HomeMy WebLinkAbout20060713IPC to ICIP 19, 7, 10, 13.pdfIDAHO POWER COMPANY
O, BOX 70
BOISE, IDAHO 83707
RECE\VED
200& JUL \, PM 4: 5 \
IDAHO PUBLIC
UT\LlTIES COMMISSION
.~-~
An IDACORP Company
July 11 , 2006
Jean D. Jewell, Secretary
Idaho Public Utilities Commission
472 West Washington Street
P. O. Box 83720
Boise, Idaho 83720-0074
Re:Case No. IPC-06-
Idaho Power Company s Response to the First Production
Request of the Industrial Customers of Idaho Power
Dear Ms. Jewell:
Please find enclosed for filing an original and two (2) copies of Idaho Power
Company s Response to the First Production Request of the Industrial Customers of Idaho
Power regarding the above-described case.
I would appreciate it if you would return a stamped copy of this transmittal letter
to me in the enclosed self-addressed stamped envelope.
Very truly yours
~~ (p.
Monica B. Moen
MBM:sh
Enclosures
Telephone (208) 388-2692 Fax (208) 388-6936, E-mail MMoen(g)idahopower.com
REQUEST FOR PRODUCTION NO. 19: What is the retail rate impact of
Mr. Said's request at page 20 for the Commission to approve inclusion of the total project
investment in the Company s rate base for ratemaking purposes? Assume for purposes of
answering this question that the total project investment includes 60 million dollars for the
generating plant and 22.8 million dollars for associated transmission and substation
improvements. Please provide supporting work papers.
RESPONSE TO REQUEST NO. 19: There is no current retail rate impact
associated with the Company s application for a Certificate of Convenience and
Necessity. The actual incremental revenue requirement to be requested by the
Company will depend upon circumstances that exist at the time of an application for
recognition of the Evander Andrews project in the Company s rate base , revenue
requirement and rates. The earliest a future retail rate impact would occur would
probably be in 2008 once the Evander Andrews power plant is in service.
application to change the Company s rates in 2008 to reflect the Evander Andrews
power plant could either be a part of a general rate case or a single issue rate case as
was the case for inclusion of the Bennett Mountain power plant costs.
In that case , the Company identified $50.3 million of power plant costs and
$7.7 million of transmission and interconnection facilities costs for a total of $58.0 million
in total project costs. The Company quantified the associated incremental revenue
requirement associated with the Bennett Mountain project at $13.5 million. This
quantification included expenses such as property taxes, property insurance and
depreciation expenses , but excluded expenses such as operating and maintenance
expenses. Power supply expense impacts were likewise not included , but were
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 21
ultimately captured in PCA computations. The Company has not quantified the
incremental revenue requirement associated with the Evander Andrews project.
However, assuming the ratio of incremental revenue requirement to total project costs
($13.5 million / $58 million = 23.3 percent) from the Bennett Mountain application might
be similar in an Evander Andrews application , an estimated incremental revenue
requirement for an $82.8 million project would be $19.3 million.
The response to this request was prepared by Gregory W. Said , Manager
of Revenue Requirement, Idaho Power Company, in consultation with Barton L. Kline
Senior Attorney, Idaho Power Company.
DATED at Boise , Idaho, this 11 th day of July 2006.
(ft-
MONICA B. MOEN
Attorney for Idaho Power Company
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 22
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 11th day of July, 2006, I served a true and correct
copy of the within and foregoing IDAHO POWER COMPANY'S RESPONSE TO FIRST
PRODUCTION REQUEST OF INDUSTRIAL CUSTOMERS OF IDAHO POWER upon
the following named parties by the method indicated below, and addressed to the following:
Commission Staff Hand Delivered
Donovan Walker US. Mail
Deputy Attorney General Overnight Mail
Idaho Public Utilities Commission FAX
472 W. Washington (83702)----.ll Email Donovan.walker(g)puc.idaho.gov
O. Box 83720
Boise, Idaho 83720-0074
Industrial Customers of Idaho Power Hand Delivered
Peter 1. Richardson, Esq.US. Mail
Richardson & O'Leary Overnight Mail
515 N. 27th Street FAX
O. Box 7218 ..x Email peter(g)richardsonandoleary.com
Boise, Idaho 83702
Don Reading Hand Delivered
Ben Johnson Associates US. Mail
6070 Hill Road Overnight Mail
Boise, Idaho 83702 FAX
..x Email dreading(g)mindspring.com
Mountain View Power, Inc.Hand Delivered
Ronald L. Williams US. Mail
Williams Bradbury, P.Overnight Mail
O. Box 2128 FAX
Boise, Idaho 83701 ---X Email ron
(g)
willi amsbradbur com
Robert D. Looper, President Hand Delivered
Mountain View Power, Inc.-1L US. Mail
1015 W. Hays Street Overnight Mail
Boise, Idaho 83702 FAX
Email rlooper(g) spellc.com
~(b.
Monica B. Moen
CERTIFICATE OF SERVICE , Page
IDAHO POWER COMPANY
CASE NO. IPC-O6-
FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS
RESPONSE TO
REQUEST NO.
DRAFT
Joint BP A and Northwest Gas Association Study of Pipes and Wires
Executive Summary
Both pipelines and electric grid exp
mile of each alternative-natura
transmission per unit of ener
pipeline would be more
associated benefits, an
case- and site-specific
fpipes and wires ell as how
ho finances the project? 2)
Bonneville Power Administration (BPA) and the Northwest Gas Association (NGA) agreed to stud
economics of delivering energy to load centers via electrical transmission lines versus natural
One objective was to determine which is more economically efficient. A second objective
determine whether the Federal Energy Regulatory Commission s (FERC) pricing rules
outcomes that do not comport with economic efficiency; in other words, whether FE
tilt the playing field toward a less than optimal economic outcome.
The Work Group compared the economic costs, reliability, delivery effic
factors associated with energy delivery to a generator located near a I
pipeline versus from an electric generator located near a gas pipeli
a 100-mile electrical transmission line.
A key finding was that making valid comparisons be
physics of the two systems. Natural gas pipelines
localized effects as a result of capacity expansions
interconnected and redundant.
etween the two systems and to
ost-recovery for capacity
as pipelines and electric power
ies is t fthe benefits accrue solely to one party, that
, in addition to whatever other costs it must pay to
probably for most cases, a natural gas pipeline
party than an expansion ofthe electric grid. So, the
; one is incremental, the other is rolled in. However, if the
eneration interconnection the two cases would be identical; the
ts in either case.
cons in pricing principles is one thing; assuming that the merchant transmissionnatu s pipeline industry will transfer to the electric industry is quite another. Our
bt on e prospects ofFERC's vision of merchant electric transmission springing up to
k congestion coming to fruition in the Pacific Northwest.
onclude that, the benefits and costs of both systems may vary widely depending on site-
lrcumstances. Both systems now are planned and developed separately. We recommend that
ver possible, energy planning and development should incorporate both electrical and natural gas
s stems to optimize an integrated system, thereby providing the greatest benefits for society.
2/26/2004
Joint BPA and Northwest Gas Association Study of Pipes and Wires
Methodology
pipeline and use electrical
the distribution system.) This is
ration of Pipes vs. Wires
Bonneville Power Administration (BPA) and the Northwest Gas Association (NG
agreed to study the economics of delivering energy to load centers via electric
transmission lines versus natural gas pipelines. One objective was to dete
more economically efficient. A second objective was to determine wh
Energy Regulatory Commission s (FERC) pricing rules could crea
not comport with economic efficiency; in other words, whether
tilt the playing field toward a less than optimal economic ou
Specifically, the Work Group compared the economic
efficiency (energy losses), and other factors associated
generator located near a load center via a 100- ile na
generator located near a gas pipeline deliv electri
100-mile electric transmission line.
Staff from BPA's Transmission Busines
belong to the NGA began t dy in
participants.) This pape s the
ical generation is located adjacent to the load
es gas from a main interstate pipeline to the
lcted in the bottom portion of Figure
an , we assumed that the distance to be covered in either scenarioile at is, we compared a pipeline to an electric transmission line, each
e further assumed that the amount of power output from the generator
0 MW. Work Group expertise was tapped to determine that: 1) a 20-inch
se nearly all costs are determined on a per-mile basis, this is not a critical assumption. There are no
omies of scale for distance; i., costs are directly proportional to distance of the line.
2/26/2004
Figure 1
Illustration of Pipes
vs. Wires Comparison
New 1500 MW
Generator Existing Transmission System
f/).
;1( ~r500 kV
lines
Existing 1500 MW
Load
f/).
::::s
New 1500
MW Load
:;;
,t'
-- -- - - --- -- --- ------- ---- ---
New 1500 MW
Generator
2/26/2004
diameter pipe would be the optimal size of a pipe capable of delivering sufficient
(250 million cubic feet of gas per day.2 (mmcf/d)) to the plant; and 2) a 500 k
would be sufficient to deliver the output of the 1500 MW plant to the load.
ibleFor analyzing costs, we considered varied terrain and ownership.
to ensure that exactly the same assumptions are used by BP A
and NGA companies for gas pipelines, we believe that the f:
to afford reasonable comparisons for purposes of this s
Pipeline estimates may not reflect the cost of all water
terrain being traversed. Significant water cro . ngs
pipeline somewhat but have little bearing st elec
additional water crossings could add a fe n doll
alternative, which is a small percentage i
s s is that losses are ignored. We
e 100 mile 500 kV line. However
ignored. Natural gas pipelines also use fuel for
equate pressure in the pipeline. This use is
similar magnitude. Therefore the two effects
on 'peli es are capital intensive. To test sensitivity, capital costser rs using various interest rates ranging from 7.0 percent to 12.0 P nt rate corresponds approximately to BPA's Treasury borrowing
0 percent rate corresponds closely to the average cost of capital in the
r for these projects. Similarly, it is a rate close to what BP A has been quoted
mers who have expressed an interest in project financing. Because the
2 This assumes a plant heat rate of approximately 7 000 Btu/kWh.
3 As will be shown below, not only are the projects inherently not substitutable (meaning that an either/or
comparison is a false one), the way the costs typically are recovered for pipelines differs from the way
transmission costs are recovered.
2/26/2004
Because these projects are
than those costs to dete
mile of electrical tr
unit costs of elec
, the
pipeline companies who participated in this study have an average weighted cost
capital of 8.75 percent, results are shown for that, as well.
The costs are shown in Table 1 , Cost Comparison. The transmission
the left, the pipeline costs on the right. The top three rows show
capital costs per mile, capital costs per 100 miles, and the ann
maintenance (O&M) costs (or their equivalent.) The box
payment required to payoff the capital investment, bot
percent cost of capital. Next, the annual costs are com
annual capital payment and the annual O&M c sts.
various units and displayed below. Specifi , value
and per MWh under various load factors. curre
for illustrative purposes.
ct into servic typically 24
d compression additions as
his period allows for pre-
gineering and preparation of
process including final
iOn equipment and physicalud e required to get commercialtructi f the pipeline, otherwise known as the
cess can be as short as two weeks.
lines, we assume that planning, which would
would nonnally take a year. Environmental work
, but would more likely take up to two years. Finally,
would take an additional two years.
observations in light of the foregoing come to mind. First, this hypothetical
smission project is cheaper than current rates. In other words , the dollar per kW-year
4 The costs shown here are economic costs for the purpose of comparing the amount of resources required
to develop each alternative. It is not a rate analysis. That means that meaningful comparisons can be
drawn among the alternatives concerning the overall cost that society would pay to develop either pipes or
wires. However, a quite different analysis would be required to compute actual rates. As such, using these
figures as proxies for rates or tolls would be misleading. Although BP A's transmission rate is shown for
illustrative purposes, and although the costs shown would roughly approximate rate effects, the two are not
strictly comparable.
2/26/2004
Finally, if it were true that one could simp
everything else the same it is clear that pi
$100 000,000
$6,056,640,51B569,
000000 000 000 000000
056,640 $10516590 $13,414,366
$6,$7,$6,
$12,$12,$12,
$0.$0,$1.
$1.$1,$1.
cost of this project is less than what BPA currently charges customers for point-to-
transmission service. Thus, the project would meet the "or test"S and would be r
into rates.
Second, when expressed on an energy basis, this shows how economic
can be. Using a 65% load factor, which approximates the typical
the fully allocated transmission costs are less than $2 per M
line were to reduce re-dispatch costs (or other congestion a
of more than $2/MWh, the line would pay for itself, at I
(However, the incidence of specific customers' costs co
dispatch compared to new transmission capacity.
st ("Annual Payment, 30 years ) and "Total Costs per year" is
ow natural gas pipelines or their customers would view the cost of
mers through a transportation rate spanning the life of a facilities, annual
on rate are more representative measures of the customer s obligations,
issi n lines are a means of transporting energy, sometimes over
oth transport two of the significant energy resources in our
s are partially substitutable; either can be used to heat water or
But the differences are significant as well.
robably most importantly, the physics of the systems differ. In an electrical
very thing is integrated-it is one large machine. Any disturbance, anywhere on
stem, is "felt" everywhere else on the system, virtually instantaneously. Because of
, the system is planned and built on an integrated basis.
5 The "or test" is discussed below.
2/26/2004
One planning criterion unique to electrical systems is known as the N-1 criterion.
this criterion, the system (including new system additions or capacity expansi
planned such that if the worst possible contingency occurs, the system wil
deliver power to load. In other words, if the worst possible thing happ
in the case at hand, the new line fails--the system can still meet
exists in the natural gas pipeline system.
The natural gas delivery system also is planned on an i
account what is there already, and recognizes options fI
system is arterial. It resembles, at least in so respect
flows from large pipelines to ever-smalle eventu
the network ( cal) are
rt shows the si ation for an
load via two 500 kV
, it has two 500 kV lines
s down, the load can still be
. n this example is 3000
W. Adding a third 500 kV
able capacity to 3000 MW.
ation differs. The bottom part of the figure
(in this case represented by 250 mmcf/d of gasIe ith an additional 250-mmcf/d load, one newto e expanded loads. In this case, if either pipeline shuts
loa can be met, except to the extent storage is available at the
ical system is planned for single and credible double line outages (these are a
e event that could take out two facilities). Lines typically experience 1.75 outages
er year. They are involved in overlapping outages with another line 0.01 times per year.
6 A more commonly used tenn in the natural gas industry is LDC, which stands for Local Distribution
Company. Generically speaking, however, both gas and electric companies serye loads and therefore may
be tenned Load Serying Entities.
7 This is a simplified view from both the electric and gas point of view. It is used only for illustrative
purposes for the points in the text.
2/26/2004
A single gas pipeline experiences 0.03 outages per year, which is comparable to the
for double transmission line outages. Although pipelines experience fewer outa
transmission lines, the outages are often more catastrophic and the duration
outages is typically much longer. Single line outages typically last 220
double line outages last 108 minutes. Although specific data on pipe
available, they are expected to last several days to weeks. This ti
the storage availability. Therefore, the overall reliability/avail
arguably is lower than the transmission system. (These stat'
Statistics " Office of Pipeline Safety (US. Department of!
Special Programs Administration). http://ops.dotgov/sta
If risks of line failures were equal, the electric
as compared to the gas arteriaL However
compared and, in both cases, are miniscule
failure are situation-specific and depend 0
study.
the past, what we are
er) appears to be heading
y, they are 1) Financing-
Funding - Who actually
current ratepayers? 4) What
ssues are described in the following
em based on forecasts of load and resources. BP A, un ook the transmission investments it determined were
ith a high degree of probability. Some transmission
uded in the network's costs. These included, for example, the
ery facilities. So
, "
network" refers to the high voltage grid in the
less of where on the network an investment was made it was financed by
ed into rates charged to all network customers. Because the network is
ted, upgrades help to provide backup transmission and to maintain voltage
ut the system, so that all customers benefit from maintaining reliability. Since
stomers benefit, all customers pay. FERC historically has been supportive of this
d of pricing for all electric utilities.
2/26/2004
Today s world is different. Now there are a variety of customers-generators, LSEs
marketers who buy and sell power and move it across the network. Under the Ope
Access Transmission Tariff (OA TT) customers generally fall into two categori
Network customers (served under the Network (or NT) rate) and Point-to-
customers (served under the PTP rate.) All customers pay for usage of
depending either on their load (NT) or their reserved capacity (PTP
BP A continues to make investments on behalf of its treaty
including the expected load growth of its NT customers.
consideration. In the simplest terms, reliability projects
improve (or avoid degradations in) reliability. lternati
according to a variety of factors, including c 0 dete
returns the greatest economic benefit in a the r
mer has the option of
the cost of capacity
finance the costs of the
n behalf of its other
needed only to meet specific
era!. Because the investment
stomer, that customer must come
ERC's so called "or test." According to that
ge its customer under these circumstances either theme ost, but not both. The "but for test" is about who
e "or test" is about how much they pay.
ts fi ial investment, the customer receives a credit on its transmission
credit is sufficient to repay the customer for its financial investment because
ould be applied according to prevailing transmission costs. In other words
g transmission rates are credited to the customer s account to repay its financial
ment. In the case at hand, for example, the customer would invest $186 million
us interest) to finance the new 10O-mile capacity addition. At current rates of
8 Or, more precisely, who takes the risk.
2/26/2004
$12. 16/kW-year, the customer s bill would be credited with that price times the amo nt
of transmission acquired until such time as the principal and interest were repaid
F or the other network c
principal), had BP A
would be the diffe
project than the U
then be re aid, wi
enew
the $186
ts books
repays
gainst
s paymg
To the customer the investment becomes a sunk cost and transmission is
as long as it takes to repay the investment. Thus , there is a tangible ec
the customer for its investment. As we will see, this is similar to h
financed and funded.
Note that while the customer takes the risk by financing
project. The distinction is important and, as we will se
world envisioned by FERC. Let's say the Hoozit Gen
million project that is the subject of this repo 9 BPA
including interest charges, and adjusts its
the investment (and investor, Hoozit) by
Hoozit's transmission usage. Once the i
for subsequent transmission usage.
generation (or load)
recover costs and all
re ratepayers on the
e if the "OR" test
ew service exceeded the
e incremental cost exceeded the
ew customer.rnl future direction. How does Hoozit benefit byall eive any money for its investment, just a creditill. y a tangible economic benefit? The answer is yesf e eneurial decision-making. It is instructive to compare
ther ellers. Some other sellers may have purchased long-term
ission out of existing capacity. Like Hoozit, these sellers
ission costs as "sunk " because they are required to pay for the
egar ess of whether they use it. Other sellers may connect to the system
transmission rights and take the risk of using non-firm transmission as
n average, at today s rates
, "
free" transmission means that Hoozit has about
advantage over these other sellers who to pay for transmission as they use it.
sellers would then avoid the $186 million investment, but would have to pay about
/MWh for transmission, when transmission is available and it is economic for the
9 Assume the "or test" does not trigger. That is the usual case.
2/26/2004
Predicting where FE
, but the general
FERC Standard M
related ac ' . ties, b
not up
fthe
est of the
sellers to run their generators. If transmission were not available at any time, the se
that depend on nonfinn transmission could not sell the power from their generat
Note that whether Hoozit sees the transmission investment as a sunk cos
when the decision is made. Prior to undertaking the project financin ,
question Hoozit faces is whether paying up front for the new tran
worth it compared to facing the congestion costs and risks it
expansion not made. At that point, there is no sunk cost.
undertakes the financial investment, it owns transmissio
Moreover, on the path in question, because Hoozit has
congestion costs, while any other party withou Inn rig
in time, the transmission appears to be free gener
initial investment (financing the 1500 M 'ty exp
transmission service clearly was not free.
ork. FERC proposes that
etwork. (By this, they
on rates.) Generatorsit s-LSEs, generators, and
costs, primarily redispatch costsan edge congestion cost risk by the acquisition ofts , in the case ofRTO West, CatalogueRs) can be acquired through existing rights, by auction
, or by funding the investment in transmission capacity
nding is envisioned by FERC to be the key to developingex ns. This is more than participant financing, as is possible in. Th ustomer pays for the project and receives in return an amount of
e period. Regardless of how a customer acquires its CRRs, their value is as
mst congestion costs.
, Hoozit gets a financial credit worth about $2/MWh over the life of its contract.
morrow, Hoozit gets CRRs as a hedge against congestion costs. Economically, there
10 Other costs such as those equivalent to today s Transmission Scheduling charges applicable to all
schedules may apply, but are not relevant to this analysis.
2/26/2004
That's not all. Once Hooz
increased and congesti
nodes) may increas
one location to red
congestion costs of
WInners osers.
on the
rofit from funding the
zit waits, someone else may
n the latter case, it wouldn'
may be reduced as a result of lower
shouldn t be much difference, at least in principle. Both represent advance purchases
transmission services. In fact, differences may and probably will arise.
One obvious difference is that today Hoozit knows that other similarly situ
will incur essentially the same level of transmission costs, either as up fr
new construction with credits, take or pay transmission payments fo
transmission out of existing capacity, or pay as you go transmissi
term firm and nonfirm transmission. Tomorrow, Hoozit will
investing a known amount for a network expansion and re
facing an uncertain amount of congestion costs in the fu
congestion costs it faces when it makes its investment, b
congestion costs it faces subsequently. In addif , its in
transmission capacity) will have its own eft! other
some predictable, some not. On top of tha capaci
generation) will further change the various ion co
the value of the CRRs, as compared to cre ay
oday s system, for the same reasons.
ozit would have a clear $2/MWh advantage over
d be greater under the SMD proposal, or less; but it
of aying for the rolled in costs of the transmission system is thatt pa r the embedded costs of transmission. There is really no such
r test." If the generator determines that the avoided congestion costs are
finance and fund the capacity expansion, regardless of how that cost
average embedded costs.
y, FERC contemplates that regional state advisory boards would inform
nsmission providers when new generation capacity is required to meet resource
2/26/2004
adequacy standards as loads grow. This would be similar to today s network planni
reliability. These costs would be rolled into the transmission provider s compan
and passed along to all LSEs. This is viewed by FERC as a backstop. It beli
avoiding congestion costs will provide sufficient economic incentives to
participants to fund transmission capacity expansion.
For the case at hand
is for the transport
of the new 20" pip
pays for the embearteria
for
Natural Gas Pi eline Fundin and Pricin
FERC defines three types of pipeline projects: an expa
(such as the case that is the basis for this report), a proj
customers (analogous to transmission upgrades for reli
two. The Commission s policy is that no sub' ies sh
benefit must fund expansions for addition ice. I
cannot be demonstrated, existing custom 0 be h
Expansion shippers must be willing to p
of the project. (See Appendix 2, Curren
for more detail.)
al service
existing
n of the
ewho
sts)
SlOn.
11 costs
ipelines
r who pays the average, or
customers benefit from the
enerator pays only the embedded
ower transmission pricing construct for new
customers is that the shipper does not necessarily
does have to fund the project. If the pipelinere tract tenns, the pipeline owner, perhaps using a variety
shi ers, undertakes the financing and funding for the project.ne aid by the rates that are charged to the shipper(s.) No shippers
e s will pay any of the costs of the capacity addition. It will beby e shipper. This corresponds to financing, funding and paying for
ities on the electric grid, but not to the hypothetical network expansion
where.
11 If, however, the pipeline expansion can be achieved by looping an existing line and the toll is less than
the existing toll, the costs are rolled into existing rates. This would be similar to expansions ofthe electric
grid for reliability purposes.
2/26/2004
nes and electric power
tab1ish clear and
As stated previously, there is no perfect analogy or substitutability between a pipeline
a transmission line. The closest thing to an electric network would be the main t
the pipeline system. All gas must pass through these arterials. Branching pipe
however, have a clearly defined physical point of delivery and mayor may
interconnect with other pipelines.
Expansion shippers mayor may not increase the capacity of an e .
analogous to expanding electrical network capacity. Generall
would be at least some benefit to existing customers. Ther
expanded service mayor may not have to pay an increme
case that most closely resembles the hypothetical case at i
Although this pipeline-pricing concept differs
transmission capacity expansions, it appear
under FERC's SMD NOPR. Shippers who
pipeline rate, regardless. It is a sunk cost i
equivalent to saying there is zero cost for
would face zero cost transmi nder th
alleviate the costs of con ey in
expansion, just as as 0 inc
alleviate "congestio cost
where from 40% to 50% less
of energy via electrical
vanta of pipelines increases directly as
distances-and 100 miles is reasonably
lly efficient.ies be consistent across both pipelines and electric
In ases, existing consumers are protected against the
pan ns. If they benefit from the expansion they will pay
costs; if they don t benefit, they will pay nothing additional.
clear that merchant electrical transmission will be forthcoming
env ons.
c and gas transmission systems are planned independently. Planning the
y system in a more integrated fashion could bring additional benefits to
nsumers. Generally, it will be cheaper to transport gas to load centers, but there
2/26/2004
Consistent with our findings, we do see plants
and building pipe, but fewer cases of locatin
transmission; for example, the Gray s Har
pipeline spur was built from the I-5 corrid
sometimes dominate decisions about plant
effect is. As it was beyond the ope of t
which to rely.
are many circumstances in which electrical transmission upgrades would be
economIC.
Recommendations and Next Steps
As the region s energy needs continue to grow and change, consume
integrated planning and development of the energy delivery syst
pipelines will be cheaper than electric transmission lines, esp
but as we found, there are numerous instances where elec
even the only alternative.
ocess to identify
tnering of electric
prospective generators. The
I time and for system planners.
er one, but in both systems working inng natural gas pipelines and for electricnd be consistent. However, while merchantnd developed in the pipeline industry, it is not in the
stry. It remains to be seen whether FERC's vision of network
ted largely by merchant transmission will be fulfilled.
ed at FERC's decisions and how utilities are required to finance and fund
nsions. We did not, however, examine actual cases of merchant
n. On the electrical side, in the Pacific Northwest, there are practically none.
notable exception is the transmission required for generation interconnection
looks very much like merchant pipeline additions. However, that is far removed
m merchant transmission on the electric grid, an unproven concept in the region.
2/26/2004
As we noted, it is often the case that the direct beneficiaries of a pipeline addition ca
identified. Because they have a property right with a clear economic value, fina
requires rates of return somewhere in the 8 to 12 percent range, depending 0
equity costs. In other words, it is a fairly low risk transaction.
Such is not the case for merchant electric transmission. Recall tha
transmission in the future goes beyond financing the investme
credits on one s bill. In the future, merchant electric trans
fund the investment and receive Congestion Revenue Ri
transmission owner thereby acquires a property right, w
unknown economic value. It is easy to imagine that the
would be much higher than we observe with line ow
willing to undertake such investments in t
Although R TO West, the proposed regio
Northwest, will have backstops to ensure
when or even whether R T will ac
owners will always be C' s jur
merchant transmiss
We recommendfu
about the charact
ordi
uld be useful t
ose that create
ne model to th
c Northwest, gas pipelines
gy. However, we did not
ver such a distance, the
i s become more economic than
ions a uired as are with Alternating
lower. ffsetting that, a converter station is
n fact, their cost prevents DC lines from being
ot Ii the regional transmission grid, TransCanada
g t ssibility of building a DC line from Northern Alberta to
While that project is not to transmit electric power generated byces it is not far-fetched to imagine another Canadian entity proposingrectI the gas field and transmitting electric power via DC lines to the
est, or even California. Whether it would be economic to do so is unknown.
mend that the same regional body consider long distance energy transport in
y and to report on its findings. We also caution readers of this report to limit our
mgs to the Pacific Northwest region.
2/26/2004
Supporting Members ofNGA
Appendix 1
Participants in BP AlNGA Study
Bonneville Power Administration
Northwest Gas Association (NGA)
A vistacorp
Duke Ener
Kevin Christie
Jan Caldwell
2/26/2004
Appendix 2
Current FERC Expansion Rate Policy for Gas Pipelines
In the Policy Statement, the Commission defined three
projects: an expansion project to provide additional se
to existing customers by replacing existing fa . ities, i
additional flexibility; and a project that co s an e
improvements for existing customers. U Com
existing shippers should not have the rat their
the pipeline has built an expansion to pr ice t
customers ' rates can be inc for pr imp
project combines an ex 'th im to increase existing line
facilities are need
-Ill
The Commission s September 15 , 1999 Policy Statement12 on proposed gas pr .
established a no-subsidy policy favoring incremental pricing of pipeline ex
thereby changing the Commission s previous policy of giving a presum
rate treatment for pipeline expansions. The Commission found that r
sends the wrong price signals by masking the true cost of capaci
shippers seeking the additional capacity.
et finds an ex IOn project
urchase capacIty at a rate
xi sting shippers through
the subsidy is necessary to
er the pipeline or its
ddition, the no-subsidy
s 0 not receive unfair advantage in
ntrant pipelines.
hat is made possible because of earlier, costly
disadvantaged because incremental pricing
Iving a subsidy from existing customers becauseno the full cost of the construction that makes their new
mm sion indicated that the issue of the rate treatment for suchili e that always should be resolved in advance, before thethe ine. Typically, pipelines file to apply current system rates for the
agr e to address rate issues in the pipelines next rate case.
12 Citing Certification of New Interstate Natural Gas Pipeline Facilities (Policy Statement), 88 FERC ~
227 (1999), clarification, 90 FERC ~ 61 128 (2000), further clarification, 92 FERC ~ 61 096 (2000).
2/26/2004
IDAHO POWER COMPANY
CASE NO. IPC-O6-
FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS
RESPONSE TO
REQUEST NO.1 0
Customer Relations & Research
DSM Programs
January 2004
r---Energy Efficiency
Leader
Program Specialist -
Residential
Program Specialist -
Residential
Customer Relations & Research
DSM Programs
January 1 2005
Energy Efficiency Department
Leader I---Assistant
Economic Analyst
Program Specialist -
Industrial
Program Specialist -
Commercial
Program Specialist -
Special Needs
Program Specialist -
Residential
Program Specialist -
Residential
L - -
-- -- - -- - --------- ----
Market Segment
Coordinator -
Irrigation
Customer Relations & Research
DSM Programs
January 2006
Energy Efficiency
Leader
Department
Assistant
Economic Analyst
Program Specialist -
Industrial
Program Specialist -
Commercial
Program Specialist -
Special Needs
Program Specialist -
Residential
Program Specialist -
Residential
Program Specialist -
Irrigation
L______-- -- -- - -- - -
--- ----
Market Segment
Coordinator -
Irrigation
Customer Relations & Research
DSM Programs
Brief Job Descriptions
Energy Efficiency Leader: The Leader position is responsible for supervising all aspects of
development, implementation , and management of the Company s demand-side management
programs, including regulatory reporting and regional representation of the Company in energy efficient
associations.
Program Specialist-Residential: Responsible for energy efficiency and/or demand response
programs for residential customers including program design, process development, system
integration, marketing and communications, contract management, and daily operations.
Program Specialist-Industrial: Responsible for energy efficiency and/or demand response programs
for industrial customers including program design, process development, system integration , marketing
and communications , contract management, and daily operations.
Program Specialist-Commercial: Responsible for energy efficiency and/or demand response
programs for Commercial customers including program design , process development, system
integration , marketing and communications, contract management, and daily operations.
Program Specialist-Special Needs: Responsible for energy efficiency and/or demand response
programs for customers with special needs including program design , process development, system
integration , marketing and communications, contract management, and daily operations.
Market Segment Coordinator -Irrigation: Responsible for representing irrigation customers
interests in programs and other Company activities. Responsible for energy efficiency and/or demand
response programs for irrigation customers including program design , process development, system
integration , marketing and communications, contract management, and daily operations.
Economic Analyst: Responsible for demand-side management analysis , financial , statistical, and
economic analyses to determine company, customer, and societal impact of DSM programs.
Department Assistant: Responsible for administrative support for the energy efficiency and demand-
side management staff.
ID AH POWER CO MP ANY
CASE NO. IPC-O6-
FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS
RESPONSE TO
REQUEST NO.
Response to Request No.
The information requested is CONFIDENTIAL and
is not provided to Mountain View Power