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Background
Clean
energy advocates started the new year with a significant victory. After
a long, contentious regulatory battle, the Oregon Public Utility
Commission (OPUC) sided with NW Energy Coalition and its allies in
denying PacifiCorp’s request to acquire two new coal plants totaling
more than 1,100 megawatts by 2013.
The
controversy began when OPUC rejected inclusion of the two coal plants
in the company’s 2004 integrated resource plan (IRP), its most recent.
At that time, commissioners said:
Coupled with
reasonable measures that could be taken to avoid outages (e.g.,
additional short-term purchases, demand response programs and
distributed resources), analysis of the coal plant delay scenarios
indicates that it may be reasonable to wait a couple of years until
IGCC technology is further developed before the Company commits to its
next large thermal resource. (Order 06-029)
But
the company refused to read the writing on the wall, let alone the
order itself, perhaps because PacifiCorp’s new owner,
Mid-AmericanCorp., is a Midwestern utility accustomed to favorable
reception to its many other coal plants. The utility simply went
forward with its plans to solicit bids to build the plants.
Fortunately,
the Coalition and its Oregon allies had already succeeded in
establishing requirements for Commission pre-approval of bid
solicitations and for consistency between the utility’s request for
proposal (RFP) and its integrated resource plan.
Relying
substantially on testimony from the Coalition and partners including
the Citizens’ Utility Board, Renewable Northwest Project, OSPIRG and
Ecumenical Ministries of Oregon, the Commission concluded that, in
fact, PacifiCorp’s RFP was not consistent with its acknowledged IRP.
This
issue of The Transformer looks at the issues raised in OPUC’s order. (Thanks go to Alan Zelenka of Emerald People’s Utility District
for his excellent summary of the decision.)
(Back to the Top)
OPUC had reasons to reject new plants
In
rejecting PacifiCorp’s request for bids to build its coal plants,
Oregon regulators went beyond a merely technical ruling of
inconsistency. Their order notes (1) the advance of potentially cleaner
technologies, (2) the unsuitability of the proposed plants for meeting
specific consumer needs, and (3) probable difficulties in selling
surplus power from the plants into a carbon-constrained energy market.
Here’s the Commission’s summary, followed by a brief discussion of each of the three main points:
In
summary, PacifiCorp’s Draft RFP is not aligned with its acknowledged
2004 IRP, and should not be approved. As in the IRP process, PacifiCorp
has failed to adequately justify, in this proceeding, the need for two
large thermal resources on the east side of its system. PacifiCorp has
not made the case that base load resources provide the best combination
of cost and risk for customers to meet resource needs in 2012 and 2013,
compared to alternatives such as additional conservation and demand
response resources, renewable resources beyond the 1,400 MW in the
company’s acknowledged 2004 IRP.
(1) New technology on the horizon
Commissioners
wondered whether something other than large, conventional coal plants
could be used to meet customers’ needs until promising, “clean coal”
[sic] technology becomes commercially viable. OPUC’s earlier denial of
PacifiCorp’s IRP had specifically directed the utility to “fully
explore bridging strategies that would allow the company to delay a
commitment to coal until IGCC [integrated gasification combined cycle]
technology is further commercialized…”
OPUC’s
order concurred with Coalition testimony on the value of keeping
options open before investing billions of dollars in 50-year-old
technology. Commission analyses of coal plant delay scenarios indicated
that it would be prudent for the company to give IGCC technology a few
years to develop before committing to its next large thermal resource.
(2) Wrong resource for meeting the need
Second, OPUC found that PacifiCorp had failed to establish that base
load (24/7) coal resources were best suited to fill its resource need.
PacifiCorp
serves six states – Utah and Oregon are its largest demand centers,
followed by Idaho, Washington, Wyoming and California. PacifiCorp’s
need for new power results almost exclusively from Utah’s rapidly
rising on-peak summer demand (primarily to run air conditioners).
Recognizing the small number of hours that new power will be needed each
year, the Commission told PacifiCorp to explore resource strategies
other than base load plants, such as short-term purchases, demand-side
measures and distributed resources.
(3) Dirty power will be hard to sell
Relying
on base load plants to meet short-term summer peaks would force the
utility to sell the coal plants’ surplus most hours of the year. OPUC
shared the Coalition’s concerns about PacifiCorp’s ability to sell that
surplus.
The company had argued that surplus
sales would generate lots of money for ratepayers. The Coalition argued
that the efforts in many Western states to limit CO2, emissions might
well leave few buyers for coal-fueled electricity. The Commission
agreed.
(Back to the Top)
Looking ahead
OPUC’s
decision directly conflicts with that of Utah regulators, who
enthusiastically endorsed PacifiCorp’s coal plans — and in fact
recommended that the company acquire up to four coal plants. So now the
company is caught between two states with different visions.
PacifiCorp
must please regulators in each of the six states it serves. Each state
pays a share of the utility’s overall costs, regardless of where plants
are located or which state or states those plants serve. This
arrangement dates to the merger of Pacific Power and Utah Power, which
was expected to create economies of scale and operating efficiencies,
since Utah’s demand peaks in the summer and Oregon and Washington
mainly in the winter.
Since then, however, the
two regions’ environmental and economic-development visions have
diverged. As a result, the company is having trouble getting all its
regulators to agree.
One possible solution for
PacifiCorp is to split into two entities. But the utility is so
interconnected that such a split would be quite difficult to pull off.
Another possibility is a “virtual” split that would allocate costs to
each state, ending the practice of sharing all the utility’s costs.
That solution would tend to raise rates for Utah, whose growing loads
are driving the problem. Because Oregon’s ratepayers help pay for new
resources, we have a stalemate.
It will be interesting to see how this all plays out.
(Back to the Top)
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