20030408NW Energy Comments.pdf

RECEIVED
FILED
2003 APR -8 PH~: 22BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
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IN THE MATTER OF THlETPtILmGB\tMH,SSIOH
PACIFICORP DBA UTAH POWER & CASE NO. PAC-03-
LIGHT COMPANY OF ITS 2003
ELECTRIC INTEGRATED RESOURCEPLAN (IRP). COMMENTS OF NW ENERGY
COALITION and ADVOCATES
FOR THE WEST
NW Energy Coalition 1 and Advocates for the West request that the Commission
consider these comments on PacifiCorp s 2003 Integrated Resource Plan ("IRP"
In general, the IRP reflects a thorough analysis of possible resource acquisition
scenarios, including demand-side management ("DSM") and renewables. Moreover, we
support the Company s effort to evaluate environmental aspects of resource acquisition
including likely future regulation of carbon emissions. This type of comprehensive
analysis should be viewed as a model for other regulated utilities in Idaho. Indeed, the
PacifiCorp IRP stands in stark contrast to Idaho Power s 2002 IRP, which included
essentially no analysis ofDSM or renewable resource acquisition opportunities, nor risks
associated with future regulation of carbon.
We believe the Commission should acknowledge the IRP, subject to the following
comments.
Analysis of Renewable Resources
PacifiCorp s analysis showed that a fairly large amount of wind resources, 1400
MWs, proved to be cost-effective when integrated into the company s system. This was
true even under the extremely conservative assumptions (e.
g.
very low green tag value
I NW Energy Coalition may provide written comments in other jurisdictions served by PacifiCorp, which
comments may be tailored for those jurisdictions and/or reflect additional analysis by the Coalition.
COMMENTS OF NWEC AND ADVOCATES FOR THE WEST --
going forward, and no capacity value assigned to wind) used to model the costs and
benefits of wind power.
When the renewab1es were taken out of this portfolio in a "stress test " for
example, costs and risks went up, demonstrating that renewables were responsible for
making this option less expensive than all fossil fueled alternatives. Most remarkable
was that this result held even when no penalty for CO2 emissions was modeled, reflecting
that this amount of wind was cheaper than fossil-fueled power above and beyond any
benefits accrued from lack of emissions.
The Company s "Renewables" portfolio was tested, but apparently rejected as too
expensive. The "Diversified I" and the Renewables portfolios have the same 1400 MW
of wind, but only the Renewab1es portfolio has another 1146 MW s of wind and 100 MW
of geothermal. These additional renewables are modeled somewhat differently than the
first 1400 MW. This Renewables portfolio, which in the first draft IRP came out as the
least risky and least costly portfolio is now rated as more risky and higher cost than the
chosen portfolio by 3., or $450 million over 20 years.
We question why that analysis changed between the IRP drafts. We believe the
explanation is that PacifiCorp made several errors which undervalued renewab1es. If
corrected, we believe the Renewables portfolio would again rise to the top as the lowest
cost and lowest risk choice.
The IRP underestimates the value of green tags . PacifiCorp assumes a
value of only 5 mills/kwh for just the first five years of a project's generating life and zero
after that. Green tags are selling for as much as 9 mills right now, in a range of between
4 to 9 mills. Moreover, there is no justification that green tag value will end after five
COMMENTS OF NWEC AND ADVOCATES FOR THE WEST -- 2
years. Incorporating a longer time period and/or a higher value, would add at least $150
million to the value of the Renewable portfolio compared to the Diversified I portfo1io.
PacifiCorp gives no capacity value to wind resources. The Company
argues the Renewab1es portfolio should include substantial extra costs to deliver shaped
power to PacifiCorp s system.3 While it is beyond dispute that even geographically
diverse windmills occasionally will not operate, the correct capacity value for wind is not
zero, given an average capacity factor of 32-36%.
Several papers have analyzed the proper capacity credit for wind, none of which
conclude that the figure should be zero. See Milligan, M. Modeling Utility-Scale Wind
Power Plants Part 2: Capacity Credit (http://www.nrel.gov/docs/fy020sti/29701.pdfj
(June 2000) NREL/TP-500-27514. National Renewable Energy Laboratory. Nabe, C.
Capacity Credits for Wind Energy in Deregulated Electricity Markets Limitations and
Extensions. Technische Universitat Berlin. (http://www.energiewirtschaft.tu-
berlin.de/mitarbeiter/wind21-paper-V7-5-nabe.pdfj; Giebel, G. "Previous works on the
Capacity Credit of Wind Energy,
(http://www.drgiebel.delWindPowerCapacityCreditLit.htmJ (concluding: "Wind energy
has a capacity credit. . . .The capacity credit tends to decrease from approximately the
load factor for small penetrations to some 10-15% at high penetrations.
2 1146 MWs of wind + 100 MWs of geothermal is about 500 aMWs of energy, or about 4.4 billion kwh/yr.
At $.005/kwh, that produces about $22 million/year. The renewables are developed over a number of
years, and one must discount the later years' contribution. We conservatively estimated the added green tag
value of allowing more than 5-years of credit, therefore, at about $150 million, but one could argue it
should be as much as $300 million.3 The first 1400 MWs of wind are modeled differently. However, because that amount is in all the
portfolios, only the affect of the second block of renewables is of importance to the ranking of the
portfolios.
COMMENTS OF NWEC AND ADVOCATES FOR THE WEST -- 3
In Colorado, Xcel Energy performed a loss of load probability analysis for the
proposed 162 MW Lamar Wind Project in Southeastern Colorado, which assigned a
capacity value of 48 MW or 29.6% to the project for bid evaluation purposes.
At the relatively small penetration of wind resources to the grid, a capacity factor
of closer to 30% could be appropriate. But using only a conservative 15% capacity factor
would add about $100 million in value to the renewable portfolio compared to the others.
PacifiCorp undervalues the ability of renew abies to mitigate fuel volatility.
PacifiCorp s analysis shows that renewables reduce the risk of volatile power
costs due to swings in gas prices. However, the company fails to put a dollar value on
this characteristic, so it is not included in its decision-making. The Company does admit
that rate stability and low risk for the kind of crisis we have recently endured is very
valuable, but does not attempt to quantify this value. A recent study by the Lawrence
Berkeley Lab estimated that the market was valuing financial hedge products which
cover gas price risks at about 5 mills/kwh. See Bolinger et al.Quantifying the value
that wind power provides as a hedge against volatile natural gas prices " Lawrence
Berkeley National Laboratory (June 2002) (http://eetd.lbl.gov/ea/EMS/reports/50484.pdfj
Using this amount applied to the additional renewables in the Renewable portfolio would
add about $250 million to its value.
PacifiCorp assumes no emissions for purchased power
PacifiCorp models the Renewables portfolio s extra renewables as displacing
about 450 aMWs of purchased power. However, the Company assumes the purchased
power has no emissions. When looking at the "Diversified 1" and "Renewables
4 500 aMWs of wind and geothermal times 5 mills/kwh for 15 years equals $328 million. Present value is
closer to $250 million.
COMMENTS OF NWEC AND ADVOCATES FOR THE WEST -- 4
portfolios, there is almost no change in emissions and thus no change in their costs--
which are valued with a CO2 cost adder of $8.00 per ton). Fixing this error adds about
$200 million to the value of the Renewables portfolio compared to the others.s One can
graphically see this error in analysis by looking at page 123 which shows how the
portfolios perform with increasing CO2 costs. Even at $40/ton, the Renewables portfolio
still is more costly than Diversified IV, a portfolio virtually identical to Renewables
except for the presence of purchased power instead of the added 1146 + 100 MW s
renewables. Had this analysis been done correctly, the two portfolios should be crossing
as CO2 prices increase.
The total effect of these errors is conservatively estimated at $700 million. This
is $250 million less cost than the Diversified I portfolio. Correction of the errors listed
above would make the Renewables portfolio the least cost option.
Analysis of DSM resources
We largely support the Company s integration ofDSM resource acquisition to the
IRP, subject to several specific comments.
First, the Company should consider the economic value of avoided or deferred
transmission and distribution upgrades flowing from DSM resource acquisition. Recent
analysis indicates these values are significant and growing. The Southwest Energy
Efficiency Project has estimated that avoided distribution costs due to reduced demand
could be as high as $O.Ol/kWh by 2020; and avoided transmissions costs could reach
$0.0 13/kWh in this period. See (http://www.swenergy.org/nmi/index.html). Further, as
5 Efficient gas-fired plants produce about a half-ton ofCOz per MWH. The 500 aMWs (see footnote 1) of
renewables added in the Renewables portfolio would cost, at the $8/ton assumed in the study, about $17.
million per year. Again, the renewables come in over several discounted years, so a conservative estimate
is about 12 years of benefits, or around $200 million.
COMMENTS OF NWEC AND ADVOCATES FOR THE WEST -- 5
noted above for renewables, DSM resources provide additional value as a hedge against
fuel price volatility of approximately $0.05/kWh. Correcting these errors would result in
recognition of significantly higher value for DSM resources.
Moreover, the Company s stress test analysis reveals that increased DSM
investment would result in lower present value revenue requirement "PVRR"See
Table E., pages 296-297. For example, the PVRR of including an additional 300 MW
DSM as a decrement to load is $11 320 508, versus $12 313 159 in the Diversified
Portfolio. We question why additional investments in DSM will not be pursued, given
the cost benefits recognized by the Company.
Finally, in its Idaho territory, we are concerned the Company does not have the
regulatory tools in place to seek all cost-effective DSJy1 investments. Specifically,
PacifiCorp does not have a DSM tariff rider or other specific mechanism to fund DSM
program costs. As with Idaho Power Company and A vista, the establishment of a
continuously replenishing DSM fund ensures that program costs are covered, and further
streamlines the creation of a portfolio of DSM resources.
Conclusion
Pacific should be commended for its effort to fairly weigh the various generation
options in this IRP. However, we believe the Company s "Renewables" portfolio
(including an additional 1146 MW of wind and 100 MW of geothermal) is truly the least
cost option if the significant errors noted above are corrected. We request the
Commission acknowledge the 2002 IRP, with direction to the Company (1) to correct and
supplement its analysis of renewables and DSM as provided herein, and (2) to apply to
COMMENTS OF NWEC AND ADVOCATES FOR THE WEST -- 6
the Commission for approval of a DSM tariff rider or other DSM program funding
mechanism in order to implement the action plan set out in the IRP.
Dated: April 8, 2003 Respectfully submitted
~ Steve Weiss, NW Energy Coalition
William Eddie, Advocates for the West
CERTIFICATE OF SERVICE
I hereby certify that on this 8th day of April 2003 , true and correct copies of the foregoing
COMMENTS were delivered to the following persons via the method of service noted:
Via Hand-Delivery:
Commission Secretary
Idaho Public Utilities Commission
427 W. Washington St.
Boise, ID 83702-5983
Via U.S. Mail:
Janet Morrison
Director of Resource Planning
PacifiCorp
825 NE Multnomah, Ste. 800
Portland, OR 97232
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COMMENTS OF NWEC AND ADVOCATES FOR THE WEST -- 7