDATION.'
Q.Please provide a detailed explanation of Mr. Doughert's adjustment.
REPLY TESTIMONY OF GREGORY W. SAID
Idaho Power/200
Said/4
1 A.Mr. Dougherty's testimony includes four different analyses. He recommends
2 the Commission adopt either his Primary or First Alternative Analysis. He also provides two
3 additional analyses that he rejects. In his Primary, First Alternative, and Second Alternative
4 Analyses Mr. Doughert replaces the costs of surface-mined coai2 from BCC because he
5 claims the cost of the surface-mined coal exceeds the "market rate." In his Primary and First
6 Alternative Analyses,. Mr. Dougherty . identifies the market rate as the cost the Bridger Plant
7 pays for coal from the Black Butte Mine. The only difference between these two analyses is
8 that in his Primary Analysis, Mr. Dougherty calculates the market rate by including the
9 deferred costs paid to Black Bute under now expired contracts while in his First Alternative
10 Analysis he uses only Black Butte's contract and transportation costs and not deferred
11 costs: In his Second Alternative Analysis, Mr. Dougherty calcuiates the market rate as the
12 cost of coal from BCC's underground operations only. And finally, Mr. Dougherty's Third
13 Alternative Analysis replaces both the surface and underground BCC coal costs with the
14 cost of Black Bute coal. In each instance the basis for the adjustment is Mr. Dougherty's
15 conclusion that the costs of coal from the Company's affliated mine exceeds the market rate
16 for coal the Company could otherwise purchase.
17
18
Q.
A.
What is the affliate trnsaction at issue here?
Idaho Power has a wholly-owned subsidiary called Idaho Energy Resources
19 Company ("IERCO"). IERCO owns a one-third interest in BCC; the other two-thirds are
20 owned by a PacifiCorp subsidiary. BCCoperates a coal mine in the Green River Basin
21 ("GRB") in southern Wyoming. BCC's mine supplies .its entire output to the Bridger Plant,
22 which is owned jointly by Idaho Power and PacifiCorpand is located.âdjacent to the mine.
23 Here, the transaction at issue is the sale of coal from BCC (a subsídia.. through IERCO) to
24 Idaho Power.
25
26 2 As is described in detail in Tom Harvey's testimony, the BCC mine has both a surfce and an
underground operation. .
REPLY TESTIMONY OF GREGORY W. SAID
Idaho Power/200
Saidl5
1 LOWER OF COST OR MARKET RULE
2 Q.. Please describe the LCM rule.
3 A. The Commission's LCM rule states:
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8
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10
The energy utility shall use the following cost allocation
methods when transferring assets or supplies or
providing or receiving services involving its affliates:
When services or supplies (except for generation) are
sold to an energy utilty by an affiliate, sales. shall berecorded in the' energy utilty's accounts at the
approved rate if an applicable rate is on file with the
Commission or with FERC. If services or supplies
(except for generation) are not sold pursuant to an
approved rate, sales shall be recorded in the energy
utility's accounts at the affiliate's cost or the markèt
rate, whichever is lower.3
11 This rule appears in Division 2~ of the Commi.ssion's rules, the division that deals with utilty
12 budgets, financing, and accounting.4
13
14
Q.
A.
What is the purpose behind the rule?
According to the Commission in Order No. 03-691, the underlying purpose
15 behind the rule is to prevent a regulated utilty from subsidizing an affilate.6 ßecause
16 transactions between utilities and their affilates are not necessarily arms~length
17 transactions, there is a risk that utilties might pay more for goods or services provided by an
18 affilate than the utilty would otherwise pay if it purchased the goods or services on the open
19 market, and funnel the excess proft through the affliate to the utilty's shareholders, who are
20 also by definition shareholders of the affliate.
21 Q.You have stated that Mr. Doughert has misapplied the LCM rule. How
22 has Mr. Doughert misapplied the LCM rule?
23
24 3 OAR 860-027-0048(4)(e). (Emphasis added).
25 4 See Re PacifCorp Request for General Rate Increase, Docket UE 170, Order No. 05-1050 at 18
(Sept. 28, 2005) ("this rule is an acCounting ruie").
26 5 See Re Affliated Transactions for Energy Utilities, Docket AR 459, Order No. 03-691 at 1 (Dec. 1,
2003).
REPLY TESTIMONY OF GREGORY W. SAID
Idaho Power/200
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1 A.As described above, the LCM rule requires that afliate transactions be
2 recorded in the utility's books at the lower of cost or market rate. The lower of cost or
3 market rule defines "market rateÐ as "the lowest price that is available from nonaffilated
4 suppliers for comparable servces or supplies."a Mr. Dougherty'S analysis is flawed because
5 he has incorrectly determined the market rate with reference to coal that is not available to
6 fuel the Plant.
7
8
Q.
A.
Please explain.
In order to perform a proper LCM analysis in this case, the market must be
9 defined by reference to sources of coal that are available to the Company for purchase in
10 lieu of the BCC surface coaL. For alternative coal to be "available" as required by the rule,
11 the Company must have the abilty to actually purchase that coal in lieu of purchasing the
12.. coal from BCC. AlthoughtheLCM rule does not define the term "available," Merriam-
13 Webster's dictionary defines it as "present or ready for immediate use c:available
14 resources::Ðor "accessible, obtainable c:articles available in any drugstore::."7 These
15 definitions are both cómmon sense definitions and they conform to the underlying purpose
16 ofthe LCM rule. The purpose ofthe LCM rule is to prevent cross-subsidization betwen a
17 utilty and its affliate. For the rule to be effective in preventing cross-subsidization, the
18 Company must be free to choose to actually purchase coal from another supplier. It is not
19 enough that another source of. coal exists if the Company cannot ..actually supplant its
20 allegedly òver-m a rket coal with that other coaL.
21
22
Q.
A.
How has Mr. Doughert defined the market price?
Implicit in Mr. Doughert's analysis is the recognition that there is no defined
23 market from which the Bridger Plant can buy coaL. . In the absence of a defined market, Mr.
24 Doughert assumes a hypothetical market at which the price of delivered coal is equal to the
25
26 6 OAR 860.027-0048(1)(i) (emphasis added).7 Merriam-Webster Online, Merriam-Webster Online Dictionary. 2010, -ehttp://w.merriam-
webster.com/dictionary/available:: (accessed March 5,2010).
REPLY TESTIMONY OF GREGORY W. SAID
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1 price included in one of the Plant's existing contracts.
2
3
Q.
A.
Please give an example of a defined market
For electric energy there are energy trading hubs-such as mid-C-that
4 define a market that can be used tò compare prices. However, coal is not traded at hubs
5 the way that energy is traded and there is no such market for coal for the Bridger Plant.
6 Q.You said that Mr. Doughert assumes a market price based on one of
8
7 the Bridger's Plant's contracts. Please explain.
Mr. Dougherty's Primary and First and Third Alternative analysis define.A.
9 market .price by reference to the coal purchased by the Bridger Plant from the Black Bute
10 mine. His Second Alternative Analysis defines the market price by reference to the cots
11 associated with BCC's underground coal. As explained by Mr. Harvey, the Black Butte mine
12 does not have suffcient additional coal available to replace BCC coal. Forthis reason, the
13 cost of the Black Butte coal should not be relied upon to define the market. Similarly, BCC's
14 underground mine is opeating at capacity and cannot replace BCC surface coaL.
15 Q.In data responses Mr. Doughert states that Black Butt coal is
16 available to the Plant because Bridger already obtains coal from Blacle Butte. What is
17 your response?
18 A.Mr. Dougherty's analysis flies in the face of the definition of "available" The
19 mere existence of Black Butte coal to satisfy existing contractual obligations does not
20 suggest that additional amounts are "available" for immediate use or obtainable by the
21 Company. In other words, his analysis reads the word "available" right out of the definition
22 of "market rate."
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24
Q.
A.
How should market rate be determined in this case?
A market rate in this case would need to consider sources of coal that are
25 actually available for purchase by the Bridger Plant to replace the coal it receives from the
26 BeC surface mine. Once that coal is identified, the market rate must include the total cost of
REPLY TESTIMONY OF GREGORY W. SAID
Idaho Power/200
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1 the coal including any transportation necessary to move the coal from its source to the
2 Plant.
3 Q.Has the Company evaluated the availabilty of coal that could bé
4 considered as a market?
5 A.Yes. As explained in Mr. Harvey's testimony, coal mines rely on contracts to
6 ensure ongoing viabilty. Therefore, market or spot coal availabilty is limited. Generally, to
7 replace the quantities of coal as suggested by Mr. Doughert, it would require that existing
8 mines expand their operations to additional pits or seams. Expanded operations would
9 require additional capital investments by those mines at costs different than the embedded .
10 costs of existing operations as reflected in current contract prices.
11 Q.Has the Company made any inquiries to quantify the costs of other
12 potential coal sources?
13 A.Yes. As described in Mr. Harvey's testimony, as the operator of the Plant,
14 PacifiCorp representatives contacted the Black Butte mine and learned that at most the
15 mine, as of February, 2010, had an additionai. tons of coal available to sell to the
16 Plant. This amount is not sufficient to replace the reqUired. and I millon tons of BCC
17 surface coal.
18 Q. Mr. Doughert suggests that the BCC surfCé costs that could be
19 replaced cost approximately . per ton. Has hé properly identified the costs . that
20 could be displaced?
21 A.No. Mr. Dougherty included non-displaceable costs associated with total
22 mining operations at BCe as costs that could be saved via shutdown ota portion of BCC's
23 operations.
24 Q.How does the cost savings associated with discontinuing BCC's
25 suñace operations compare to the cost provided by Black Butte for additional
26 tonnage?
REPLY TESTIMONY OF GREGORY W. SAID
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1 A. As described in Mr. Harvey's testimony, the decremental cost of BCC's
2 sunace coal is approximateiy. per ton. The cost of replacing that sunace coal with
3 Black Butte coal (assuming it has the capacit to actually do so, which it does not) is
4 approximately $. per ton, including transportation from the mine to the. Plant. Thus,
5 even if all other issues-such as the actual availabilty of Black Butte coal-are ignored,
6 BCC's displaced sunace coal costs are lower than Mr. Dougherty's "market rate" coal from
7 Black Butte. In other words, if the Company acted on Mr. Doughert's adjustment and
8 ceased its sunace. operation and replacd that coal with coal from Black Butte (again,
9 assuming this was actually possible) it would actually increase the cost to operate the
10 Bridger Plant. Customers would be harmed financially by Mr. Dougherty's adjustment.
11
12
MR. DOUGHERTY HAS NOT IDENTIFIED ANY UREASONABLE COSTS
Q.Do you agree with Mr. Doughert's suggestion thaJ when the
13 Commission approved the affliated relationship between Idaho Power and IERCO in
14 Order No. 91-667 it reserved the right to review all financial aspects of the
15 arrangement In later ratemakingproceedings?
16 A.Yes, ..1 do. As Mr. Dougherty's own testimony states, however, the
17 Commission reserved the right to review for reasonableness the financial aspects. of the
18 relationship.a This does not mean that the Commission ordered the application of the LCM
19 rule to all future transactions. My understanding is thåtthis "reasonableness" standard has
20 been used by the Commission to analyze other afliate transactions as well. .For example, I
21 have been advised that in Order No. 02.820, the Commission described its analysis of costs
22 under a generation facilties lease between PacifiCorp and an affliate and noted:
23
24
25
26 a Re Idaho Power Company, Docket UJ 107, Order No. 91-567 at 4 (Apr. 29, 1991) (hereinafter
"Order No. 91-567"); Staff/200, Dougherty/5, II. 8-10.
This leaves the issue of the standard to be applied when
reviewing the cost of the lease. The question is whether the
costs of the lease are reasonable, i.e., is the cost of the lease
a necessary and ordinary recurring expense. If it is, the costs'
REPLY TESTIMONY OF GREGORY W. SAID
Idaho Power/200
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1
2
are included in rates. If not, the costs are not included in
rates.9
3 In a later rate case where the Commission analyzed the costs incurred under the same
4 affliate lease, i understand that the Commission found the costs were prudently incurred.10
5 The Commission's analysis focused on prudence-using its traditional prudence analysis-
6 and not the lower of costor market.11
7 This reasonableness analysis is especially appropriate here because, as explained
8 later in my testimony, IERCO is not treated as an affilate for ratemaking so its operations'
9 should be subject to the same standard as all of Idaho Power's operations.
10 Q.Did Mr. Doughert identify any specific costs that he found to be
11 unresonable?
12 A.No. At the conclusion of his testimony he suggests that he identified certain
13 costs that he would have recommended for adjustment in a general rate case review but did
14 not do so here because his LCM adjustment was larger. This "line item cost" analysis is
15 problematic for two reasons. First, Mr. Dougherty failed to identify. these costs in his
16 testimony and provided absolutely no support for them. Moreover, in a data request Idaho
17 Power specifically asked Staf whether they claimed that anyBCC costs were unreasonable.
18 In response, Mr. Dougherty merely reiterated his testimony that the BCC costs were above
19 Black Butte costs and therefore above-market and did not claim that the costs were
20 unreasonable.12 On that basis alone the Commission should reject any adjustment based
21 on his "line item cost" analysis. Second, Mr. Dougherty's analysis here poses a serious
22
23 9
Id. at 7.
24 10 See Order No. 05-1050 at 22-23.25 . .11 Id. When reviewing the lease, the Commission looked at whether PacifiCorp's actions were
26 reasonable at the time it entered into the lease based on the information it had available at the time.
12 Staff Response to Idaho Power Data Request NO.1 (a) attached as Exhibit 201.
REPLY TESTIMONY OF GREGORY W. SAID
Idaho Power/200
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1 policy concem because it suggests that when analyzing BCC costs the Commission has the
2 option of treating IERCO as an affliate or a non-affliate depending on which analysis yields
3 a larger adjustment. Sound public policy would require that the Commission apply either the
4 LCM or the reasonableness standard to BCC's costs, but not neither or both.
5
6
POLICY CONCERNS RAISED BY STAFF'S PROPOSAL
Q.Does Mr. Doughert's proposed adjustment pose any policy concerns
7 for the Company related to its coal procurement strategy?
8 A.Yes. Mr. Dougherty's. proposal to annually examine long-term BCC coal
9 contracts is problematic because it fails to acknowledge the long-term benefits of captive
10 mines, it discourages future investment in captive mines, and it ultimately harms customers.
11 Idaho Power pursues a diversified coal supply strategy. This strategy relies on a
12 combination of fixed price contracts, indexed contracts, and BCC coal to meet the coal
13 supply needs .of all of its coal-fired plants. This strategy results in a long-term, stable, and
14 low-cost supply of coaL. While these coal contracts may be long-term, Idaho Power
15 conducts regular reviews of its fueling strategies in its effort to reduce fuel costs and
16 optimize customer benefits.
17 There is no viable spot market for purchasing coal to fuel the Bridger Plant. For this
18 reason, long-term contracts are essential for the Company to continue to provide. a cost-
19 effective and reliable source of fuel for the Plant.
20 If the Commission adopts Mr. Dougherty's adjustment and methodology and the
21 Company is unable to recover reasonable and prudently incurred costs, it will change the
22 Company's coal strategy and mining. operations. It would be unreasonable for the Company
23 to continue operations as it has done since the inception of the BCC relationship if there is a
24 significant and real risk that reasonable costs wil be consistently disallowed. In essence,
25 the Company's coal operations will shift from a long-term strategy to short-term cost
26 recovery, ultimately at customers' expense.
REPLY TESTIMONY UF GREGORY W. SAID
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1 Q.How does Mr. Doughert's proposal fail to acknowledge the long;.term
2 benefits of captive mines?
3 A.The use of captive mines has provided long-term benefits to Idaho Power's
4 customers. These benefits include the provision of a reliable and steady source of coal forAI
54fe Bndger Plant, operational flexibilty, and cost-efective coal blending to maximize the
6 efficiency of the Bridger Plant. The BCC mine wil likely continue to provide benefits into the
7 future. In Staff's March, 2009, audit of PacifiCorp Staff recognized the advantages of
8 êaptive mines, noting that, "As a result of potential rising costs, having captive mines may
9 result in an increasing benefit to PacifiCorp's customers."13
10 Mr. Dougherty's proposed adjustment misconstrues the value of the BCC contract by
11 minimizing the long-term benefits received by customers over the life of the agreement.
12 This annual review wil create significant problems in terms of long-term planning and is
13 unlikely to benefit customers.
14 A least-cost fueling strategy for Bridger cannot be based solely on an annual
15 determination of the BCC mine costs relative to other available supply options. The decision
16 to invest in the BCC mining operation was based on long-term analysiséxtended overthe
17 mine's life. Because mine production costs will typically fluctuate more than contraCt prices,
18 it is unreasonable to limit recovery of production costs in a particular year or test period
19 when the cåptive operations provide significant savings and benefits to customers over the
20 life of plant's operation. This is especially true here because BCC coal is clearly superior to
21 other supply options over the extended period.
22 In this.case, the least-cost coal supply for the Bridger Plant is a combination Of the
23 current Black Butte agreement and the combined BCC surface and underground operations.
24 These provide the optimum coal supply for Bridger. If the Company's coal strategy focused
25
26
13 Docket UE 207, Exhibit PPU203, Lasich/5, attached as Exhibit 202.
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1 exçlusively on annual determinations of BCC costs, as Mr. Doughert's adjustment requires,
2 then coal costs wil actually increase, as is discussed in detail in Mr, Harvey's testimony.
3 Q.How does Mr. Doughert's adjustment discourage investment in captive
4 mines?
5 A.If captive mines are subject to annual adjustments based on theappliaation
6 of the LCM rule where Mr. Doughert or another analyst creates a surrogate market price for
7 an unestablished coal market, as proposed here, it wil provide a strong disincentive for the
8 Company to enter into long-term coal ccmtracts with affliates even though these. contracts
9 have traditionally provided substantial benefits to customers. When the Commission
10 reviews long-term, non-affliated contracts for inclusion In rates, it uses a prudence analysis
11 that examines whether the Company acted reasonably when it entered into the agreement.14
12 The Commission does not use hindsight to second guess the utilty's conduct. If the
13 Commission analyzed these long-term contracts annually, it would create a strol'g
14 disincentive to enter into a long-tenn contract because the risk would be too. great that future
15 costs would be disallowed based on unknowable future events. This. prudence review
16 represents a well reasoned conclusion that it is frequently in customers best interests .for
17 utilties to enter into long-term contracts and therefore the Commission wil not secon(l guess
18 that decision if it was reasonable when made.
19 Although the Commission has applied this same prudence analysis to affilated
20 transaetiQns in the past15, that is not what Mr. Doughert is doing here. In proposing an
21 annual LCM adjustment based on annual, rather than long-term cost fluctuations, Mr.
22 Dougherty's is applying a much harsher standard to affliated interests than would otherwise
23 apply if the contract were between a utility and a non-affilate. This despite the.fact there is
24 no identified cross-subsidization here. This makes the decision to continue a relationship
25
26 14 Order No. 05-1050 at 23.
15 See Order No. 05-1050 at 23.
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1 with a captive mine or begin a new relationship with a captive mine much more difficult. If
2 utilties are discouraged from establishing captive mines, such as BCC, because they
3 receive unfavorable treatment in years when the mine's costs exceed the market (although
4 as Mr. Harvey testifies that is not even the case here) then customers lose out on the
5 numerous benefits these captive mines provide. In the future customers wil lose this benefit
6 if the Commission adopts Mr. Dougherty's adjustment because thèrisk is too great that any
7 long-term benefits are sacrificed by annual adjustments based on the application of the LCM
8 rule.
9 Q.Does Mr. Doughert's proposal also jeopardize thè Company's diverse
10 coal supply?
11 A.Yes. As noted above, the Company's coal procurement strategy entails
12 purchasing coal from both BCC and non-affliate mines. This combination of coal sources
13 serves the important goal of mitigating supply risk by ensuring that the Company is
14 purchasing coal from several sources at anyone time. The Bridger Plant has generally
15 relied on two mines for fuel, the BCC mine and the Black Butte Mine. This assures the plant
16. can acquire the continuous coal supply that it requires. For instance, .if a major issue arose
17 in BCC's underground operations that limited coal production, the surface operation could
18 be ramped up to help fill the production void. Similarly, if Black Butte sustained a signifcant
19 production limitation then the BCC integrated surface and underground operations could
20 ramped up to provide for additional coaL. This operational flexibilty is a kèY advantage of
21 captive mines and this diversified approach provides the level of reliable and continuous
22 coal supply that is required by a regulated utilty in order to meet its obligation to reliably
23 serve its customers' loads. If the Company implements Mr. Dougherty's proposal-ceasing
24 surface operations and increasing purchases from Black Butte or ceasing BCC operations
25
26
REPLY TESTIMONY OF GREGORY W. SAID
Idaho Power1200
Saicl15
1 altogether and purchasing exclusively from Black Butte 16-the Company's well-considered
2 coal strategy wil be compromised. This coal strategy has served customers well in the past
3 and wil continue to do so in the future.
4
5
THE LCM RULE SHOULD NOT APPLY IN THIS CASE
Q.You stated that the LCM rule should not apply in this case to the coal
6 purchases by the Plant from BCC. Why is that?
7 A.These purchases do not raise the risk of the harm the LCM rule was intended
8 to remedy and so there is no reason to apply it in this case.
9
10
Q.
A.
What is the purpose behind the LCM rule?
As described above, .the purpose of the rule is to prevent cross-subsidization
11 between a utilty and its affliate.
12 Q.In this case is there a risk of cross-subsidization between Idaho Power
13 and BCC?
14 A.No. The Commission has long recognized that transactions between Idaho
15 Power and BCC pose no risk of cross subsidization because of the unique manner in which
16 the Commission addresses IERCO's (the affliate that owns BCC) operations. Unlike other
17 utilty afliates, for ratemaking purposes IERCQ's operations are merged with those of Idaho
18 Power. As the Commission noted in Order No. 91-567, wher~ the Commission approved
19 the coal sales agreement between BCC and Idaho Power, IERCO is "disregarded as a
20 separate entity for ratemaking purposes."17 The Commission added:
21
22
23
24
25 16 This hypothetical is based on .Mr. Dougherty's unsupported assumption that Black Butte has theavailable capacity to actually replace BCC caal. As Mr. Harvey's testimony makes clear, however,
26 this assumption is wrong.
IERCO's results of operations have been merged,
consolidated, and included with Idaho's for the purposes of
filing of iiieorne tax returis and for rate making purposes.
Therefore, there is no danger of cross-subsidization between
Idaho aiid IERCO, nor is there any danger of Idaho paying in
17 Order No. 91-567 at 2.
REPLY TESTIMONY OF GREGORY W. SAID
Idaho Power/200
Said/16
1 excess of market value to IERCO or its assignees for the coal
purchased. Idaho is paying for its coal the same as if IERCO
2 were not even involved in this transaction. 18
3 Therefore, the LCM rule should not apply in this case because: (1) for ratemaking
4 purposes, I~RCO (and BCC) is not treated as an affliate at all; and (2) there is no cross-
5 subsidization in this case.
6
7
Q.
A.
Has Staff alleged that Idaho Power is subsidizing IERCO in this case?
No. In fact Mr. Dougherty specificaiiy stateddthat"there is no cross-
8 subsidization between IERCO and Idaho Power."19 By Staff's own admission the
9 fundamental purpose behind the LCM rule is not at issue in this case.
10 Q.Mr. Dougherty suggests that the LCM rule applies to all affliated
11 interest transactions and it should apply here also. Do you agree?
12 A.No. i have been advised that the Commission has waived the application of
13 this rule on several occasions. In Order No.06..16, the Commission waived the rule when
14 Idaho Power sought Commission approval to allow it to provide short..term loans to
15 IERCO.20 Staff recommended the waiver, even though the interest rate on thé loans was
16 not a market rate, noting:
17 Since IERCO's net income is included in IPC's net operating
income, Staff believes the Commission should allow a cost-18 based approach to the loans and allow IPC to set interest
rates at IPC's short-term borrowing costs and not the lower of19 cost or market,1.
20 This. precedent is important because the basis for Staffs recommendation, and the
21 Commission's ultimate adoption of that recommendation, applies here with equal force-
22
23 18 Order No. 91-567 at 2 (emphasis added).19 12 .
24 Staft 00, Dougherty/5, i. 30 - 6, I. 1.
25 20 Re Idaho Power Company Application for Authority to Provide Short-Term LoanS to Idaho EnergyResources Co., Docet UI 244, Order No. 06-016 at 3 (Jan. 17,2006) (hereinafter "Order No. 06-
26 016").
21 Order No. 06-016 at App. A at 4.
REPLY TESTIMONY OF GREGORY W. SAID
Idaho Power/200
Saidl17
1 IERCO is not an affliate for ratemaking purposes so the lCM rule should not apply to
2 transactions between Idaho Power and IERCO.
3 In Order No. 91-513, the Commission approved the mining contract between
4 PacifiCorp and Energy West Mining Company ("EWMC") on a cost-based approach rather
5 than the lower of cost or market. 22 The Commission found that EWMC was established
6 such that it could not earn a profit(like B.CC) and found that it was unlikely a third-party
7 could provide the services at a lower cost. The Commission found:
8
9
10
11
12
13
This cost-based approach and the limitation of EWMC's
activities to those arising under the contract minimize the
likelihood of cross-subsidization. Due to recent reductions in
operating costs at EWMC's Utah mines Pacifc is purchasing
coal at or below market prices. Through the rate-making
process, the Commission can ensure that Oregon utilty
customers do not pay unreasonable expenses. The
Commission concludes that the agreement is fair and
reasonable and not contrary tothe publicinterest.23
Here, BCC also performs only activities arising under a contract and that contract is
14 very similar to the one the Commission addressed in Order No. 91-513.
15 Q.Has .the Commission ever waived the LCM rule with respect to BCe
16 coal?
17 A.Yes. As Staf noted. in their March 11, 2009, "Staf Audit Report of
18 PacifiCorp":
19
20
21
22
23
24
Commission orders concerning affliated interest contracts with
Bridger (Order No. 01-472, UI 189) and Energy West (Deer
Creek, Order No. 91-105, Ui 105) allow for a cost-based
pricing of coal from these affliates. This is an approved
departure from OAR 860-027-0048, Allocation of Costs by an
Energy Utility, which norally requires the lower of cost or
market standard when a utility is purchasing goods or servicesfrom an affliate.24 '
25 22 Re PacifiCorp, Docket U1105, Order No. 91-513 at 3 (Apr. 12, 1991).
26 23 Order No. 91-513 at 2.
24 Docket UE 207, Exhibit PPU203, Lasich/5 (emphasis added), attached as Exhibit 202.
REPLY TESTIMONY OF GREGORY W. SAID
Idaho Power/200
Said/18
1 Based on these past waivers and the unchanged circumstances surrounding coal
2 sourcing for the Bridger Plant, the Commission should again waive the rule as it has in the
3 past.
4 Q.If the LCM rule does not apply to the coal purchases in this case, how
5 should the Commission anaiyze BCC's costs?
6 A.As discussed above, BCC's operations-because thêy are merged With those
7 of Idaho power for ratemaking-should be analyzed based on the same standards as all
8 other Idaho Power costs and contracts. If the costs are reasonable and the Company was
9 prudent in entering into the contract with BCC then the Company should be allowed to
10 recover those costs in rates.
11 Q.Doesn't the Commission's Order No. 91-567 also require the Company
12 to notify the Commission of any material changes in costs that occur?
13 A.Yes it does. Although the Company has not filed a separate and distinct case
14 solely for the approvai of the contract amendments/restatements, the cots resulting from
15 those amendments/restatements have been brought before' both the Idaho and Oregon
16 Commissions on numerous occasions for review, during both general rate cases and annual
17 power cost cases, and on each occasion the respective Commissions have reviewed and
18 approved the same.
19 Q.Mr. Doughert suggests that an accounting principle, EITF 04-6, máy be
20 responsible for the annual fluctuations in BCCcoal costs. Do you agree?
21 A.Yes, to some extent the accounting principle does account for the annual
22 fluctuations. However, in this case the impact of this principle is fairly small.
23 Q. Are there difficulties with applying the LCM test when coal costs are
24 accounted for under the EITF 04-6 accounting standard?
25 A.Yes. While the annual fluctuation in cost resulting from the EITF standard is
26 relatively small, the application of the LCM rule does not align well with this method of
REPLY TESTIMONY OF GREGORY W. SAID
Idaho Power/200
Said/19
1 accounting. The EITF accounting standard requires BCC to book the costs of overburden
2 removal in the month that those costs are incurred. Because the overburden removal cost
3 can vary from year to year, independent of actual coal production, the unit cost of coal can
4 be impacted. Theoretically, in years when the booked costs of overburden removal do not
5 align with the corresponding coal removal and production, the unit cost of coal could be
6 artificially inflated or deflated for that period. Therefore, under this approach the Company
7 would recover its prudently incurred cost~ only in years when the unit price is artificially
8 deflated due to the EITF standard. This puts the Company in ~ "heads you win, taUs I lose"
9 situation where it is not allowed an opportunity to recover prudently inGurred costs that are
10 necessary to continuously and reliably serve its customers.
11 Q.Mr. Doughert suggests that regardless of the Impact of the accounting
12 principle, it applies equally to affliated and non-affliated mine and therefore it Is
13 immaterial. Do you agree?
14 A.No. This comparisón is invalid because non-affliated mines, such as Black
15 Butte, do not. sell their coal to the Plant based solely upon their operating cost. EITF 04-6
16 deals with how a mine accounts for its costs, not how that mine contracts to sell its coal.
17 Because non-affiliated mines do not sell their coal to the Plant baseçl upon their cost,
1.8 application of this principle can have a disproportionate impact on affiliated transactions and
19 provide further disincentive to a utilty choosing to enter into this type of relationship.
20
21
22
23 .
24
25
26
Q.
A.
Does this conclude your testimony?
Yes.
REPLY TESTIMONY OF GREGORY W. SAID
Idaho Power/201
Witness: Greg Said
BEFORE THE PUBLIC UTILITY COMMISSION
OF OREGON
IDAHO POWER COMPANY
Exhibit Accompanying Testimony of Greg Said
Staf Response to Idaho Power Data Request 1 (a)
March 17, 2010
Idaho Power1201
8ad/1
..:.
March 8.,2010
TO:Lisa Rackner
Idaho Power Company
Michael Doughert, Proram Manager
Corporate Analysis and Water RefJulation
Ed Durrenberger, Senior Utilty Analyst
Electrc Rates and Planning
. "FROM:
OREGON PUBLIC UTILITY COMMISSION
UE214
Idaho Power's First Set of Data Requests to OPUC
. . . Due March 8, 2010"
Data Request Nos. 1-7
Request.
1. See Staf1200, Doughert/5, lines 8-10.'
a. Does Staff assert that BCC coal costs are. unreasonable? If so, please.
provide all justifications for this position.
b. Does. Staff assert that the BCC coal costs reflected in the Company's filing
do not represent the actual cost of mining the coal and delivering it to the
plant?
Response:
a. Throughout testimony, Staf asserts:
. BCC is an affliate of Idaho Power;
· OAR 860-027-0048, AllocatIon of Costs by an Energ Utility, applies .
to the.transfer pricing beteen BCC and Idaho Power;
· Bcè weighted cost per ton Is higher than the third part delivered
cost per ton; and
· As a result, BCC coal costs in rates must be the lower of cost or
market.
b. No. Staff asserts that the afliate's coal costs are higher than the market
cost
BEFORE THE PUBLIC UTILITY COMMISSION
OF OREGON
IDAHO POWER COMPANY
Exhibit Accompanying Testimony of Greg Said
Docket UE 207, Exhibit PPLl203, Lasich/5
March 17, 2010
Idaho Power/202
Witness: Greg Said
DPUC Staff Audit Report
PacifCorp
March 11, 2009
Staff Audit Report of
PacifiCorp
Audit Number: 2008-002
March 11, 2009
Audit team:Dustin Ball (Lead Auditor)
Michael Doughert
Marion Anderson
Prepared by: Dustin Ball
1
Idaho Power/202
Said/1
Audit 2008-002
October 2008 - March 2009
ExhIbit PPU203
Lasich/1
Idaho Power/202
Said/2
OPUC Staff Audit Report
PacifiCorp
March 11, 2009
Audit 2008-002
October 2008 - March 2009
Exhibit PPU203
laslchl2
Corporate ServicesCost Allocation Manual
Pursuant to OAR 860-027-0048, PacifCorp provided Staff a Cost Allocation
Manual (CAM) as an attchment to its 2007 Affliated Interest Report. Staff
reviewed the content and format of the CAM and believes that PacifCorp has
adequately addressed its cost allocation methods.
Coal Purchases from Affliate
PaciCorp purchases coal from certain affliates, Bridger Coal Company, Energy
West Mining Company, and Trapper Mining Company. The Bridger Mines
provides coal to the Jim Bridger plant, of which PacifCorp pwns66. 7 p.ercent.
The Jim Bridger plant is locted in Wyoming. According to the Company, the
transition of Jim Bridger Coal Company from surfce. mining operation to a
comtiined underground/surface mining operation has resulted in an increase in
costs and a shif in cost drivers. As a result in the change in operation, coal
costs from Jin Bridger have increased.
Energy West Mining Compt:ny's Deer Creek Coal Company (lInderground
mining method) provides coal for the Company's Carbon, Hunter, and Huntington
Plants, which are located in Utah. According to PacifiCorp, coal cosa; have
increased from 2006 to 2008 due to a number of factors including labor and
benefit costs, materials and supplies, mine maintenance, and profesional
services.
PaCifCorp. is also a minority owner of Trapper Mining Inc. .(21.4 percent).
Trapper Mining Inc. provides coal to PacifiCorp's Craig Plant, which is located in
Colorado. According to PaciCorp's 10-K, the Craig Plant is supplied from coal
produced from a surface mining operation.
The following tables shows Bridger Coal Company (Underground/Surface), Deer
Créek Coal Company (Uiiderground), and Trapper Mining Coal Company
(Surface) coal costs for 20Ö6 through 2008. -The table also for illustrative
purposes shows coal. costs for PacifiCorp coal plants not supplied by affliates.
Unless specified, the coal costs do not include transporttion costs.
Table 25 - Coal Costs, 2006 - 2008
Change
2006.2008
41.41%
4.81%
47
Idaho Power/202
Said/3
OPUC Staff Audit Report
PacifiCorp
March 11, 2009
Audit 2008-002
October 2008 - March 2009.
Exhibit PPLJ03
Laslchf3
Trapper Coal Base - Colorado
(Craio - Surface)$22.68 $24.43 $25.57 12.74%
Trapper Coal Spot - Colorado
(Craio - Surfacè)$22.50 $20.60 $29.88 32.8%
Coal Purchased from Third Parties
Coal supplied to Cholla - Arizona
(Surface)$24.05 $24.24 $27.52 14.43%
Dave Johnston - Wyoming
(Surface)$5.34 $5.83 $7.14 33.71%
Dave Johnston - Wyoming with
Transportation $9.99 $10.52 $12.09 21.02%
Wvodak - Wvomlna (Surface)$10.59.$10.81 $11.49 ...8.50%
Nallghton - VVvomina (Surface)$25.04 $27.46 $26.86 7.27%
Colstrip.Montana. (Surface)$14.46 $15.~0 $17.27 19.43%
Havden - Colorado (Combined)$31.38 $33.43 $34.03 17.27%
Hayden - Colorado with
Transporttion NA NA $36.80 NA
The following table highlights market prices.
Table 26 - DOEIEIA 2007 Info Averaae sale price ($ per Short Ton)
State.2006 2006 2007 2007
Underaround Surface Underaround Surface
Colorado $24.91
$24.10 $24.70 (Totai)Not listed
New $29,15 $29.91
Mexico lTotal)Not Listed (Total)Not listed
Utah
$24.98 Not listed $25.69 Not listed
Wyoming $9.67 (Open)
Not Listed $9.03 Not Listed 13.62 (Caøtive)
. .. ..* Information received from PaclflCorp based on Platt's mdicates that 2008
average Colorado coal price was $34/ton, a significant increase frm the 2007
level. Additionally, 2008 average Utah coal price was $28.41, also a signifcant
increase from the 2007 level.
48
Idaho Power/202
Said/4
OPUC Staff Audit Report
PacifCorp
March 11, 2009
Audit 2008-002
October 2008 - March 2009
Exhibit PPl03
Laslch4
The DOElEIA prices exclude silt, culm, refuse bank, slurry dam, and dredge
operations. The DOElEIA did not include a price for underground operations in
Wyoming (withheld to avoid disclosure), but the average 2007 market price for
underground operations in Utah was listed at $25.69 and the average 2007
market price for total operations in Colorado was listed as $24.91.
The m~rket price in these neighboring states are comparable to PacifiCorp's
2007 costs for underground and combined operations (Bridger - $23.59; and
Deer Creek - $26.27). The 2008 Deer Creek cost of $25.08 refect a $1.19/ton
decrease in cost from the 2007 level resulting in considerably lower than market
levels ($28.41) in 2008. As noted by FERC Market Snapshot Regional Coal Spot
Prices, Utah and Colorado coal prices have risen sharply in 2008.
In a response to a Staff data request, PaciCorp stted that all power plants are
tyically designed and constructd to consume a typical range of coals. As an
example, the Hayden Plant consumes Colorado coals, which are normally
bituminous, while other plants (Jim Bridger, Dave Johnston, Wyodak, and
Colstrip) consume sub-bituminous coals. The following table highlights the Btullb
of col used by PacifiCorp plants
T bl 27 H t C t t f C I db P ¡fiC PI tsae-ea on en 0 oas use )y ac i orp an
Mines Btu/lb
Havden (Colorado)10,500-11.300 Btu/lb
Dave John~on, VVyodak and Colstrip (PRB)8,000-8800 Btulb
Jim BrldgeUGreefiRiver Basin.. VVvornlng)9,200';10,000 Btullb
According to its website, the DOE/EIA lists Powder River Basin (PRB) spot cost
per short ton, as of November 7, 2008, as $14.50. The website does not
distinguish between underground and surface operations as there appears to be
a lack of historical pricing for VVyoming underground operations. (Bridger is
currently the only undergrOUnd mine operation in Wyoming.) HoweVér, it should
also be noted that the cost of PRB col is expected to increase due to rising
costs of Appalachian coal. According to Mineweb.com9:
Soaring demand for coal and spiking prices should open new
markets at home - and to a lesser extent overseas -- for low-cost,
low-sulfur coal from Wyoming's Powder River Basin, providing a
boost for the miners that prouce it and .the railroads that move it
The article also points out:
9 http://ww.mieweb.comlmineweblview/mlneweb/enpage38?oid=54526&sn=Detail
49
Idaho Power!202
Said!5
OPUC Staff Audit Report
PacifCorp
March 11, 2009
Audit 2008-002
October 2008 - March 2009
Exibit PPU203
Laslchl5
PRB coal is the world's cheapest source of electricity," said Dan
Scott, director of equity research at inve~tment bank Dahlman
Rose. "In today's market, that creates interesting opportunities for
miners and the railroads hauling the coaL.
As a result of potential rising costs. having captive mines may result in an
increasing benefit to PacifCorp customers. This is not a foregone conclusion
and costs and cost trends would need to be examined during subsequent rate
filings.
Transfer Pricing
Commission orders concerning affliated interest contract with Bridger (Order
No. 01-472, U1189) and Energy West (Deer Creek, Order No. 91-105,
U1105) allow for cost-based pricing of coal from thes affliates. This is an
approved departure from OAR 860-027-0048, Allocation of Costs by an Energy
Utilty, whieh normally requires the lower of cost or market stnd~ird when a utility
is purchasing goods or services from an affilate.
ORS 757.495, Contracts involving utlJties and persons with affliated interests,
requires the CÒmmission to approve the contracts if the Commission finds that
the contracts are fair and reasonable and not contrary to the public interest. In
both the Bridger and Energy West contracts, the Commission found that the
contracts were fair and reasonable and not contrary to the public interest.
However, concerning approval of affliated interest colîtracts, the Comriission
does not need to determine the reasonableness of all the financial aspects of the
contract for ratemaking purposes. The Commission can reserve that issue fora
subsequent proceding. The subsequent proceeing in this case would be the
Company's TAM or general rate filing.
Concerning transfer pricing in UI 189, Staffs memo states:
If there should be a further lowering of the savings to PaçifiCorp
and its customers, it may necessitte a modifcation to the transfer
price to meet the Commission's AI policy. This would then reuire
PacifiCorp to comply with proposed ordering condition No.3 to
protect the public's interest.
Deer Creek Mine
Based on a comparison, the average 2007 market price in Utah (underground) of
$25.69 was lower than PacifiCorp's coal costs concerning Deer Creek
underground ($26.27). However; as previously mentioned, the 2008 Deer Creek
cost of $25.49 reflects a decrease in costs from the 2007 level resulting in slightly
lower than market levels ($25.69). If 2008 Der Creek costs are actually
50
Idaho Power/202
Said/6
OPUC Staff Audit Report
PacÎfiCorp
March 11, 2009
Audit 2008-002
October 2008 - March 2009
Exhibit PPU203
Laslch/6
determined to be below market and maintained at below market, this would result
in a benefit to customers.
Trapper Mitling
Concerning Trapper Mining, the 2007 market price for total operations in
Colorado ($24.91) is higher than the Trapper Mining 2007 cost for base ($24.43)
and spot ($20.63) purchases. Additionally, 2008 third-part coal costs for
PacifiCorp's Hayden Plant in Colorado was signifcantly higher ($34.03) than the
TrapperMining 2008 cost for base ($25.57) and spot($29.88) purchases. .Asa
result, Trapper Mining costs actually appear are clearly below market cost, which
results in a benefit to customers.
Bridger Coal
As previously mentioned, Bridger is a cornbined surface/undergrounc,I mining
operation. The following table highlights the change in operation of Bridger from
a predominantly surface operation to a predominantly underground operation
from the 2006 through 2008 time peripd.
T bl 28 B'd MI I 0 tae-ri iger n ng JDera ions
Through
'Septernber
2006 2007 2008
Surface Operations - Tons (000)5.646.0 3,139.4 t,745.0
Surface Operations ";$/ton $18.490 $18.354 $24.467
.,
Underground Operations - Tons 422.3 2ìß44.9 ".2 471.8
Undemround Operations - $rron $51.24 $29.812 $34.185
The 2008 Bridger combined underground/surface cost ($28.34) as well as
underground,co($34.19) are comparable to the 2008 underground mining for
Utah ($28.4) and Colorado ($34.00). The Bridger 2008 sUi'ace coal.cost
($24.467) is considerably higher than two other PacifiCorp's Wyoming plants
(Dave Johnston ($12.09 with transporttion), Wyodak ($11.49), but actually lower
th~iiæal,Çt~t at Naughton ($26.86).. It sho~J1d be noted that Bridger is located inSouthwest Wyoming's Green River Basin (GRB). . Accrding to information
furnished by PacifCorp, there are only three coal mines operating in the GRB.
Additionally, it should be noted that PacifiCorp Bridger costs are higher than the
Wyoming overaU market costs. Unfortunately, because Bridger isthe.öl1lY
underground mining operations in Wyoming, comparative cost studies can not be
made for Wyoming underground operations. In addition, Bridger coal is mined
from GRB and requires a higher heat content than PRB coal, which also affects
any straight cost comparison.
51
Idaho Power/202
Said1
OPUC Staff Audit Report
PacifìCorp
March 11, 2009
Audit 2008-002
October 2008 - March 2009
ExhIbi PPU03
laslch/7
Because PRB coal is the next logical coal supply for Bndger, associated
transportation costs to transport PRB coal to Bridger could possibly make this
option economically infeasible. With that said, the affliated interest statute
allows for a review of costs th~t go into rates.
As a result, rate case staff. should examine 2008 comparable coal costs to
determine ifthe 2008 Bridger costs are in the range of 2008 comparable
underground mining costs for the GRB region. If Bndger costs show a trend of
exceeding comparable market costs, staff may be required to review the transfer
pricing in Ui 189 concerning Bridger in order to protect the public's interest.
In addition, during a rate case or TAM review, utilty staff should recommend that
Bridger .coalcosts be adjusted for the lower of cost or mark7t for ratemaking.
Again, the aff.liated interest order concerning Bridger (Commission Order
No. 01-472,UI189) includes a condition that states:
The Commission reserves the right to review for reasonableness'all
financial aspects of this arrangement in any rate proceeding or
alternative form of regulation.
Staff Re~~mmendation~:
10. Staff should examine 2008 comparable coal costs to determine if the 2008
Bridger costs are in the ~nge () 2008 comparable underground mining
costs for the Green River Basin region. If Bridger costs show a trend of
exceedingçomparable market costs, staff may.be required to review the
transfer pncing in. U i 189. concerning Bridger in order to protect the public's
interest. (Furter investigation during the rate case)
11.ln futu re filings, Staff should recommend that Brldgercoal costs be
adjustedfbr thelåwer of cost or market for raemaking. (FUrter
investigation during the rate case)
Review of Affliate Coal Costs
Staff ex~mined account line detail of affliate coal costs. Tlie following J~öllments
are relevant concerning PacifCorp's coal costs included in rates.
Bridger Coal
Management/Supervisory Overtime
Bridger. experienced a.signifcant. increase in Management/Supervisory overtime
costs from $1171838 in 2006 to an annualized amount of $448,908 in 2008.
Audit Staffis not aware of any recent rate orders that have allowed overtime for
management/supervisory personneL. The Oregon-allocated amount.equals
approximately $80,499 ($448,908 x 66.67 percent x .268974 allocation). As a
52
Idaho Power/202
Said/8
OPUC Staff Audit Report
PacifiCorp
March 11, 2009
Audit 2008-002
October 2008 - March 2009
exhibit PPU203
Laslchf8
result of supervisory overtme costs, ¡nfuture. rate filings, assigned Staff should
examine mining wage/salaries in the same method as analyzed during rate
cases and make the appropriate adjustments to coal costs
Bargainingrremporary Overtime
Bridger experienCed a si~nificant increase in Bargainingrremporary overtime
costs from $6,866,573 in 2006 to an annualized amount of $10,537,424 in 2008
(57.3 percênt). This 2008 overtime amount represented approximately
31 percent of Bargaining/ Temporary 2008 annualized total (regular plus
overtime) pay. Bridger shifed from surface to combination underground/surface
mining operation. As a result, Bridger increased full-time equivalents (FTE) from288 to 353. .
The following table examines FTE and regular/overtime wages for
Bargainingrremporary employees.
Table 29.. Bridger Bargail1il1g/Temporary FTE and Wages (2008
Annualized)
Per Employee
Total FTE 353
Total ReQLJlar $16,878,441 $47,814
Total Overtime $10.537.424 $29,851
Total $21,416,218 $77,665
As ~ result of the high oveliime.costs, in future rate filngs,asslgned ~taffshoLJId
examine minin~ wage/salaries in the same method as analyzed during rate
cases arid makE) the appropriate adjustments to coal costs.
Incentives
Bridger's 2008 annualized incentive costs equal approximately $878,067.
Following the same methodology for ratemaklng, Staff would reç9mmend a
50 percent adjustment to incentives. The Oregon-allocated amount equals
approximately $78,730 ($878,067/2 x ea.67 P€lrcentx .268974 allocation)., .11' .
future rate filings, assigned Staff should. examineinqentives in. the .same method
as analyzed during rate cases and make the appropriate adjustments to coal
costs.
Health Care Costs
According to PacifiCorp, Bridger Coal health care benefit programs target a
90/10 sharing arrangement for bargaining employees and programs ranging frm
a 90/10 to 74/26 for management employees. i 1' the most recent energy utilty
rate.9ase.(UE.197),Staffrecommendedan 85/15 sharing of premium costs.
Bridger's 2008 annualized health costs were $4,417,512. At an 85/15 sharing,
these costs would be approximately $4,172,095. The Oregon-allocated amount
53
Idaho Power/202
Said/9
OPUC Staff Audit Report
PacifiCorp
March 11, 2009
Audit 2008-002
October 2008 - March 2009
Exhibit PPLI03
LaichJ9
equals approximately $44,009 ($245,417 x 66.67 percent x .268974 !3llocation).
. In future rate filings, assigned Staffsbould examine he~lth care costs in the same
method as analyzed during rate cases and make the appropriate adjustments to
coal costs.
Employee - Meals
Bridger experienced $43,564 (annualized to $58,085) in.meals and entert!3inment
expenses. During a rate case, Staf wil normally recommend a. 50 petçent
sharing between customers and shareholders. This is a fair approach that
somewb!3t mirrors the policy associated with bonuses (50 percent sharing
between customers and shareholders) and the handling of these expenses for
income tax purposes. For income tax purposes, the amount allowable as a
federal income tax deduction for business meal and entertinment is generally
limited to 50 percent ofthe total expense. The Oregon-allocated amount equals
approximately $5,208 ($58,085/2 x 66.67 percent x.268974 aIlQcaticm). .In future
rate filings, assigned Staff should examine meals in the same method as
analyzed during rate cases anci make the appropriate adjustments to coal costs.
Donations
Bridger's 2008 annualiZed costs for donations are approximately $2,933. These
çosts should be disallowed because th.e Commission has not allowed regulated
utilities to recover contributions to charities, community affairs, and economic
development organizations through rates charged for regulated services. These
expenses are discretionary and are not required to provide safe and adequate
service tQ9ustomers. In addition, Commission policY~oes notrequire customers
to support ca.LJses inwhiçhthey do not. believe. 10 The ()regon-~1I9cated emoLJnt
equals approximately $526 ($2,933 x. 66.67 percent)( .~68e74 alloci:tion).. .In
future rate filings, assigned Staff should examine donations in the same method
as analyzed during rate cases and make the appropriate adjustments to coal
costs.
Fines and Citatins
Bridger's 2008 annualized costs fQr ft.neš and citations are $203,388. Customers
shoulcinot be required tQ payfor fines!3nd citations incurred by Bridger. The
Oregon-allo.cate~ !3mOunt equals !3Pproximately $36,473 ($203,388 x 66.67
percent x .268974 allocation). In future rate filings, assigned Staff should
examine fines and citaions in the same method as analyzed during rate cases
and make the appropriate adjustents to coal costs.
10 OPUC Order 87-406 staes at pp. 40-41, "Slnceconiniunit afflrs expenditure are
discretionary, the funds could be retained by the busines's owners.... 'Owoers of unregulated
businesses, rather than their customer, make community afirs contributions." Also see
Order 91-186 at 16,
54
OPUC Staff Audit Report
PacifiCorp
March 11, 2009
Idaho Power/202
Said/10
Audit 2008-002
October 2008 - March 2009
ExhibIt PPLl203
Laslch10
Other O&M
Because of the change in operations, Bridger experienced increased costs in
many O&M line items and incurred other costs not experienced during surface
mining operations. Audit Staf recommends that during futre rate filings, Staff
should examine line item costs in order to trend costs. and to highlight any
possible extraordint:ry costs that shoüld not be included in rates.
Staff Recommendations concerning Bridger costs:
12.ln future rate filings, assigned Staff should .examine mining wage/salaries,
overtime costs, health care costs, incentive, donations, meals and
entertinment, and fines in the same method as Company wages are
analyzed during rate cases and make the appropriate adjustment to coal
costs.
13.ln future rate filings, assigned Staff should examine line item costs in order
to trend costs and to highlight any possible extraordinary costs. _
Deer Creek Mine
Staf examined acCunt-line detail for the Deer Creek Operations. The following
comments are relevant concerning PacifiCorp's coal cots in rates.
Management/Supervisoty Overtime
Deer Creek experienced a significant decrease.. in Management/Supervisory
overtme costs from $351,306 in 2006 to an annualized amount of $182,.?:?5 in
2008. Although this is a decrease in costs, Audit Staff is not aware ofan~ recent
rate orders that have allowed overtime for management/supervisory personnel.
The Oregon-allocated amount equals approximately $49,094 ($182,525 x
.268974 allocation). In future rate filngs, assigned Staf should examine
sUR~rvsory overtime in the same .rTethod as analyzed during rt:e cases and
make the appropriate adjustments to coal cots.
Bargaining Overtime
Deer Creek experi~nc~da. increase in bargaining. overtime costs from
$2,350,962 in 2006 to an annualized amount of $2,526, 102 in 2008. This 2008
overtme amount represented- approximately 18.4 percent of Bargaining 2008
annualized total (regular plus overtime) pay. The following table examines FTE
and regular/()vertime wages for bargaining employees.'¡
Table. 30 - Deer Creek Baraainina FTE and WaGes 2008 Annualind)
Per EmDlovee
Total FTE .278
Total Regular $11,217,881 $40,352Total Overtime $2,526 102 $9,087Total$13,744.261 $49,439
55
Idaho Power/202
Said/11
OPUC Staff Audit Report
PacifiCorp
March 11, 2009
Audit 2008-002
October 2008 - March 2009
Exibit PPLJ203
Laslch/11
As can be seen from the above table, total pay of Deer Creek bargaining
personnel ($49,439) is approximateiy 63.7 percent of total average bargaining
pay of Bridger Coal ($77,655). This diffrence is primarily a result of lower
overtime payments and reflects a considerable savings for ratepayers. In future
rate filings, assigned Sta should examine mining wage/salaries in th.e same
method as analyzed during rate cases and make the appropriate adjustments to
coal costs.
Incentives
Deer Creek's 2008 annualized incentive costs equal approximately $1,230,000.
Follqwing the same methodology for ratemaking, Staff would recommend a
50 percent adjustment to incentives. The Oregon-allocated amount equals
approximately $165,419 ($1,230,000/2 x .268974 allocation). In fuure rate
filings, asSigned Staff should examine incentives in the same metnod.as
analyed during rate cases and make the appropriate adjustments to coal costs.
Health Care Costs
According to PacifiCorp, Deer Creek's health care benefit prognams in 20Q7 and
2008 ranged from 85/15 to 80/20 cost sharing. The option of a 90/10 cost
sharing arrangement for management employees was implemented in 2008. All
other plans have a 74/26 cost sharing arrangement in 2008. In the most recent
energy utility r¡:te case (UE 197), Staff recommended an 85/15 sharing of
premium costs.. In future rate filings, assigned Staff should examine health care
costsin the same. meth9d as analyed during rate cases and make the
appropria,te eidjustments to coal costs.
Meals and Entertainment
Deer Creek experienced $33,463 (annualized to $44,617) in meals¡:nd
entertinment expenses. As previously mentioned, duringei reite case, Staff Wil
normally recommend a 50 percent sharing between customers and shareholders.
The Oregon-allocated amount equals approximately $6,000 ($44,617/2 x
.268974 allocation). In fuure rate filings, assigned Staff shopld ex¡:mine meals in
the same method as analyed during rate cases and m¡:ke the appropriate
adjustments tocqal.costs.
Club/Organization Membership and Expense
Although Deer Creek had costs in 2006 and 2007 for this line item, PacifiCorp
reported $0 for 200e. Normally, this is¡:cost item that staff would examine in .
more detail; Iiowever because there Is no cost in 2008, a further review is not
necessary. In future ~ate filings, assigned Staff should examine membership
expenses in the same method as analyzed during rate cases and make the
appropriate adjustments to coal costs. .
56
Idaho Power/202
Said/12
OPUC Staff Audit Report
PacifiCorp
March 11, 2009
Audit 2008-002
October 2008 - March 2009
Exhibit PPU203
Laslch/12
Mining Services
In 2008, Deer Creek Mine experienced $2.33 milion in mining services.
According to PacifiCorp, these services are for major equipment overhauls
perfrmed away from the mine at vendor facilties. During PacifiCorp's
subsequent rate filings these costs should be reviewed in detail to determine if
some. of these expenses are more correctly capitalized. This is because
replacements and overhauls generally have the effect of inereasing the servce
potential of an asset by either Improving the asset's effciency or extending the
asset's economic useful life. As a result, the costs of replacements and
overhauls are capltalized.11
OtherO&M
Audit $taff reeommends that during future rate filings, assigned staff should
examine line item costs in order to trend costs and to highlight any possible
extraordinary costs. Concerning Deer Creek, Audit Staff notes considerable
increase in professional services, management fees, royalties, and fuel from
2007 to 2008.
Staff Recommendations concerning Deer Creek costs:
. 14. In future ~le filings, assigned ~taff should .exaniinemining wage/salaries,
overtime costs, health care costs, . incentive, donatic)ns, .. meal~ and
entertinment, and membership expenses in the same methOd as
Company wages are analyzed during rate cases and make the
appropriate adjustments to coal costs.
15.ln fuure rat$ filings, assigned Staff should examine line item costs in order
to trend costs and to highlight any possible extraordinary costs.
Trapper Mining
Because PacifCorp is a minority owner ofT~pPer Mining, PaclfiCorp did not
have detailed line item costs for Trapper Mining. However, as previously
mentioned, Trapper Mining costs were lower than the listed DOE/EIA 2007
market costs. As a result, PacifiCorp Is actually receiving goods at the lower of
cost or market.
Coal Transportation
PacifiCorp's Cholla, Dave Johnston, and Hayden Plant all received transported
coaL. The following table examines transportation cost per ton.
11 Munter- Radcliffe, Applying GAAP and GAAS, Depreiable and Intangible Assets, Matthew
Bender & Co., Inc. page 10-21.
57
Idaho Power/202
Said/13
OPUC Staff Audit Report
PacifiCorp
March 11 t 2009
Audit 2008-002
October 2008 - March 2009
Exhibi PPU203
Lasich/13
bTaIe 31 - Coal Transporttion Costs
Percent
Change
Plant 2006 2007 2008 2007 -2008
Cholla - Arizona (Coal from
New Mexico and MOntana $4.91*$7.47 $7.97 6.69%
Dave Johnston - Wyoming
(Coal from Wvominã)$4.65 $4.68 $4.94 5.26%
Hayden - Colorado (Coal
from Colorado)NA""NA $2.76 NA
" Cholla's 2006 costs were signifcantly lower than subsequent yealS due to a
$3 milion credit applied to Cholla in January 2006.
"" Pnorto 2008, PacifCorp did not separate transportaticm bO$ts from coal
costs at the Hayden plant.
Because PacifCorp's Cholla plant is located in Arizona, higher transportation
costs would be reasonably expected. Because of the low cost of coal being
supplied to the Dave Johnston plant ($7.1.4 in 2008), transportatioo.costs actually
account for approximately 40.4 percent of total coal costs. Even with
transportation CQsts, the Dave Johnston plant had the second lowest 2008 coal
costs for PacifiCorpplants at $12.07 per ton. Only the Wyoakplant, supplied by
the Wyodak mine and not.requiring transportation, had lower costs at $11.49 per
ton.
As previouslymentioned, PaGifCorp has.tw0 Commission approved affliated
contracts with Burlington Northern Santé FeRailroad (BNSF). Berkshire-
Hathaway currently owns 17 percent of BNSF. PacifiCorp has long-term col
transportation contracts with BNSF, including indirect payments to a generation
plant that is jointly owned by PacifiCorp. The transportation contact were
approved by the CommiSSion in Order NO.07..323 (UI269), dated July27,2007.
BNSF provides transportation services from:
1. Various coal mines in the Wyorning Powder River Basin to PacifCorp's
David Johnston Steam Plant (David Johnston); and
2. Various coal mines in Wyoming, New Mexico, and Montana to
PacifiCorp's ChoJla Generating Station (Cholla).
These agreements were executed as third-part agreements prior to PacifiCorp
becoming a subsidiary of MEHC. This type of service is provided pursuant to a
58
Idaho Power/202
Said/14
OPUC Staff Audit Report
PacifiCorp
March 11, 2009
Audit 2008-002
October 2008 - March 2009
Exhibit PPU203
. Lasich/14
contract filed and approved by the Surface Transportation Board (STB) 12 would
generally not require Commission approval; however, PacifiCorp and MEHC
agreed to a different affilate transaction standard as part of PacifiCorp's
acquisition by MEHC. PacifCorp pays approximately $30 millon per year for
services under the Agreements with BNSF. PacifCorp records most of the
charges related to the BNSF agreements in FERC Accunt 501, FueL.
Operations and Maintenance Expenses
The following table presents O&M expenses (FERC accounts 500-598) for 2006
and 2007,:
T bl 0a e 32.&M Cost Comi arlson
Percentage Change
2006 2007 20062007
Labor 123864,786 100,446,457 -18.9%
Non-Labor 432,179,061 572,124,600 32.4%
TotaIO&M 556,043,847 672,571,057 21.0%
The overall increase is higher than the Consumers Price Index for All Urban
Consumers of 2.8 percent for the period and is largely atributble to two areas -
(1) higher gas costs and (2) plant additions. An account comparison was made
and there were 15 instances of year-ta-year variances greater than 10 percent.
The company provided satisfactory explanations for these increases. The
distortions due to singular accounting occurrence i.e. out-of-period charges
were also itemized.
Customer Service
The company stated that there is a ten-year technology improvement plan.
There are four current deliverables:
1. Customer correspondence improvement project - template improvement
as to location and clarity.
2. Automated outage customer call back program - customizing notification
and follow up service restoration.
3. Computer telephony integration and interactive voice response systems -
symmetry between account information displayed online and phone
accessible and multiple phone match screens.
12 The Surfce Transportation Board (STB) was creted in the Interstate Commerce Commission
Termination Act of 1995 and is the succesor agency to the Interstate Commer Commission.
The STB is an economic regulatory agency that Congress charged with the fundamental missions
of resolving railroad rate and service disputes and reviewing propose railroad mergers. The
STB is declslonally independent, although ltis administratively afliated with the Departent of
Transportation. (ww.stb.dot.gov)
59
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-E-10-01
IDAHO POWER COMPANY
ATTACHMENT NO.3
BEFORE THE PUBLIC UTILITY COMMISSION
OF OREGON
UE214
IN THE MATTER OF )
IDAHO POWER COMPANY'S )
2010 ANNUAL POWER COST UPDATE )
)
)
)
IDAHO POWER COMPANY
REPLY TESTIMONY
OF
TOM HARVEY
March 17, 2010
REDACTED
Idaho Power/300
Witness: Tom Harvey
r
1 Q.
2 A.
3 Boise, Idaho.
4 Q.
5 A.
Idaho Power/300
Harvey/1
Please state your name and business address.
My name is Tom Harvey. My business address is 1221 West Idaho Street,
By whom are you employed and in what capacity?
I am employed by Idaho Power Company ("Idaho Powet' or "Company") as
6 Manager~Joint Projects.
7
8
Q.
A.
Please describe your educational background.
I have a Bachelor of Business Administration-Business Management from
9 Boise State University.
10
11
Q.
A.
Please describe your business experience with Idaho Power.
I have been the Manager-Joint Projects for four months. In this position I
12 supervise Idaho Power's interests in the Jim Bridger, North Valmy, and Boardman coal-fired
13 power plants. I also manage Idaho Powets interests in the Bridger Coal Company ("BCC")
14 and coal supply acquisition/fuel management. I am a member of the Bridger Coal
15 Management Committee which is comprised of two Idaho Power and two PacifiCorp
16 employees. This committee directs Bridger Coal on both short .and long-term strategy
17 issues, reviews current operations and approves all capital and 0 & M expenditures. With
18 respect to the Jim Bridger Plant ("Bridger Plane or "Plant") I work with PacifiCorp on the
19 fueling strategy and oversee Idaho's minority share of the overall operations of the Plant.
20 Prior to my appointment to my current position, I served as Idaho Power's Fuels
21 Management Coordinator from 1985 to 2009. In this position I was responsible for coal
22 su~ply acquisitionluel management for Idaho Power's interest In the coal-fired power plants
23 and Bridger Coal Company. Prior to 1985. I worked in Idaho Powets power supply and
24 plant accounting departments. Beginning with the Fuels Management Coordinator position,
25 I have worked closely with PaclfiCorp to coordinate fuel deliveries and coal purchase
26 strategy.
REPLY TESTIMONY OF TOM HARVEY
1
2
Idaho Power/300
Harvey/2
Q.
A.
What is the purpose òf your testimony?
The purpose of my testimony is to respond to the coal cost adjustment
3 proposed by Staff witness Michael Doughert.1 Company Witness Gregory Said's testimony
4 responds to the policy issues raised by Mr. Doughert's proposal while my testimony
5 addresses the technical and factual issues raised by his adjustment.
6
7
Q.
A.
Please describe Mr. Doughert's proposed adjustment.
Mr. Dougherty's adjustment focuses on the coal costs for the Bridger Plant.
8 As I wil discuss in more detail below, Idaho Power co..owns with PacifiCorp both the Bridger
9 Plant, and its associated mining operation, BCC. The Plant is run primarily on coal from
10 BCC's surface and underground mining operations, supplemented by coal purchased from
11 thel3labk Butte Mine ("Black Butte"). Mr. Doughert claims that the costs of the coal
12 purchased by the Company for the Bridger Plant from. BCC exceeds the market rate for coal
13 añd therefore violates the Public Utilty Commission of Oregon's lower of cost or market
14 ("LCMD) ~ule.2 To remedy this perceived violation, Mr. Doughert replaces the cost of BCC's
15 surfce coal-which is more expensive to produce than the underground coal-with the cost
16 of the Black Butte coal. Accordingly, Mr. Doughert proposes a $15 million system-wide
17 adjustment.
18
19
Q.
A.
Please summarize the Company's reponse.
My testimony, together with the testimony of Gregory Said, wil demonstrate
20 that Mr. Dougherty's LCM analysis is flawed in two respects: First, Mr. Dougherty
21 improperly calculates the cost of BCC surface coal for comparison to market alternatives. In
22 order to produce a meaningful result the LCM analysis mustcoñsider the decremental cost
23
24 1 Staff/200.
25 2 The LCM rule states that for transactIons between a regulated utility and an unregulated affilate,
26 any. goods sold by the affliate to the utility must be priced at the lower of the cost to the affliate to
produce the good or the market rate to purchase a comparable prouct fr a non-affilated supplier.
REPLY TESTIMONY OF TOM HARVEY
Idaho Power/300
Harvey/3
1 (or, avoided cost) of the BCC surface coaL. When the decremental cost is considered, it wil
2 demonstrate that the cost that the Company wil avoid if it replaces the -BCC surface coal
3 with coal from Black Butte is actually less than it would pay for the replacement Black Butte
4 coal-assuming it could be obtained. . Second, Mr. Dougherty errs in setting the "market
5 price" by reference to the cost of Black Butte coal-hich, as i wil explain, is not available in
6 sufcient quantities to replace BCC surface coaL. The contract price the Company pays for
7 Black Butte coal does not constitute the "markee price at which the Company could obtain
8 an alternative coal supply for the Bridger Plant. i wil show that when the cost of coal that
9 may be available to replace the BCC surface coal is considered, it is clear that, overall, BCC
10 coal is the lowest cost resource.
11 Finally, i wil describe the non-price benefits of the BCC contract to Idaho Power's
12 customers, which include the use of BCC coal in the blending process to produce the most
13 efficient coal for the Bridger Plant and the flexibilty to use BCC operations as a hedge
14 against production decreases at Black Butte.
15
16
17
BRIDGER PLANT ANDBCC
Q.
A.
Please describe the Bridger Plant.
The Bridger Plant is a coal-fired electric generation facility consisting Of four
18 units with a unit nameplate net capacity of 530 megawatts ("MW') each. The plant is jointly
19 owned by PacifiCorp and Idaho Power and is located in southern Wyoming, in the Green
20 River Basin ("GRB"). PacifiCorp is a two-thirds majority owner and operates the Plant.
21 Idaho Power owns the remaining one-third minority interest. At normal operàtion the Plant
22 bums approximately i..tons of coal annually.
23
24
Q.
A.
Is the Bridger Plant run continuously?
Yes. Large coal-fired generation plants, such as the Bridger Plant, are less
25 expensive to operate than other forms of generation, and conversely, are expensive to shut
26 down and restart. For these reasons, the units are normally run.continuously and shut dOWn
REPLY TESTIMONY OF TOM HARVEY
Idaho Power/300
Harvey/4
1 only for planned maintenance, unplanned outages, or emergencies. Because these
2 resources generate on a continual basis it is essential that they have access to a continuous
3 and reliable source of coal. The Plant's continuous operation dictates, in part, the coal
4 procurement strategy for the Company. As described in more detail in Mr. Said's testimony,
5 the Company's coal strategy relies on a combination of indexed contracts and BCC coal to
6 meet the coal supply needs of the Bridger Plant. A key component of this strategy is the
7 Use of BCC's captive mine and long-term contracts to produce a long-term, stable, and low-
8 cost supply of coaL. For the Bridger Plant this strategy is mindful of the lack of a spot market
9 for coal purchases in the GRB.
10
11
Q.
A.
What are the sources of the Bridger Plant's coal?
The Bridger Plant was designed and constructed as a limine-mouth" plant,
12 which means it is physically located next to the coal mine that supplies the majority of its
13 coaL. The adjaCent mine is owned by BCC, which is jointly owned. by PaCifiCorp and Idaho
14 Power, on the same two-thirdsone-third basis as the Bridger Plant. 3 This arrangement
15 ensures that the Plant has acce to a continuous and reliable supply of coaL. BCC
16 provides the Plant with approximately I millon tons of coal annually-or approximately
17 . tons per delivery day. Of the total BCC deliveries, it is projected that the BCC
18 surface mining operation wil provide the Bridger Plant with approximately I ~iIion tons of
19 coal in 2010, and .'millon tons in 2011, and the underground operations wil account for
20 approximately I millon tons in 2010, and I millon tons in 2011.
21 Coal is delivered to the Plant from the BCC mine by use of a large conveyor belt
22 system that transports and delivers coal directly from the mining operation into the Plant.
23 This type of mine-mouth plant operation has several advantages over an operation where
24
25 3 BCC is one-third owned by Idaho Energy Resourcs Company ("IERCO"), a subsidiary of Idaho
Power, and two-thirds owned by Pacific Minerals Inc.("PMI"), a subsidiary of PacifiCorp. The coal
26 supply agreement between Idaho Power and IERCO was approved by the Oregon Commission by
Order No. 91-567 in Docket UI107 on April 25, 1991.
REPLY TESTIMONY OF TOM HARVEY
Idaho Power/300
Harvey/5
1 the coal is delivered from another location. First, the mine mouth operation has the obvious
2 advantage of eliminating the need to ship coal over long distances in order to supply the
3 generating plant-usually at great expense. In addition, the mine mouth operation avoids
4 the undesirable result of locating the coal fired generation plant in close proximity to large
5 population centers which typically correspond to the large load centers.
6 Q.Where does the Plant get the rest of its fuel?
7 A. The remain~er of the coal consumed by the Plant each year-approximately
8 . millon tons-comes from the Black Butte Mine, which is also located in the Green River
9 Basin, approximately 12 rail miles from the Bridger Plant.
10
11
Q.
A.
Please describe BCC's underground and suñace mining operations.
As mentioned above, the Bndger Plant relies on coal from both the sunace
12 and underground operations of the BCC mine.
13 The sunace mine commenced commercial operations in August 1974 and has been
14 producing coal for the Bridger Plant since that time. The sunace mine utilzes draglines for
15 overburden removal and a truck/shovel fleet for coal removal. The coal is trucked to dump
16 stations and is then transported to the Plant utilzing .a conveyor system. Current maximum
17 . capacity of the ~unace mine is approximateiy. millon tons per year. Because the
18 sunace operation is used, in part, to provide operational flexibilty to thaBGC operation and
19 the Plant itself, the production levels at the sunace mine are determined by forecasting BCC
20 underground and Black Butte delivery schedules to ensure that the.. plant receives its
21 required coal volumes.
22 The Company starte~ underground mining operations with the development of the
23 portals and main entries in September 2004 and the first longwall coal production was in
24 March 2007. The primary method of coal extraction at the BCC underground operation is a
25 longwall system. The underground operation is currently operating at capacity and
26 production is limited to its current levels.
i
I
!
!
REPLY TESTIMONY OF TOM HARVEY
Idaho Power/300
Harvey/6
1
2
Q.
A.
Are the surface and underground mines separate operations?
No, the surface and underground mines are run as an integrated operation.
3 While the underground mine provides the lion's share of the coal to the Bridger Plant, the
4 surface operation provides coal critical to the blending process, additional capacity, flexibilty
5 in running the underground operations, a hedge on prices, and support for the common
6 costs. Both the surface and the underground BCC operations share common assets such
7 as conveyors, scrapers, dozers, light duty vehicles,.. maintenance shops, administrative
8 buildings, etc. Mine administration personnel including purchasing, planning, engineering,
9 environmental services, information technology, safety, human resources, administration
10 services, government relations and surveying support both operations.
11
12
Q.
A.
How is the price of BCC coal determined?
In 1974, PacifiCorp and Idaho Power entered into a long-term coal sales
13 agreement with BCC. Pursuant to that agreement, and its restatements and amendments,
14 the c.oal sales. priçeis computed based on BCC's total projected costs and includes a
15 calculated operating margin as provided for in Idaho Powér's rate base. The såles price is
16 adjusted periodically as updated cost data becomes available. Each time the sales price is
17 adjusted the parties execute an amendment to the agreement.
18 Q.Has the Company undertken any effort to reduce BCC's mining
19 costs?
20 A.Yes. BCC pursues best mining practices on a daily basis. BCC has pursued
21 several initiatives that have resulted in reduced costs. BCC is also pursuing a royalty rate
22 reduction with the Bureau of Land Management on federal coal leases. BCC has also
23 employ~d contractors when cQstefféctiveand/or timing dictates. In the spring of 2009, BCC
24 solicited bids for the performance of final reclamation. Reclamation work is being performed
25 per agreement with the Wyoming Department of Environmental Quality. BCC subsequently
26 awarded a bid to Oftedal Construction Inc. Ofedal commenced reclamation activity in
REPLY TESTIMONY OF TOM HARVEY
Idaho Power/300
Harvey/7
1 March 2010. With improved predictive maintenance practice, the BCC mine has been able
2 to extend the useful life of surface equipment. By lengthening critical component lives, the
3 mine has been able to lower hourly operating costs. BCC has, where feasible, incorporated
4 into its mine plan the movement of overburden from the surface mine stripping operations
5 and directly placed the overburden in a final mine closure location to reduce rehandle costs.
6 Q.Mr. Doughert's adjustment focuses on the costs associated with
7 BCC's surface coal separate from the costs associated with BCC's underground coal,
8 suggesting that Bridger should shut down its surface operations and replace the
9 surface coal with coal purchased from Black Butte or some other third part. Is Mr.
10 Doughert's recommendation reasonable?
11 A.No. First, as I wil explain below, while BCC's surface coal is more expensive
12 than the underground coal, the costs associated with any available replacement coal are
13 higher than the cost that would be avoided if the surface operation ended. In fact, thé
14 decremental cost of BCC surface coal is approximately
15 . That being the case, the BCC surface coal is the lowest
16 cost resource. Second, there is a very significant advantage to the abilty of the Company to
17 control the production of the surface mine. For instance, if there were a major issue at the
18 BCC underground operation or at the Black Butte mine that limited coal production, BCC's
19 surface operation could be ramped up to help fil the production void. This diversified
20 approach provides the level of reliable and continuous coal supply that is reuired by a
21 regulated utility in order to meet its obligation to reliably serve its customers' loads.
22 Q.You have stated above that the decremental cost of the BCC surface
23 coal is actually $. . Could you please explain
24 what you mean by thedecremental cost and ~ow you made your calculation?
25 A.As explained above, BCC's underground and surface mines constitute one
26 integrated operation. As such, many of the costs to run the mine are allocated to the col
REPLY TESTIMONY OF TOM HARVEY
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1 produced by both the surface and underground mines. If the surface mine were shut down,
2 which Is the logical implication of Mr. Doughert's adjustment. many of the shared costs
3 would not be avoided but rather would need to be reallocated to the cost of the underground
4 coaL. In other words, BCC cannot avoid all of the costs allocated to the surface coal by
5 shutting down the surface mine. So, for the purposes of a lower of cost or market analysis.
6 theacit of the surface coal should be considered at the cost that BCC could avoid by
7 shutting down the surface mine-or, the decremental cost of the BCC surface coal.
8 Q.Has BCC calculated the decremental cost of the surface coal, and if so,
9 please explain how that calculation was made.
10 A. Yes. BCC calculated the decremental cost öf surf~ce coal based upon its
11 moslpul'èntlyavailable mine plan. The current mine plan projects BCC costs to be ..
per ton for the April 2010 through12
13 March 2011 test period. These updated production costs were then used as the starting
14 point for the decremental analysis.
15 To calculate the decremental cost for the test period, BCC projected total mine
16 operating costs based on continued operation of the underground mine and final
17 reclamation activities. Surfce coal production was eliminated, which resulted in significant
18 expenditure reductions for labor and benefits, materials and supplies, outside services, and
19 röyalties. Surface mine expenditures for severance tax, extraction tax, federal reclamation
20 fees, and black lung excise taxes were eliminated. Unavoidable operating costs previously
21 allocated between surfce coal production and final recl.amation are charged only to final
22 reclamation which necessitated increased reclamation trust fund contributions,. The analysis
23 did not include severance costs that would exist if surface coal production was terminated.
24 In the end the decremental cost of the surface coal at BCC is . per ton. In order to
25 ensure a conservative estimate, The Company approximates this cost as . 'for
26 purposes of its analysis in this case.
REPLY TESTIMONY OF TOM HARVEY
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1 This analysis estimates that BCC would save approximately .'for every ton of
2 surface coal not mined. That sum would therefore be available to purchase replacement
3 coal on .the open market.
4 Q.Can you describe how the decremental cost was detennined?
5 A. The decremental analysis prepared for the test period assumed Bridger Coal
6 Company would produce I millon tons of coal at a cost Of. milion or .er
7 ton. Without the Bridger surface operation, test period Bridger Coal production would
8 decrease to . milion tons at a total cost of $. milion, or .per ton. The
9 estimated decremental mine cost of $., in this test penod, was derived .py dividing the
10 dollar differential ($. milion) by the tonnage differential (ImiIlOn) between the two
11plâns. The result of the study is a "reduction in total BCe cost of ~ and a
12 reduction 01_ surl lone lorthø leet period. When yö díiJ.i!l â~fJtìbY the
13 tons you get ~ the decremental cost per ton.
14 Q. What is the significance of the decremental cost?
15 A.The decremental cost is the benchmark against which alternative coal costs
16 should be measured because this is the amount it actually costs to purchase coal from
17 BCC'ssurface mining operation. Later in my testimony i will examine in detail the actual
18 costs of market alternatives available to replace BCC surface coal should the Company be
19 required to do so. This comparison i.s meaningful only after properly determining the
20 decremental cost of BCC's surface coal.
21 Q.Does Mr. Dougherts comparison ofBCC sunace costs utilize the
22 decrementalcost?
23 A.No. Mr. Dougherty's analysis focuses on the average costs per ton for
24 surface and underground coal reflected. in the Company's response to Staffs first data
25 request. Accordingly, Mr. Dougherty assumes that if BCC were to cease its surface mining
26 operation, that BCC's underground coal would continue to be available to the Bridger Plant
REPLY TESTIMONY OF TOM HARVEY
Idaho Power/300
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1 at the average cost per ton also described in that response. Mr. Dougherty's analysis is
2 flawed, however, because it does not take into consideration the fixed costs associated with
3 the integrated mining operation that cannot be avoided if the surface mine is shut down and
4 that wil therefore be allocated to the underground coaL. His analysis also fails to account for
5 the increased costs of reclamation the Company would incur if surface. mining ends. When
6 all of those costs are considered, it becomes clear it would be more expensive for the
7 Bridger Plant to replace the BCC surface coal with Black Butte coal.--r similarly priced
8 alternative coal-than to continue to purchase both underground and surface coal from
9 BCC.
10
11
ALTERNATIVES TO BCC SURFACE COAL
Q.You stated above that Mr. ÔougherfY'$anâlysi$i' fl,Wecl b.cause it
12 errOneously åS$ul1es that the Company êould replåce the BCC sl,lfâc.cOal with coal
13.from Black Butte or someotler third part. Pleâse explain.
14 A. The Black Butte mine presently suppliesapprQxiniåtely.one.thi,.pøftnecoal
15 that is used to fuel the Bridger Plant-approximately . millon tons per year. By.defining
16 the "markee as the price paid by the Company for the Black Butte coal, Mr. Doughert
17 implicitly assumes that the Company could replace the BCC surface mine coal with coal
18 from Black Butte-or some other third party-and at the same price that it is paying for the
19 Black Butte coal that it is currently purchasing. The fact is that it cannot. First, I wil
20 describe the terms and conditions under which Black Butte currently supplies coal to the
21 Bndger Plant, and then i will explain why additional Black Butte coal cannot be used to
. 22 replace the BCe surface coaL.
23
24
Q.
A.
Please describe the Black Butt contract.
Effective on October 31, 2008, PacifiCorp, Idaho Power, and Black Butte
25 Coal Company entered into a coal supply contract for coal purchases for the Bridger Plant.
26 This contract has a term of January 1, 2010, through December 31,2014. Annual volumes
REPLY TESTIMONY OF TOM HARVEY
Idaho Power/300
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1 range fro. milHon tons in 2010 to .,million tons for 2011lhrough 2014. The base
2 price is $.-per ton F.O.B. mine and is adjusted for changes in taxes and royalties,
3 indexed components, and btu content.
4 Q.Can the Plant purchase additional coal from Black Butt to replace the
5 BCC suñace coal?
6 A.No. First, Black Butte has very little additional coal that it can. commit to sell
7 to the Bridger. Plant. The vast majority of Black Bute's production is already committed to
8 be sold under the Bridger Plant's current contract, with most of the remainder committed to
9 the North Valmy Power Plant, which is co-owned by Idaho Power and NVEnergy. Infact, In
10 2008, the Black13L1tte lliljehad nOe)(eeSSproduçtigtiCapacity at all.
11
12
13
14 . By way of comparison, BCC
15 projects surface production of approximately millon tons for 2010 and 2011,
16 respectively. Clearly, Black Butte simply does not have enough volume available to replace
17 the BCC surface production.
18 Moreover, with respect to the Black Butte coal that might be available, there is no
19 evidence that it could be obtained at the same price as under the existing contract. On the
20 contrary, the price quoted by Kiewit Mining for that uncommitted production was
21 substantially higher than the price paid by Bridger under the existing Black Butte contract.
22 Kiewit Mining quoted an F.O.B. mine price Of. per ton, with an adjustor for changes in
23 diesel fuel costs, for volumes, such as the above referenced . annual tons, in excess
24
25
26
REPLY TESTIMONY OF TOM HARVEY
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1 of the new contract. This price does not include the price of shipping the coal from the Black
2 Butte Mine to the Bridger Plant, estimated to be. per ton.4
3 Q. How does this cost compare to the cost oIBCC's surface-mined coal?
4 A. As described above, the decremental cost of BCC coal is $.: per ton.
5 This is the amount the Company saves if it does not mine that coaL. To replace that coal
6 with Black Butte coal wil cost approximately $. per ton. Thus, the Company would
7 save. per ton and pay. 'per ton. This results in an increase in overall coal costs
8 and indicates quite clearly that in fact the BCC surface coal is lower than the price available
9 from Black Bute.
10
11
COAL BLENDING PROCESS
Q.Are there any other reasons why BCC's surface coal could not be
12 replaced with Black Butte coal?
13 A.Yes. BCC's surface coal is an integral part of the necessary blending
14 process before coal is burned at the Bridger Plant. From a coal quality perspective. the
15 Bridger Coal surface and underground operations are complementary. On average, the
16 Bridger surface operation produce the coal With the highest sodium, and lowest ash
17 content and ash softening temperatures, while the Bridger underground operation produces
18 the coal with the lowest sodium, and highest ash content and ash fusion temperatures.
19 Removing the surface coal from the blending process and replacing it with Black Butte coal
20 wil adversely impact the effciency. of the plant and also have an adverse environmental
21 impact.
22
23
Q.
A.
Please describe the blending process that occurs for the Bridger Plant.
Because of operational and environmental constraints, the coal that is burned
26 4 Presently, all Black Butte coal is shipped to Jim Bridger by rail. In the past some limited amounts of
Black Butte coal have been shipped by trck.
REPLY TESTIMONY OF TOM HARVEY
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1 Plant meets all environmental regulations and generates at . its optimum level with minimal
2 de-rates. To achieve these standards, coal from different sources is analyzed and blended
3 to conform to the required quality standards.
4
5
Q.How does Bee surface-mined coal fit into this process?
The surface operation is critical to this coal blending process. All coal,A.
6 surface and underground, has a certain coal quality. Mine plans are developed on a
7 monthly basis to ensure that the delivered coal product to Bridger meets specific coal quality
8 constraints. These constraints concern ash, slag, and environmental considerations, all of
9 which are sensitive and effected by the chemical make-up of the coal that is burned. On a
10 daily basis mine deliveries are adjusted to meet Plant specifications. All coal blending is
11 performed by the surface mine. Blending is critical because the. underground mine
12 operations are limited to a single coal seam. Without the flexibilty of.he surface operation,
13 BCC could not deliver a coal stream that would meet the requirements of Bridger
14 operations.
15 All three coal sources for the Bridger plant (BCC surface, BCC underground,and
16 Black Butte) have quality cycles. Geology and quality can vary within a seam as well as
17 from seam to seam. Through blending of coals, both BCC and the Bridger Plant minimize
18 quality variations that undermine optimal Plant performance. Both BCC and the Bridger
19 Plant have installed coal analyzers that provide operations with instantaneous data. With
20 this information, both the Mine and the Plant can adapt their blending.
21
22
Q.
A.
What other factors affect the coal blending process?
Ash content is a very important consideration when blending coal. Because
23 of its importance, BCC has CoalScan Analyzers designed to specifically measure ash
24 content. The ash content of the underground operation fluctuates depending upon the ash
25 content of the mined seam and the amount of coal produced by the continuous miners. In
26 201'0, for instance, the ash content of tlie . underground coal is. projected to range from
REPLY TESTIMONY OF TOM HARVEY
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1 approximately 10 percent to 22 percent. Comparatively, the ash content of the surfce
2 operation is projeced to be from 7 percent to 13 percent. The coal burned in the generating
3 units should have an ash content of 12 percnt or less; thus, blending the surface and
4 underground coal is necessary to achieve usable coaL.
5 In addition to ash content, the Plant also has established coal quality targets for heat
6 content (Btu/lb), ash softening temperature, iron, sodium, and calcium. Sodium, ash, and
7 heat content are the most critical variables. As previously stated, from a coal quality
8 perspective, the BCC surface and underground operations are complementary. On
9 average, the BCC surface operation produces the coal with the highest sodium, and lowest
10 ash content and ash softening temperatures, while the BCC underground operation
11 produces the coal with the lowest sodium, and highest ash content and ash fusion
12 temperatures. Fueling plans are prepared to ensure BCC coal deliveries, in aggregate,
13 conform to established targets.
14 The Bridger Plant also performs limited blending. To maximize generating
15 availabilty, a Thermo Fischer CQM Elemental Analyzer has been installed at the Plant. This
16 analyzer provides the Plant With instantaneous coal quality data as coal is transferred from
17 the stockpile to the coal silos. The Plant operator is provided With measurements of
18 moisture, ash, sulfur, btu content, ash softening temperature, iron, calcium, and sodium.
19 Q.Has Bee applied these coal quality targets to all coal supplied to the
20 Bridger Plant?
21 A.Yes. Coal quality targets have been established for heat content (btullb), ash
22 content, sulfur, ash softening temperature, sodium, calcium and iron for BCC, Black Butte
23 coal, and the Bridger Plant. Personnel from the PacifiCorp Fuels Department, BCC, Idaho
24 Power, and the Bridger Plant all. participate in daily calls to discuss and review the fueling
25 plans. BCC adjusts its coal quality to meet the Plant's requirements. Depending upon
26
REPLY TESTIMONY OF TOM HARVEY
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1 Black Butte's coal quality, BCC wil adjust the proportion of surface and underground
2 deliveries to ensure coal, in aggregate, conforms to established targets at the Plant.
3 The following table ilustrates the coal quality targets that have been developed:
4 Coal Quality Targets
5 Briger Coal
Compan
;:9200
12%-14%
0.60%
;:2175
2%-3%
~8%
~6%
BJackBut
Coal
;:9000
11.50%
0.600Æi
6
7
8
9
Btu Contnt
AshSul
Ash softnig TempeaSodiCaliuIr
~4%
Jim BridgerpJa
;:9200
12%
0.60%
;:2175
~3.2%
~8%
~6%
10 As.this table ilustrates, the Plant relies on blending from all three sources of coal to
11 achieve the most effcient coal for combustion at the Plant.
12 Moreover, even in months when there is no surface production, BCC can ensure a
13 consistent coal quality by blending stockpiled coal.
14 Q.How does Black Butte coal fit into the overall blending process for the
15 Bridger plant?
16 A.Similar to BCC coal, Black Butte ships a blended coal product. Black Butte is
17 currently mining in two pits. The.two active pits, Pit 14 and Pit 11, have significantly different
18 sodium levels and heat content. The sodium content of Pit 11 is much higher and can
19 cause slagging of ash on the boiler walls. This can cause a de-rating of the Plant during
20 slag removal operations.
21 The Bridger Plant has established an approximate 3 percent sodium target. At
22 times, the Black Butte mine has had limited production capacit of low sodium content aoal.
23 During periods when high sodium Black Butte coal is delivered, low sodium BCC surface
24 coal is critical for blending. Black Bute coal is blended with BCC coal at the Bridger Plant.
25 Under the prior Black Butte coal supply agreement, in addition to tl)eir deliveries by rail,
26 Black Butte s~urced the Bridger Plant with. tons of premium low sodium, high ash
REPLY TESTIMONY OF TOM HARVEY
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1 fusion temperature coal from Pits 22, 23 and 24 (Leucite Hills Mine). This coal was
2 transported by truck and stockpiled by Black Butte at a site adjacent to the Bridger Plant.
3 Bridger Plant personnel utilzed this coal for blending on an as needed basis. These ultra-
4 low sodium reserves, however, were depleted in 2009.
5 Under the new Black Butte agreement, with the term of 2010 though 2014, the coal
6 is being sourced from the higher sodium Pit 11 and Pit 14. The current contract
7 specification allows Black Butte to ship coal with up to 4 percent sodium on a monthly basis.
8 Sodium content above 3.2 percent causes ash to slag on the boiler tubes. As a result
9 blending with lower sodium BCC coal is required to mitigate Black Butte Goal deliveries with
10 sodiumoontent above 3 percent.
11
12
Q.
A.
Have there been Issues with the quality of Black Butt coal in the past?
Yes. In 2008, mining at Black Butte was limited to two pits: Pit 8, a low
13 sodium coal, and Pit 11, a high sodium coaL. Low sodium coal production was limited as Pit
14 8 reserves were close to depletion. Due to limited Pit 8 supplies, BlaokButte's deliveries to
15 the Bridger Plant averaged in excess of 4.5 percent sodium in 2008 which necessitated
16 blending. of low sodium coal from the BCC surface mine. The. Bridger Plant owners had
17 several meetings with Black Butte in 2008 regarding the sodium content and limited supply.
18 Sodium content remained high and excess supply non-existent until Black Butte
19 subsequently opened Pit 14, in 2009. Utilzing exciusively Black Butte coal, without BCC
20 surface mine deliveries in 2008, the Bridger Plant would have sustained persistent MW de-
21 ratings due to slagging from Black Butte coaL.
22 Q.HoW does .thls blending process affct the application of the lower of
23 cost or market rule?
24 A.Mr. Dougherty proposes replacing the BCC surface operations with Black
25 Butte coaL. As demonstrated above, however, BCC surface coal (and the combined BCC
26 coal product) are necessary to the blending process and ensure that the process is
REPLY TESTIMONY OF TOM HARVEY
Idaho Power/300
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1 performed in the most cost-effective manner and performed to maximize the efficiency of the
2 Plant's operations. Thus, even if sufficient volumes were available from Black Butte,
3 replacement of BCC surface coal with Black Butte coal poses serious blending problems for
4 the Plant.
5 Mr. Dougherty's Second Alternative Analysis, which replace the surface coal with
6 underground coal, also ignores this blending process which requires both surface and
7 underground coal to create a usable final product for the Plant.
8 Q.You have explained why Black Butt coal cannot replace BCC surface
9 coal. However, aren't there other alternative sources in the Green River Basin from
10 which the Company can purchase coal to replace BCC's surface operations at 'a
11 savings to customers.
12 A.No. Aside from BCC and Black Bute, there is only one additional operating
13 coal mine in the'Green River Basin-the Kemmerer Mine. The Kemmerer Mine is dedicated
14 to supplying PacifiCorp's Naughton power plant, with the remainder going to supply
15 industrial customers in the region. There is no additional coal available from this s.ource.
16 Q.If the Company cannot obtain replacement coal from the GRB, what Is
17 the next logical alternative?
18 A.The only other viable source of coal to fuel the Plant are mines located in the
19 Powder River Basin ("PRB")-which is located approximately 566 miles from the Plant.
20 There are, however, two significant problems with using PRB coaL. The first is the effort and
21 expense involved in shipping coal from the PRB to the Bridger Plant. The estimated cost to
22 ship coal from the PRB to the Bridger Plant is around. per ton, which is double the
23 estimated. per ton cost the coal itself. In total, the per ton cost of PRB coal, including
24 transportation is likely to be at least $. per ton F.O.B. Plant without adding in additional
25 costs such as freeze protection and dust suppression. Assuming that significant volumes of
26 PRB coal could be obtained and then shipped to the Plant, use of coal from mines in the.
REPLY TESTIMONY OF TOM HARVEY
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1 PRB would require significant capital investment in the Plant because of the different quality
2 and chemical make-up of the coal compared to the GRB coal the plant currently burns.
3 These issues with the Powder River Basin make it uneconomical to consider coal from that
4 region as a possible fuel source for the Plant.
5 Q.Is there a spot market from which the Plant could acquire coal to
6 replace the BCC surface coal?
7 A.No. Because of the location of the Bridger Plant there is no spot market that
8 can serve it. Moreover, because the Plant is a baseload resource requiring a consistent and
9 reliable source of coal, prudent operation dictates that it contract for its coal to ensure a
10 stable supply.
11
12
STAFF'S RECOMMENDATIONS
Q.Based on the foregoing analysis, how does the Company respond to
13 Mr. Doughert's specific recommendations?
14 A.Mr. Dougherty's testimony includes a Primary and First Alternative Analyses
15 which he recommends and a Second and Third Alternative Analysis that he does not
16 recommend. Mr. Doughert's Primary and First Alernative Anaiyses call for the
17 replacement of the BCC surface coal with Black Butte coaL. As explained above, there are
18 significant problems with both these analyses. First, Black Butte is not an alternative market
19 available to supply coal in lieu of the surface operations. At most Black Butte coal could
20 replace approximately one-third of the BCC surface coaL. Second, the decremental cost of
21 surface coal is actually less than the replacement cost of Black Butte coaL. Third, the current
22 BCC coal costs are actually lower than the cost of replacement coal from Black Butte.
23 Fourth, obtaining coal to replace the remaining two-thirds of BCC surfce coal from the PRB
24 wil greatly increase coal costs because that coal, including transportation, is significantly
25 more expensive than BCC coaL. Fifth, reduced availabilty of BCC surface coal would make
26 blending to meet coal quality requirements impossible at times and cause de-rating of the
REPLY TESTIMONY OF TOM HARVEY
Idaho Power/300
Harveyl19
1 Plant, thus increasing the cost of generation. Thus, when the LCM rule is properly applied
2 to BCC coal costs it is evident that in fact the BCC costs, including the surface operation, '
3 are lower than the cost to replace that coal through market purchases from non-affilated
4 mines.
5 Mr. Dougherty's Second Alternative Analysis, which he does not recommend,
6 replaces the surface coal with BCC's underground coaL. This analysis is also flawed for
7 several reasons. First, BCC's underground coal is not available to replace the surface coal
8 because it lacks the necessary capacity and the surfac,e coal is an essential component of
9 the blending process required to safely and effciently operate the Bridger Plant. Second,
10 the LCM rule applies to goods transferred within a market, not to individual cost components
11 included in an affilate's overall costs. Third, if surface operations ceased, the cost of
12 underground operations would Increase because of the shared overhead expenses. Thus, if
13 surface mining ended, the costs of the underground operation would not be the amount
14 refected in this filng because that amount assumes surface operations exist.
15 Mr. Dougherty's Third Alternative Analysis, which he does not even recommend is
16 also flawed. This proposal replaces all BCC coal with Black Butte coal, including carr-over
17 tonnage. As demonstrated above, replacing BCC's . million tons ot' coal with Black
18 Butte's _tons of additional capacity is unrealistic.. Thus, Black l3utte coal is not an
19 available market for replacement coal. Moreover, removing the BCC surface coal from the
20 essential blending process would result in significant problems for the Bridger Plant.
21 The following table ilustrates the cost comparison between BCC's surface coal costs
22 and alternative sources of coal proposed by Mr. Dougherty:
23
24
25
26
REPLY TESTIMONY OF TOM HARVEY
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Harvey/20
1 Coal Source Cost Per Ton (inclu~ing transporttion)
2 BCC Surface Decremental (Apr. 2010
3 through Mar. 2011)
4 Black Bute (Staff's Primary Analysis)
5 Black Butte (Staff's First Alternative
6 Analysis)
7 Black Bute Replacement (400,000 tons)
8 PRB Coal
9
10 As is clear from this comparison, BCC surface coal is lower in cost than any
11 available coal from either Black Butte or the PRB.
12 Q.What is the difference between the Primary and First Alternative
13 Analyses?
14 A.The only difference betwen the two analyses is that the Primary method
15 includes carry over tonnage from the previous Black Butte contract. Inclusion of the price
16 for carry over tons is inappropriate because Mr. Dougherty is attempting to define a market
17 rate-the cost at which the Company could go into the marketplace and actually purchase
18 coal in lieu of purchasing coal from its affliate. Carr-over tonnage-coal provided at a
19 lower cost because it should have been delivered in a previous year with a lower cost-does
20 not factor into a proper market analysis. If the Company were negotiating to purchase coal
21 to replace the BCC surface coal it could not expect that other suppliers would give it the
22 same price that Black Butte gave it in past years. Benefits from this carry-over tonnage are
23 already included in the case and therefore customers wil receive the benefit of the carr-
24 over tonnage even without his adjustment.
25
26
Q.
A.
Does this conclude your direct testimony in this case?
Yes, it does.
REPLY TESTIMONY OF TOM HARVEY
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-E-10-01
IDAHO POWER COMPANY
ATTACHMENT NO.4
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