OAH Docket No. 3-2500-16554-2
PUC Docket No. ET-2/CN-05-347
STATE OF
OFFICE OF
ADMINISTRATIVE HEARINGS
FOR THE
|
In
the Matter of the Application of |
findings of fact, conclusions and recommendation |
The above-entitled matter came on for
hearing before Administrative Law Judge Kathleen D. Sheehy on July 28, 2005, in
the small hearing room of the Minnesota Public Utilities Commission (“Commission”)
in
Michael Bradley, Moss & Barnett,
4800
Karen Hammel, Assistant Attorney
General, 1400
B. Andrew Brown, Dorsey and Whitney
LLP,
Bill Storm, formerly with the EQB and
now with the Department, appeared on behalf of those agencies for the purpose
of presenting evidence concerning GRE’s site permit application.[1]
David L. Jacobson,
Notice is hereby given that, pursuant
to Minn. Stat. § 14.61 and the Rules of Practice of the Commission and the
Office of Administrative Hearings, exceptions to this Report, if any, by any
party adversely affected, must be filed within 15 days of the mailing date
hereof with the Executive Secretary, Minnesota Public Utilities Commission, 121
Seventh Place East, Suite 350, St. Paul, Minnesota 55101. Exceptions must be specific, and must be
stated and numbered separately. Proposed
Findings of Fact, Conclusions and Order should be included, and copies thereof
must be served upon all parties. Replies
to exceptions are not permitted. Oral
argument before a majority of the Commission will be permitted to all parties
requesting such argument who are adversely affected by the Administrative Law
Judge’s recommendation. Such request
must accompany the filed exceptions, and an original and 15 copies of each
document must be filed with the Commission.
The Commission will make the final
determination of the matter after the expiration of the above-set forth period
for filing exceptions, or after oral argument, if such is requested and had in
the matter.
Further notice is hereby given that the
Commission may, at its own discretion, accept or reject the Administrative Law
Judge’s recommendation and that said recommendation has no legal effect unless
expressly adopted by the Commission as its final order.
1. Should
the Commission grant a Certificate of Need (CON) for the 170 MW simple-cycle
combustion turbine plant GRE proposes to build in
2. Should the Commission issue a Site Permit
to locate the proposed plant in
The Administrative Law Judge concludes
that the Commission should grant the CON and issue the Site Permit as requested
by GRE.
Based upon all of the proceedings herein,
the Administrative Law Judge makes the following:
Procedural
History
1. GRE is a
2. On
February 28, 2005, GRE applied for a CON for a simple-cycle combustion turbine
plant to be built at the site of its existing Cambridge Peaking Plant in in
3. The
proposed facility is a large energy facility within the meaning of Minn. Stat.
§ 216B.2421, subd. 2(1).
4. On
March 11, 2005, GRE filed a Site Permit Application with the EQB. Because the proposed plant would be fueled by
natural gas, the project qualifies for alternative review under Minn. Stat. §
116C.575, subd. 2.
5. On
March 17, 2005, the EQB passed a resolution authorizing a joint hearing on the
site permit application with the PUC’s hearing on the CON.[4]
6. By
letter dated March 14, 2005, the chair of the EQB notified GRE that its
application was accepted.[5]
7. On
March 29, 2005, GRE filed additional information supplementing the CON
Application.
8. GRE’s
public notice dated March 28, 2005, is included in the record,[6]
but there is no affidavit or other evidence to substantiate that GRE sent a
copy of the application by certified mail to Isanti County, the City of
Cambridge, or Cambridge Township, or that notice was provided to property
owners whose land is adjacent to the proposed site, as required by Minn. Stat.
§§ 116C.575, subd. 4, and 116C.57, subd. 2b.
As noted below, however, the EQB mailed notice of filing the application
to the local units of government, and the project was well publicized in the
local newspapers. Although notice to
adjacent landowners is important, the record reflects that local officials and adjacent
landowners were aware of the project and attended the public hearings. Under these circumstances the Administrative
Law Judge finds that the error in providing notice, if any, was harmless and
did not interfere with the public’s right to be informed about the project.
9. On
March 31, 2005, the EQB mailed the notice of filing the application and notice
of a public meeting to participate in scoping the Environmental Assessment to
persons on its general and project notification list, local government list,
technical representatives, and PUC energy staff list. The public meeting was scheduled to take
place on April 19, 2005, at the
10. Between
March 28, 2005, and April 10, 2005, the GRE and the EQB published in the Cambridge Star, the Scotsman, and the Isanti
County News a notice of the filing of the application, a description of the
proposed project, directions for obtaining a copy of the application, and a
notice of the public meeting to be conducted on April 19, 2005.[8]
11. On
April 8, 2005, the Commission issued an Order finding GRE’s CON application to
be substantially complete and authorizing a joint hearing on the CON and site
permit applications pursuant to Minn. Stat. § 216B.243, subd. 4. On the same date the Commission issued a
Notice and Order for Hearing referring the matter to the Office of
Administrative Hearings.[9] GRE and the Department were the named parties
in the Notice and Order for Hearing.
12. On
April 11, 2005, the EQB published in The
EQB Monitor notice of acceptance of the project and of the public meeting
to be held at the Isanti County Fairgrounds on April 19, 2005.[10]
13. The
EQB held the public meeting at the Isanti County Fairgrounds on April 19,
2005. The public was given until April
29, 2005, to submit written comments regarding the scope of the Environmental Assessment.[11]
14. On
May 5, 2005, the chair of the EQB issued the scoping decision for the
environmental assessment.[12]
15. On
May 5, 2005, the EQB mailed copies of the scoping decision to each person on
the EQB general notification list, local government list, project contact list,
and technical representatives.[13]
16. The
EQB’s Environmental Assessment was completed on May 31, 2005.[14] The Environmental Assessment was posted on
the EQB web page on or about May 31, 2005.
On the same date, the EQB mailed a combined notice of the availability
of the Environmental Assessment and notice of the public hearings to persons on
the EQB general notice list, local government list, project contact list, and
technical representatives.[15] On June 20, 2005, the EQB published a
combined notice of the availability of the Environmental Assessment and notice
of the public hearings in The EQB Monitor.[16]
17. On
July 10, 2005, the EQB published notice of the public hearings in the Scotsman. On July 13, 2005, the EQB published notice of
the public hearings in the Star Tribune,
the Pioneer Press, and the Cambridge Star.[17]
18. On
June 7, 2005, and June 24, 2005, GRE filed additional information supplementing
the CON Application.
19. On
July 26, 2005, public hearings were held at 3:00 and 7:00 p.m. in the
20. The
evidentiary hearing was held July 28, 2005, at the Commission’s offices in
Parties to the
Proceeding
21. After
the matter was referred to the OAH, Mankato Energy petitioned to intervene as a
party, as did Minnesota Power. Mankato
Energy’s petition to intervene as a party was granted; Minnesota Power was
granted status as a participant.[20]
22. Mankato
Energy is a wholly-owned subsidiary of Calpine Corporation. Calpine operates power projects in 28
states. In September 2004, the Commission
issued an Order granting a CON to Mankato Energy for a “two-on-one” combined
cycle natural gas-fired power plant in
23. The
proposed project would generate electricity using a simple-cycle combustion
turbine generator. It is designed to
provide a source of electricity to meet demand during peak consumption periods
during the summer; the plant would not be accredited in the winter and is not
needed for GRE’s winter peak consumption.
The total summer accredited output would be 170 MW. The estimated installed cost is
$69 million, and the projected start date for plant operations is the
summer of 2007. The existing 69-kV
substation would have to be modified to accommodate the increase in electrical
output. The substation bus feeds four
existing 69-kV lines as well as the local distribution substation located at
the site. Preliminary results from the
MISO transmission studies indicate that sections of lines will need to be
upgraded either through reconductoring or rebuilding at the existing 69-kV
voltage.[22] The combustion turbine would be fueled by natural
gas, which would be transported to the site by pipeline owned by Northern
Natural Gas (NNG).[23]
24. The NNG pipeline originates in
CERTIFICATE OF NEED
25. GRE
proposes to construct a 170 MW combustion turbine plant. Construction of any electric power generating
plant with a capacity of 50,000 kilowatts or more requires a CON from the
Commission.[25]
26. The
Commission may not issue a CON for a large energy facility that generates power
by means of a nonrenewable energy source unless the applicant has explored the
possibility of generating power by means of renewable energy sources, and the
applicant has demonstrated that the alternative selected is less expensive
(including environmental costs) than power generated by a renewable energy
source.[26] Hydropower, wind, solar, geothermal, and
biomass are considered renewable energy resources.[27]
27. GRE
and the Department determined that the following objectives were reasonable in
analyzing whether renewable resources could meet GRE’s needs:
(a) Applicability – can the alternative meet
GRE’s demand and the associated reserve requirements during peak consumption
periods?
(b) Availability – can the alternative provide a
170 MW commercially proven facility for the 2007 summer season?
(c) Reliability – can the alternative enhance
the reliability of the bulk electric system?
(d) Environmental Impacts – does the alternative
minimize environmental and community impacts?
(e) Cost and Economic Effects – is the
alternative is the least-cost alternative, and does it provide economic
benefits to the community?[28]
28. GRE
did not consider geothermal energy because there are no utility-scale sites in
29. According
to the U.S. Department of Energy (DOE), there is a total undeveloped capacity
of 137 MW of hydropower in
30. Hydropower
could meet GRE’s demand, and it would likely meet the reliability,
environmental, and cost factors identified above; however, the length of time
needed for construction of hydropower projects means it would not be available
in time to meet GRE’s needs by the 2007 summer season.[31]
31. In
general, both wind and solar generation are intermittent in nature and are
unsuitable alternatives for a peaking facility.[32]
32. Construction
of 170 MW of solid fuel biomass capacity by 2007 is not feasible. Furthermore, solid fuel power plants have
operating characteristics consistent with baseload resources and would not
offer a cost effective peaking alternative.[33]
33. GRE
also examined using an ethanol-fueled facility as a renewable energy
alternative. There are both technical
and economic drawbacks to this alternative.
The technical concerns include manufacturer reluctance, untested
technology, higher emissions of certain pollutants, fuel handling problems,
maintenance issues, and less efficiency.[34]
34. Based on the project objectives, there are
no reasonable renewable alternatives that are available in the necessary
timeframe that would reliably and economically meet peaking resource needs.[35]
Innovative Energy Projects
35. Innovative
energy projects must also be considered as a supply option in lieu of a
fossil-fuel generation facility.[36] Excelsior Energy filed comments stating that
an innovative energy project cannot meet an in-service date of 2007, and the
substantial capital costs involved with development and construction of an
innovative energy project, along with the low capacity factor assumed in GRE’s
application, make an innovative energy project unsuitable to meet GRE’s need.[37]
36. Minn.
Rules pt. 7849.0120 provides that a CON must be granted to the applicant
if:
A. the
probable result of denial would be an adverse effect upon the future adequacy,
reliability, or efficiency of energy supply to the applicant, to the
applicant’s customers, or to the people of
(1) the
accuracy of the applicant’s forecast of demand for the type of energy that
would be supplied by the proposed facility;
(2) the
effects of the applicant’s existing or expected conservation programs and state
and federal conservation programs;
(3) the
effects of promotional practices of the applicant that may have given rise to
the increase in the energy demand, particularly promotional practices which
have occurred since 1974;
(4) the
ability of current facilities and planned facilities not requiring certificates
of need to meet the future demand; and
(5) the
effect of the proposed facility, or a suitable modification thereof, in making
efficient use of resources;
B. a
more reasonable and prudent alternative to the proposed facility has not been
demonstrated by a preponderance of the evidence on the record, considering:
(1) the
appropriateness of the size, the type, and the timing of the proposed facility
compared to those of reasonable alternatives;
(2) the
cost of the proposed facility and the cost of energy to be supplied by the
proposed facility compared to the costs of reasonable alternatives and the cost
of energy that would be supplied by reasonable alternatives;
(3) the
effects of the proposed facility upon the natural and socioeconomic
environments compared to the effects of reasonable alternatives; and
(4) the
expected reliability of the proposed facility compared to the expected
reliability of reasonable alternatives;
C. by
a preponderance of the evidence on the record, the proposed facility, or a
suitable modification of the facility, will provide benefits to society in a
manner compatible with protecting the natural and socioeconomic environments,
including human health, considering:
(1) the
relationship of the proposed facility, or a suitable modification thereof, to
overall state energy needs;
(2) the
effects of the proposed facility, or a suitable modification thereof, upon the
natural and socioeconomic environments compared to the effects of not building
the facility;
(3) the
effects of the proposed facility, or a suitable modification thereof, in
inducing future development; and
(4) the
socially beneficial uses of the output of the proposed facility, or a suitable
modification thereof, including its uses to protect or enhance environmental
quality; and
D. the record
does not demonstrate that the design, construction, or operation of the
proposed facility, or a suitable modification of the facility, will fail to
comply with relevant policies, rules, and regulations of other state and
federal agencies and local governments.
37. GRE’s
forecast in the CON application is based on GRE’s 2003 Integrated Resource Plan
(IRP), which was accepted by the Commission in Docket No. E-002/CN-03-974.[38] The demand data in GRE’s 2003 IRP were
derived from GRE’s 2002 Long Range Load Forecast, which was approved by the
Rural Utilities Service.[39] In its simplest terms, GRE’s CON application
compared its forecasted demand against its accredited capacity, which
demonstrated a need for the additional 170 MW.[40] GRE estimates that the plant will have a
capacity factor of between 5 and 10 percent.[41] The only plants capable of operating
efficiently with such a small capacity factor are peakers. An intermediate facility is one intended to
operate between 20 and 70 percent of the time (which would be two to seven
times longer than would be required by the GRE facility).[42]
38. Mankato
Energy contends that GRE has failed to substantiate that the type of power it
needs is peaking power, as opposed to intermediate power. Mankato Energy points to GRE’s 2003 IRP, in
which GRE identified a combined cycle 586 MW intermediate resource as the least
cost plan to meet its needs;[43]
however, the cost difference calculated at that time between a combined cycle
and a combustion turbine plant was less than 1 percent over a 15-year planning
horizon.[44]
39. GRE
subsequently contracted with Minnesota Power to purchase 130 MW of baseload
power, plus MAPP planning reserves, along with 45 MW of intermediate power,
plus MAPP planning reserves. In
addition, GRE purchased 100 MW of wind power.
GRE filed a 2004 IRP update to reflect these purchases.[45]
40. Based
on the purchases of baseload and intermediate power from Minnesota Power, and
based on the wind power purchases, GRE reevaluated its forecasted demand
compared to its accredited capacity. The
2004 IRP update reflects GRE’s conclusion that a peaking facility, and more
specifically a 170 MW combustion turbine, was the appropriate plant to meet the
expected peak demand deficiency.[46]
41. During
these proceedings the Department requested updated forecasting data from GRE,
which GRE did not have because it had not yet completed its 2004 Long Range
Load Forecast. GRE provided the Department with actual usage data for 2003 and
2004. Based on that information, and
after making certain other adjustments, the Department determined that GRE had
not overstated its need.[47] The Department and GRE agreed to meet outside
of these proceedings to discuss GRE’s forecasting methodologies.[48]
42. GRE’s
forecast of need in the CON, as adjusted by the Department and as supplemented
by actual usage data, is sufficiently accurate to conclude that GRE has a need
for at least 170 MW of peaking power.[49]
43. While
GRE’s application is based on its 2003 IRP, GRE contends that its conclusions
as to the need for a 170 MW combustion turbine are supported by GRE’s 2005 IRP
(which was filed on June 30, 2005, and is being evaluated in Docket No.
ET-2/RP-05-1100). According to the 2005
IRP, GRE will not need to acquire permanent additional intermediate capacity
until 2009 or 2010.[50]
44. Mankato
Energy disputes that the 2005 IRP supports GRE’s forecast demand for peaking
power. It maintains that GRE should have
used actual cost data from Mankato Energy’s bids, as opposed to generic cost
data, in the IRP modeling process. In
response, GRE maintains that additional modeling based on actual data would be
too expensive and that generic data should be used in the resource planning
process, because it is intended to be an open process not limited by use of
trade secret data. The Department
contends that it is not appropriate to make this determination in a CON
proceeding. The Administrative Law Judge
agrees with the Department and concludes that the issue whether actual or
generic cost data should be used in the IRP process is one that is more
properly raised in the 2005 IRP docket.
The 2005 IRP is being evaluated by the Department and is subject to
approval by the Commission; it is premature to use GRE’s 2005 IRP to support
either party’s position in this proceeding.
45. The
Commission approved the forecast contained in GRE’s 2003 IRP, and this
forecast, as adjusted by the Department and as supplemented by actual usage
data, is sufficiently accurate to support GRE’s determination that it needs 170
MW of peaking power.[51] GRE has proved by a preponderance of the
evidence that its need is primarily for capacity, as opposed to energy, and
that a peaking resource is an appropriate facility to meet this need. GRE does not need the production capability
of an intermediate resource such as Mankato Energy’s second-phase facility.
46. There
are no significant conservation programs that might affect the need for the
proposed project.[52]
47. GRE
has not conducted any promotional activities that have significantly
contributed to the need for the proposed project.[53]
(4)
Ability of Current Facilities or Facilities Not Requiring Certificates
of Need to Meet Future Demand
48. The
primary alternatives to the proposed project that would not require
certificates of need are power purchases from existing facilities inside or
outside of Minnesota, planned facilities outside Minnesota, or construction of
Minnesota facilities that are small enough not to require certificates of
need. New facilities that are small
enough not to require a certificate of need would have to be numerous. The economies of scale in the electric
industry make this an uneconomic alternative.
Therefore, facilities that do not require certificates of need cannot
meet the identified demand.[54]
(5) The Effect of the Proposed Facility (or a
Suitable Modification) in Making Efficient Use of Resources
49. The
proposed project would utilize existing transmission lines and NNG’s existing
pipeline system as its source of natural gas.[55]
50. The
natural gas would be transported through two existing 16-in. and 12-in.
pipelines owned by NNG, and a new 0.5 mile lateral pipeline would be
constructed connecting to both lines.
There is sufficient natural gas capacity available to reliably serve the
proposed project’s summer needs.[56]
51. The
site would have two water storage tanks, with one 300,000-gallon tank used to
store raw water and one 200,000-gallon tank to store demineralized water.[57] The compressor wash wastewater would be
stored in an on-site tank, off-loaded into tanker trucks, and hauled to a
municipal wastewater treatment plant for ultimate treatment and disposal. Some of the wastewater (except the compressor
wash wastewater and sanitary wastewater) from the site would be processed
through an oil/water separator and then pumped to an on-site retention pond and
discharged to an adjacent ditch that would likely flow into Beckins Creek,
which discharges to the Rum River. GRE
will seek a wastewater permit from the Minnesota Pollution Control Agency
(MPCA) for the retention pond.[58]
52. With
regard to the requirements of
B. Has a
More Reasonable and Prudent Alternative to the Facility Been Demonstrated by a
Preponderance of the Evidence on the Record?
53. Before
deciding to proceed with the proposed project, GRE examined the following
alternatives: (a) conservation and
energy efficiency; (b) oil-fired combustion turbine, simple cycle; (c) combined
cycle combustion turbine; (d) coal fired technologies; (e) purchased power; (f)
new transmission; (g) customer-owned distributed generation; (h) demand side
management (DSM); (i) emerging technology alternatives; and (j) upgrading existing
resources.[59]
54. GRE’s energy conservation goals, existing
load management and energy conservation programs, other conservation measures
considered, future load management and conservation plans, some conservation
ideas that have not been implemented, its conservation accomplishments, and the
cost of the conservation programs are outlined in Ex. 1, Appendix C.
55. GRE has reduced its summer peak demand in
2004 by approximately 300 MW, primarily through load management, conservation
measures and customer owned generation.
DSM is expected to further reduce demand by another 16 MW in 2005. While these programs have delayed the need
for additional peaking capacity, additional participation in these programs
cannot entirely replace the 170 MW of need by 2007.[60]
56. Conservation is not efficient for purposes
of reducing peak demand for energy.[61]
57. A fuel oil-fired CT alternative could be
constructed in a year or less; however, its permitting process also takes about
a year and would need to be completed before the start of construction. Therefore, the fuel oil CT fails the timing
criterion.[62]
58. A
natural gas-fired combined cycle facility would take 24 months to construct and,
therefore, could not meet the timing criterion.
In addition, the combined cycle is not well suited to meet the
requirements of a peaking facility because capital costs are higher.[63]
59. Coal-fired
technologies fail to meet the primary objectives due to the lengthy time needed
to site, permit and construct them as well as inappropriate operating
characteristics.[64]
60. GRE
analyzed the purchased power market by means of a request for proposals (RFP)
issued on March 2, 2004. The RFP
requested proposals for both intermediate and peaking resources.[65] GRE received 31 proposals from 17 different
responders, and all but five of the proposals relied on new generation.[66] Mankato Energy submitted four bids, two of
which were described as peaking, one was described as intermediate, and one was
described as a combined intermediate/peaking proposal.[67]
61. Mankato
Energy would use a 320 MW intermediate facility to serve GRE’s 170 MW of
peaking requirements. While a portion of
the Mankato Energy plant is designed to operate like a peaker, there is not
enough remaining capacity from that portion of the plant to meet GRE’s needs.[68] If no additional contracts for its remaining intermediate
output are negotiated, Mankato Energy was equivocal as to whether it would
actually complete construction of the second phase of the project to meet GRE’s
needs, or whether it would simply purchase the needed energy from MISO.[69] GRE could purchase energy from MISO itself;
however, GRE has concluded that this is not a sufficiently reliable alternative
to meet GRE’s demand for 170 MW of peaking power.
62. Mankato
Energy could also provide ancillary services to GRE and, more specifically,
capacity that could be used when wind generation is unavailable; however, these
services are no longer of individual value as MISO follows changes to load and
generation from a regional perspective.[70]
63. New transmission is not a true alternative
to generating resources in many instances.
Because of the length of time required to construct new bulk
transmission facilities and regulatory uncertainties, particularly surrounding
cost recovery, new transmission lines are not a reasonable alternative to meet
GRE’s immediate needs. Construction time
for a transmission line of significant length, which is the focus of this
alternative, would probably require a year or more, and it would require about
one year to obtain site permits.
Therefore, the transmission alternative would not meet the timing
criterion.[71]
64. GRE
currently has approximately 116 MW of customer-owned generation in place, which
represents the capacity benefit from these generators in the summer
season. GRE anticipates the addition of
17 MW of customer-owned generation by 2006.[72] Timing would be a concern, as it would
require more than 70 diesel generator sets of 2 MW to be installed before the
summer of 2007.[73] And because the distributed generation is
customer-owned, the timing of any construction would be outside of the control
of GRE. There would be no guarantee that
170 MW of summer capacity would be built by 2007.[74]
65. GRE
examined emerging technologies as alternatives to the proposed roject,
including fuel cells, pumped storage hydroelectric, compressed air energy
storage, battery energy storage and superconducting magnets. None of these alternatives meet the Project
objectives, either because of the immature state of their development or their
inappropriateness for peaking application at this time.[75]
66. GRE
has currently achieved a peak summer demand reduction of 300 MW and expects to
add another 16 MW to the total in the summer of 2005. GRE does not expect these reductions to
replace the 170 MW need.[76] Since DSM programs typically take several
years to deliver maximum results, this alternative would not meet the Project’s
time criteria.[77]
67. GRE
identified three possible future upgrades that could add a total of
approximately 42.1 to 57.9 MW. This
alternative could not supply the additional 170 MW of summer peaking capacity
before the summer of 2007.[78]
(2) Cost
of Proposed Facility and Energy to be Supplied Compared to Proposed
Alternatives
68. Economic
cost comparisons between the Project fueled by natural gas, fuel oil and
ethanol show that the natural gas alternative is the most cost effective.[79]
69. GRE
plans to continue to expand its DSM efforts beyond current programs, but it
would not be possible to achieve the load relief necessary to meet capacity
needs by the summer of 2007.[80]
70. With
regard to purchased power alternatives, GRE screened the responses to its RFP in
two steps. First, GRE evaluated the
proposals on the basis of geographic proximity, developer experience and
expertise, resource type, GRE business experience with the responder, certain
price elements, and responsiveness to the RFP.
The proposals submitted by GRE, Mankato Energy, and a second developer
survived this first screening step.
Second, the proposals that passed this initial screen were subjected to
a more extensive cost and risk analysis.
Because the proposals had different price structures, GRE calculated an
“all-in” price on a dollar-per-MW basis for each option that included all
fixed, variable, and fuel costs at two different annual capacity factors (5%
and 10%).[81] This analysis showed that GRE’s self-build
proposals were the lowest cost alternatives, the other developer’s proposals
were second, and Mankato Energy’s lowest cost proposal came in third.[82] Mankato Energy submitted an additional offer,
which was presented as an offer for intermediate capacity, but it was not materially
different in price from Mankato Energy’s earlier offer.[83]
71. Mankato
Energy did not supply any information about what, if any, upgrades to the
transmission network would be required in order to have Mankato Energy supply
purchased power to GRE.[84] GRE did not include this cost in its
calculation of Mankato Energy’s “all-in” price.
If it had, the price differential would likely have been greater.[85]
(3) The Effects of the Proposed Facility Upon the
Natural and Socioeconomic Environments
Compared to the Effects of Reasonable Alternatives
72. GRE
compared air emissions from the proposed project to estimated emissions from
use of fuel oil and ethanol.[86] The proposed project would have lower
emissions than the fuel oil alternative and lower emissions than could be
estimated for an ethanol-fueled alternative.[87]
The proposed project would meet GRE’s projected needs at a lower cost with less
environmental impact than the fuel oil and ethanol alternatives.[88]
73. Under
normal operating conditions, the proposed project would use significantly less
water than the ethanol and fuel oil alternatives.[89]
74. The
project would be located on land that is currently used for utility operations.
Adjacent property is used for agricultural and transportation purposes.[90]
75. The
proposed Project would use existing natural gas pipelines.[91] A plant using fuel oil or ethanol would mean
increased traffic in and out of the facility due to fuel deliveries.[92]
76. Mankato
Energy’s air emissions would generally be much lower than the emissions from
the
77. GRE
compared the
78. Mankato Energy’s facility will use
reclaimed water from a local wastewater treatment plant for processing and
cooling; GRE’s proposed project will use groundwater for these purposes. There is no evidence that GRE’s use of
groundwater will adversely impact the aquifer, regional water supplies, or any
existing potable wells in the area.[96]
79. The State of
80. The
proposed project would utilize approximately 75 skilled craft workers for the
construction, lasting approximately one year.[98] The Project would create 2 to 3 full time
equivalent jobs during operation.[99]
81. The
proposed project would benefit the community in that GRE’s members would
continue to supply reliable power to support economic growth in the region.[100]
(4) The
Expected Reliability of the Proposed Facility Compared to Reasonable
Alternatives
82. Because
the proposed project and the fuel oil and ethanol alternatives use similar
technology, the proposed project should be at least as reliable as the fuel oil
and ethanol fuel alternatives.[101]
83. GRE
determined that Mankato Energy’s proposal, in addition to being more costly,
was less reliable than the proposed project based on concerns about Calpine’s
credit risk. Calpine has had a below
investment-grade bond rating for all but four months of its existence.[102] Bond ratings below investment grade indicate
a higher risk of the company going into bankruptcy.
84. GRE’s
principal lender, the Rural Utilities Service (RUS), requires GRE to solicit
competitive bids to supply its energy needs.
GRE is required to compare not only the economics of the bids, but to
evaluate the risks involved with each bid.
In order to protect RUS loan security, RUS expects GRE to select an
alternative (project or agreement) that is economical and has a low risk
profile. RUS prefers that the
prospective suppliers have a minimum of an investment-grade credit rating. If RUS determines that the selected
alternative has a high risk profile, RUS would require some type of additional
credit assurance.[103]
84. Mankato
Energy contends that concerns about its credit could be minimized in a variety
of ways, including the use of a letter of credit, which GRE could use to
purchase power if Mankato Energy failed to deliver the necessary energy. If drawn upon in a manner that Mankato Energy
deemed inappropriate, however, this process could result in litigation and
would not ensure that power was available when needed.[104]
85. Mankato
Energy also suggested that GRE could use step-in rights and other subordination
rights to protect itself in the event Mankato Energy or Calpine filed for
bankruptcy or failed to deliver necessary energy.[105] These are contractual rights that would be
subject to challenge and possible disallowance in bankruptcy. In addition, Xcel Energy already has step-in
rights to the portion of the plant that includes the operational controls over
the portion of the plant that GRE would operate in a step-in situation.[106] Step-in rights may be inadequate where more
than one customer is able to exercise those rights.[107]
86. Finally,
Mankato Energy proposed that use of a limited liability company with a “ring
fence around the entity” could resolve the potential bankruptcy issue.[108] Mankato Energy, as a wholly owned
subsidiary, does not have independent capital, and could go bankrupt itself. In addition, Mankato Energy is an asset of
Calpine and, therefore, could potentially be sold in bankruptcy to meet
Calpine’s debts.
88. These
options might well be appropriate or be given more weight had Mankato Energy
been the low bidder, but its proposals were not competitive with either the
bids of the other developer or with GRE’s self-build proposal. With regard to the requirements of
C. Whether the Benefits of the Proposed Facility
to Society Are Compatible with Protecting the Natural and Socioeconomic
Environments, including Human Health
(1)
The Relationship of the Proposed Facility to
89. GRE
is a member of the Mid-Continent Area Power Pool (MAPP) with load
responsibility as part of the reserve sharing pool for MAPP members. The generation reserve sharing pool concept
is a key reason why MAPP was formed, for by sharing generation reserves in a
pool, individual members can carry lower generation reserves than if they were
not members of the pool. MAPP requires
that members maintain 15 percent more capacity than their peak load to ensure
regional electric system reliability. A
delay in the project could result in GRE not having enough capacity to meet its
MAPP peak load obligation. MAPP requires
any utility not meeting this requirement to purchase capacity at $45,000 –
$90,000 per MW of deficit. Therefore, a
100 MW deficit would result in a penalty of $4.5 – $9.0 million for each season
in which this occurs, which would most likely be summer only.[109]
90. Electric
system reliability is complex and is dependent upon adequate generation and
transmission capacity. GRE’s neighboring
systems and other pool members could experience lower reliability if this
project were delayed. Conversely,
additional generation capacity could improve system reliability.[110]
(2)
Effect on the Natural Environment Compared to
91. In
the event of a delay, GRE would attempt to meet its needs through increased use
of existing facilities. GRE’s existing
baseload generation facilities are currently running at or close to full
capacity and, therefore, could not be utilized to meet this need. GRE’s existing natural gas and oil-fired
peaking facilities would need to be dispatched more frequently, resulting in
higher fuel costs and increased emissions.
Constructing the proposed project would be more efficient than relying
on any of GRE’s current peaking facilities to provide the same amount of
energy.[111]
92. Negative
effects on the natural environment include traffic and noise pollution during
construction, and noise and air emissions during operation. The environmental effects of the proposed project
are subject to the permitting activity of various governmental agencies.[112]
(3)
Effects on the Socioeconomic Environment in Inducing Future Development
93. Because
the proposed project is a peaking plant, it is not expected to directly induce future
development. The rural and suburban
service
94. The
State of
(4) Socially Beneficial Uses of the Output of the
Facility
95. The
project will provide socially beneficial uses by supplying the member-owners
with reliable, relatively low-cost power.
96. With regard to Minn. R.
7849.0120, Item C, GRE has proved by a preponderance of the evidence that the
benefits of the proposed facility are compatible with protecting the natural
and socioeconomic environments, including human health.
D. Compliance with Policies, Rules and
Regulations
97. There
is no indication in the record that the design, construction and operation of
the Project would fail to comply with relevant policies, rules and regulations
of other state and federal agencies and local governments. The issuance of a Certificate of Need would
not conflict with any other regulatory requirements.[116]
98. The
equipment that would be required for the project is as follows:
·
a simple cycle combustion turbine using “F” class
technology, such as a Siemens/Westinghouse V84, with a nominal summer capacity
of approximately 170 MW under MAPP summertime conditions;
·
a generator step-up transformer;
·
less than 10,000 feet of transmission line from the
transformers to the existing Cambridge Substation;
·
a natural gas town border station and meter;
·
an evaporative cooler;
·
an exhaust stack, approximately 90 feet tall, with silencer;
·
two water storage tanks, one to store raw water with
capacity of approximately 300,000 gallons, and a demineralized water storage
tank with a capacity of approximately 200,000 gallons;
·
a mobile water demineralization system, which will recharge
the mineral beds off-site;
· a new water
retention basin near the south end of the site; and
· an existing
warehouse to house the critical parts, tools and supplies needed for
maintenance and reliable operations.[117]
99. Natural
gas would be delivered to the project via the NNG system. Natural gas would be provided to the plant
site by a new 10-inch line off the NNG 16-inch and 12-inch trunk‑lines. The new pipeline would be 0.5 miles. A town border station would be constructed at
the site, as would a gas metering and conditioning station.[118]
100. One
generator step-up transformer would be used to increase the voltage supplied by
the project to the substation voltage of 69 kV.
The
101. The proposed project would require raw water
only to provide evaporative inlet air cooling and, potentially, wet compression
power augmentation to sustain the cooler weather capacity of the combustion
turbine during the warmest days of the year.
GRE estimates that the proposed unit will operate without using any
water more than 80 percent of the time.[120]
It would also require water to provide fire protection.
102. Two
on-site water storage tanks would accommodate water demands.
103. GRE would construct a new well on the Project
site south of
104. GRE
intends to use treated water for operation of the evaporative cooler during the
summer months and potentially for wet compression power augmentation. GRE would use a transportable
demineralization unit to treat the raw water.
The demineralization beds will be recharged off site; therefore, no
on-site wastewater discharge will occur from the demineralization system. An estimated 150,000 gallons of wastewater
(compressor wash water) will be generated annually from maintenance of the combustion
turbine. This process wastewater would
be stored in an on-site tank. The
process wastewater will be off-loaded into tanker trucks and hauled to a
municipal wastewater treatment plant for ultimate treatment and disposal. The expected wastewater discharge on site are
expected to be limited to the approximately 1.8 million gallons from
evaporative cooler blow down.[122]
105. GRE plans to dispose of storm water and
process wastewater under a new NPDES discharge permit. Storm water drainage patterns from the
service building area north of 349th Avenue NE would be unchanged by the project,
while storm water from the portion of the site south of 349th Avenue NE would
be routed to a new water retention basin constructed near the south end of the
site. Process wastewater, consisting
primarily of approximately 1.8 million gallons of evaporative cooler blow down
water, along with approximately 3 million gallons of storm water runoff, would
be routed to the new retention pond. The
retention pond would have a controlled outlet that would discharge water to a
drainage swale from the south edge of the project site to a wetland located
about 300 feet south of the site. GRE
will obtain a drainage easement from the adjacent property owner to allow for
the discharge through the drainage swale.
The wetland discharges to the southwest through an unnamed creek that intersects
Beckins Creek about one mile southwest of the site. Beckins Creek discharges to the
Statutory and Rule Considerations
106. Minn.
Stat. § 116C.57, subd. 4, provides that in determining whether to grant a site
permit the Commission shall be guided by the following responsibilities,
procedures, and considerations:
(a) Evaluation of research and
investigations relating to the effects on land, water and air resources of
large electric power generating plants and high voltage transmission lines and
the effects of water and air discharges and electric and magnetic fields
resulting from such facilities on public health and welfare, vegetation,
animals, materials and aesthetic values, including baseline studies, predictive
modeling, and evaluation of new or improved methods for minimizing adverse
impacts of water and air discharges and other matters pertaining to the effects
of power plants on the water and air environment;
(b) Environmental
evaluation of sites and routes proposed for future development and expansion
and their relationship to the land, water, air and human resources of the
state;
(c) Evaluation
of the effects of new electric power generation and transmission technologies
and systems related to power plants designed to minimize adverse environmental
effects;
(d) Evaluation
of the potential for beneficial uses of waste energy from proposed large
electric power generating plants;
(e) Analysis
of the direct and indirect economic impact of proposed sites and routes
including, but not limited to, productive agricultural land lost or impaired;
(f) Evaluation
of adverse direct and indirect environmental effects which cannot be avoided
should the proposed site and route be accepted;
(g) Evaluation
of alternatives to the applicant’s proposed site or route proposed pursuant to
subdivisions 1 and 2;
(h) Evaluation
of potential routes which would use or parallel existing railroad and highway
rights-of-way;
(i) Evaluation
of governmental survey lines and other natural division lines of agricultural
land so as to minimize interference with agricultural operations;
(j) Evaluation
of the future needs for additional high voltage transmission lines in the same
general area as any proposed route, and the advisability of ordering the
construction of structures capable of expansion in transmission capacity
through multiple circuiting or design modification;
(k) Evaluation
of irreversible and irretrievable commitments of resources should the proposed
site or route be approved;
(l) When
appropriate, consideration of problems raised by other state and federal
agencies and local entities;
(m) If
the board’s rules are substantially similar to existing regulations of a
federal agency to which the utility in the state is subject, the federal
regulations must be applied by the board; and
(n) No site or route shall be designated
which violates state agency rules.
107. Minn. Rules pt. 4400.3150 implements the
above statutory requirements and requires that the Commission be guided by
specified siting and routing considerations.
They are as follows:
(a) Effects on human settlement, including,
but not limited to, displacement, noise, aesthetics, cultural values,
recreation, and public services;
(b) Effects on public health and safety;
(c) Effects on land-based economies,
including, but not limited to, agriculture, forestry, tourism, and mining;
(d) Effects on archaeological and historic
resources;
(e) Effects on the natural environment,
including effects on air and water quality resources and flora and fauna;
(f) Effects on rare and unique natural
resources;
(g) Application of design options that maximize
energy efficiencies, mitigate adverse environmental effects, and could
accommodate expansion of transmission or generating capacity;
(h) Use or paralleling of existing
rights-of-way, survey lines, natural division lines, and agricultural field
boundaries;
(i) Use of existing large electric power
generating plant sites;
(j) Use of existing transportation, pipeline,
and electrical transmission systems or rights-of-way;
(k) Electrical system reliability;
(l) Costs of constructing, operating and
maintaining the facility which are dependent on design and route;
(m) Adverse human and natural environmental
effects which cannot be avoided; and
(n) Irreversible and irretrievable
commitments of resources.
108. The
application and the Environmental Assessment contain adequate information to
allow the Commission to consider these factors.
(a) Effects on Human Settlement
109. In
general, the effects on human settlement would be very limited due to the use
of a pre-existing plant site in an industrially zoned area. No population displacement or adverse impacts
on housing would occur as a direct result of project construction and
operation. The nearest residence is
1,300 feet to the southwest of the proposed location of the project.[124]
110. Area
aesthetics will not significantly change, because the site is already developed
and contains the existing Cambridge Station and its 25 MW fuel oil fired combustion
turbine. Although the proposed combustion
turbine will be larger than the existing facility, and two new water tanks will
be constructed, they will look similar to the existing plant.[125]
111. The
upgrade of the 69-kV transmission line in Isanti, Chisago and Kanabec counties would
involve changing to taller poles, upgrading wire size and adding lightning
protection. The lines would not appear
significantly different from existing line configurations.[126]
112. Exterior
lighting would be in accordance with the Illuminating Engineering Society
Handbook and code requirements.[127]
113. Some
construction noise would be unavoidable, but it would be predominantly
intermittent and short term.
Construction noise impacts should be mitigated by properly muffling
construction equipment and limiting activity during nighttime hours.[128]
114. The
proposed project would generate additional operational noise, but the combustion
turbine would be fitted with equipment to minimize the velocity of air moving
into the inlets and with silencers to reduce the noise of the exhaust leaving
the stacks. There is currently a high
level of low-frequency noise in the area due to busy highways near the site. Considering the existing level of background
noise and a negligible increase in noise levels from the combustion turbine,
GRE expects no discernable change in noise level to be perceived by the nearest
receptors.
115. There
would be increased truck traffic associated with construction in the short-term
and GRE operation and maintenance staff in the long-term. The additional traffic would not
significantly affect area transportation services.[129]
116. The
benefits to the immediate area and beyond would include temporary and permanent
job creation; additional property, income and sales tax revenues directly
attributable to the project; and the additional assurance that GRE has adequate
generating capacity in 2007 and beyond to reliably meet customer demand for
electricity.[130]
117. The estimated work force needed to construct
the project is approximately 75 skilled craft workers over the 12-month
construction period. The State of
118. The
project would have no adverse effect on any historical properties in the
vicinity of the site.[132]
119. No
significant recreational resource exists on or immediately adjacent to the
project. There should be no adverse
impact on any recreational opportunities.[133]
120. Public
services in
(b) Health and Safety
121. The
project would not have measurable impacts on public health and safety because
emissions will be minimized through the use of clean fuels. There will be no discernable change in the
level of noise. Although traffic volumes
will increase during the construction phase, additional traffic volumes during
normal operation attributable to the project would be minimal.[135]
122. The
impacts to ambient air quality are based on modeling using U.S. Environmental
Protection Agency-approved dispersion models (ISC3-Prime). Modeling results show that air quality
impacts would be below the Potential for Significant Deterioration significance
levels for all pertinent air pollutants.
The project should not have significant impact on the air quality, due
to the use of clean burning natural gas technology, dry low-NOX
emission control technology and limits on the total emissions.[136]
(c) Land-Based
Economies, Including Agriculture, Forestry, Tourism and Mining
123. No
effects on land-based economies are expected because the project would be
located within the footprint of an existing plant. The area is currently zoned industrial, and
the project would not change the land use of the area.[137]
(d) Effects on
Archaeological and Historical Resources
124. The
project would use existing transmission facilities and an existing plant
site. No archeological or historical
resources would be affected.[138]
(e) Effects
on the Natural Environment
125. Storm
water drainage patterns north of
126. The
Project should have no negative impacts on any wildlife in the area.[140]
127. Simple
cycle combustion turbine technology can operate without water, except for that
required for fire protection. The
project would be capable of using water to provide evaporative inlet air
cooling and wet compression power augmentation to sustain the cooler weather
capacity of the CT during the warmest days of the year. The estimated groundwater withdrawal rate would
be approximately 108 gallons per minute.
Evaporative cooling would be used to cool the air entering the units up
to about 20 percent of the time.[141]
(f) Effect on Rare and Unique Natural
Resources
128. Construction
of the CT should not impact the local vegetation of the area.[142] There are several areas of outstanding
biodiversity significance that could be affected by the upgrades to the
transmission lines. GRE must comply with
the recommendations of the Minnesota Department of Natural Resources to mitigate
and minimize these impacts.[143] In all other locations, the disturbance will
be limited to pole replacement and will be minimal.[144]
(g) Design Options That Maximize Energy
Efficiency, Mitigate Environmental Effects, Accommodation of Expansion
129. The
unit proposed for this project is relatively large with good efficiency
characteristics. It is large enough to
take advantage of scale economies within a single unit. The size of the project maximizes the value
of technological efficiencies, land use, and the transmission system.[145] A simple cycle combustion turbine is the most
appropriate generation technology for the peaking service need the project is
intended to address. Overall power
supply costs are minimized when a low capital cost resource like combustion
turbines are used in peaking service.
Peaking service also requires flexibility in operation, particularly
rapid and frequent startups and short-duration runs.[146]
130. The
project incorporates several features to minimize potential adverse environmental
effects associated with the construction and operation. These include design features, specific
resource protection measures, construction constraints and controls, and
operational programs.[147] For example:
· The predicted low noise levels result from
use of the best available noise control technology, including diffusers on the
air inlet of the combustion turbines and silencers on the stack to minimize the
impact of any noise.
· The project will be constructed to look like
the existing plant, exterior lighting will meet code requirements, and
night-time security lighting will point downward and inward.
· GRE will require its contractor to apply for
and comply with a construction storm water permit under the MPCA’s NPDES
Stormwater Permit Program for Construction Activities.
· The combustion turbine uses clean-burning
natural gas technology, dry low-and NOX emission control technology,
which limits total emissions and reduces the impact on air quality and
substantially reduces water consumption.
131. The
project site cannot accommodate future expansion without acquisition of
additional property or removal of the existing 25 MW turbine. GRE currently has no plans for further
expanding generating capacity at the proposed site.[148]
(h) Use or Paralleling of Existing
Rights-of-Way, Survey Lines, Natural Divisions Lines, and Agricultural Field
Boundaries
132. The
project would use existing 69-kV transmission facilities. No new rights-of-way are required, except as
required by county mandates to accommodate future road relocations.[149]
(i) Use of Existing Large Electric Power
Generating Plant Sites
133. The
project would use an existing plant site near
(j) Use of Existing Transportation, Pipeline,
and Electrical Transmission Systems or Rights-of-Way
134. The
project would use existing 69-kV transmission facilities. No new rights-of-way are required, except as
required by county mandates to accommodate future road relocations.[151]
(k) Electrical System Reliability
135. GRE
needs the proposed project to meet the peak demand needs of its members and
their owner/customers. In addition, the
transmission improvements associated with the project will help improve
transmission system reliability.[152]
(l) Costs of Constructing, Operating and
Maintaining the Facility Which Are Dependent on Design and Route
136. GRE
evaluated nine sites for the proposed combustion turbine. Based on considerations of transmission,
natural gas supply, land use, water availability, wastewater disposal,
transportation infrastructure, local support, economics and environmental
impacts, two sites were selected for further consideration—the
(m) Adverse Human, Natural and Environmental
Effects Which Cannot be Avoided as a Result of Construction and Operation of
the Plant
137. There
should be no significant adverse human, natural and environmental effects from
the project.[154]
(n) Irreversible and Irretrievable Commitments
of Resources
138. There
should be no irreversible or irretrievable commitments of resources.
Exclusions
Which Must be Avoided Under the
139. The
project would be located within the footprint of an existing plant in an
industrially zoned area and, therefore, does not involve any of the exclusions
identified under Minn. Rule 4400.3450, subps. 1, 3, and 4.[155]
Based on the foregoing Findings of
Fact, the Administrative Law Judge makes the following:
1.
The Minnesota Public Utilities Commission has jurisdiction
over this matter, pursuant to Minn. Stat. §§ 216B.08, 216B.243 and
116C.06.
2.
All relevant procedural requirements of law and rule have
been fulfilled.
3.
Based on GRE forecasts as supplemented by actual data for
2003 and 2004, there is a need for the proposed project.
4.
Increasing planned conservation efforts is not a
cost-effective alternative to the project.
5.
GRE does not significantly promote electricity consumption
in
6.
Current and planned facilities not requiring certificates of
need and purchased power are not adequate to meet projected needs.
7.
The project will make efficient use of existing resources
for transmission, pipelines, and land use.
8.
Denial of the Certificate of Need to GRE would likely have
an adverse effect upon the future adequacy, reliability and efficiency of
energy supply to GRE, to the member cooperatives that GRE serves, and to the
people of
9.
Considering the size, type, timing, costs, natural and
socioeconomic environmental effects, and reliability, a more reasonable and
prudent alternative to the project has not been demonstrated by a preponderance
of the evidence on the record.
10.
The project will provide benefits to society in a manner
compatible with protecting the natural and socioeconomic environments,
including human health.
11.
The record does not demonstrate that the design,
construction, or operation of the project will fail to comply with relevant
policies, rules, and regulations of other state and federal agencies and local
governments.
12.
GRE has demonstrated that it has explored the possibility of
generating power by means of renewable energy sources and has demonstrated that
the project is less expensive (including environmental costs) than power
generated by a renewable energy source.
13.
An innovative energy project would not be the best resource
to meet the need identified in this proceeding.
14.
GRE’s application satisfies the requirements for a
Certificate of Need set forth in Minn. Stat. § 216B.243 and Minn. Rules
Ch. 7849.
15.
GRE’s proposed site is acceptable under the provisions of
Minn. Stat. § 116.57, subd. 4, and
Based on the foregoing Conclusions, the
Administrative Law Judge makes the following:
1.
That the Commission grant GRE’s application for a
Certificate of Need for a 170 MW simple-cycle combustion turbine large electric
power generating plant without condition.
2.
That the Commission issue a Site Permit for the 170 MW
simple-cycle combustion turbine large electric power generating plant to be
located as proposed by GRE with any appropriate conditions.
Dated
this 3rd day of October, 2005
s/Kathleen D
Sheehy
KATHLEEN D.
SHEEHY
Administrative Law Judge
Under Minn. Stat. § 14.62, subd.
1, the agency is required to serve its final decision upon each party and the
Administrative Law Judge by first class mail or as otherwise provided by law.
Mankato Energy raised two issues
concerning GRE’s 2005 IRP: whether GRE
should use an independent evaluator in future RFP settings and whether GRE
should have used actual rather than generic data in its 2005 IRP. When GRE moved to strike this testimony during
the hearing, the Administrative Law Judge denied the motion in order to permit
Mankato Energy to develop the record on these issues, but permitted GRE to
respond. After review of the record and
further consideration, the Administrative Law Judge has concluded that these
issues are not related to whether a certificate of need or site permit should
be issued, and they are more appropriately raised in the docket addressing
GRE’s 2005 IRP.
K.D.S.
[1] At the time GRE filed its application, the authority to site power plants resided with the Minnesota Environmental Quality Board (EQB). Effective July 1, 2005, the authority to site power plants was transferred to the Commission by Minn. Laws 2005 Ch. 97, Art. 3, § 17.
[2] Ex. 1, § 1.1.
[3] Ex. 1, § 1.1
[4] EQB Ex. 5.
[5] EQB Ex. 4.
[6] EQB Ex. 6.
[7] EQB Ex. 8.
[8] EQB Ex. 9.
[9] The Commission published the Notice and Order for Hearing in the State Register in the April 18, 2005 issue at 29 S.R. 1211.
[10] EQB Ex. 10.
[11] EQB Ex. 13.
[12] EQB Ex. 13.
[13] EQB Ex. 14.
[14] EQB Ex. 15.
[15]
EQB Ex. 18.
[16] EQB Ex. 20.
[17] EQB Ex. 23.
[18] Public Hearing Transcript, July 28, 2005, Vols. 1 at 16-24 & 2 at 17-30.
[19] These comments have been marked as Exhibits 47 and 48, respectively.
[20] Second Prehearing Order dated June 13, 2005.
[21] Tr. at 186; Ex. 41 (Morton Direct) at 5-7.
[22] Ex. 1, § 3.12 & Appendix D.
[23] Ex. 1, §§ 2.1 3.0, 3.12 & Appendix D, 3.6.1; Ex. 31 (Rakow) at 3.
[24] Ex. 32 (Griffing) at 6-7; Ex. 30 (Sulzer) at 2-3.
[25] Minn. Stat. §§ 216B.243, subd. 2; 216B.2421, subd. 2(1).
[26] Minn. Stat. § 216B.243, subd. 3(a).
[27] Minn. Stat. § 216B.2422, subd. 1(c).
[28] Ex. 1, §4.1; Ex. 37 (Fang) at 7.
[30] Ex. 37 (Fang) at 8-9.
[31] Ex. 37 (Fang) at 9.
[32] Ex. 1, §§ 4.2.1 and 4.2.5; Ex. 37 (Fang) at 9.
[33] Ex. 37 (Fang) at 9; Ex. 1, § 4.2.2.
[34] Ex. 1, § 4.2.3.
[35] Ex. 1, § 4.6; Ex. 37 (Fang) at 8-10.
[36] Minn. Stat. § 216B.1694, subd. 2(4).
[37] Ex. 48, Comments of Excelsior Energy filed July 28, 2005.
[38] Ex. 1, § 2.1; Ex. 34 (Ham) at 2.
[39] Ex. 1, section 2.1.
[40] Tr. at 60.
[41] Ex. 1, Section 3.7.1.
[42] Tr. at 181-82.
[43] Tr. at 124.
[44] Tr. at 51; Tr. at 203-05.
[45] Ex. 46 (Collins) at 3-4.
[46] Tr. at 44-45, 58, 60; Ex. 46 (Collins) at 3-4.
[47] Tr. at 135.
[48] Ex. 22 (Pritchard) at 2. An applicant for a CON may use a forecast methodology of its own choosing, with due consideration given to cost, staffing requirements, and data availability. An applicant’s forecast is subject to tests of accuracy, reasonableness, and consistency. See Minn. R. 7849.0270, subp. 3.
[49] Ex. 34 (Ham) at 10.
[50] Ex. 15 (Beck Rebuttal) at 4; Ex. 46 (Collins) at 3-4.
[51] Ex. 34 (Ham) at 10; Ex. 31 (Rakow Direct) at 12; Tr. at 124.
[52] Ex. 34 (Ham) at 9-10.
[53] Ex. 1, § 2.4; Ex. 34 (Ham) at 10.
[54] Ex. 31 (Rakow) at 12.
[55] Ex. 1, § 2.4, 3.6.1.
[57] Ex. 1, § 3.4.
[58] Ex. 1, § 3.15.1.
[59] Ex. 1, § 4.4; Ex. 37 (Fang) at 15.
[60] Ex. 1, § 4.3; Ex. 34 (Ham) at 9-10.
[61] Ex. 37 (Fang) at 18.
[62] Ex. 37 (Fang) at 19.
[63] Ex. 1, § 4.4.4; Ex. 37 (Fang) at 17, 19.
[64] Ex. 1, § 4.4.4. ; Ex. 37 (Fang) at 14.
[65] Ex. 1, § 4.4.1.
[66] Ex. 1, § 4.4.1.
[67] Ex. 26 (Selander Rebuttal) at 12, SS-1.
[68] Tr. at 177.
[69] Tr. at 177-82.
[70] Ex. 25 (Selander Rebuttal) at 13; Tr. at 69.
[71] Ex. 1, § 4.4.3; Ex. 37 (Fang) at 20.
[72] Ex. 1, § 4.4.5.
[73] Ex. 1, § 4.4.5.
[74] Ex. 37 (Fang) at 20.
[75] Ex. 1, § 4.4.6.; Ex. 37 (Fang) at 18.
[76] Ex. 1, § 4.3 and Appendix C, §§ C.2 and C.3.
[77] Ex. 37 (Fang) at 20.
[78] Ex. 1, § 4.4.2.2; Ex. 37 (Fang) at 20.
[79] Ex. 1, § 4.2.3 and 4.5, Table 4-4; Ex. 37 (Fang) at 28-43.
[80] Ex. 1, Appendix C.2; Ex. 37 (Fang) at 21.
[81] Ex. 26 (Selander Rebuttal) at 5-7, SS-1.
[82] Ex. 26 (Selander) at SS-1. Mankato Energy included a rate of return of between 8% and 15% in its proposals to GRE. See Tr. 173. Because it is a cooperative, GRE’s proposals, on the other had, included no rate of return. See Tr. at 22.
[83] Ex. 25 (Selander Rebuttal) at 13.
[84] Ex. 25 (Selander Rebuttal) at 14.
[85] Mankato Energy argues that GRE cannot establish that its proposal is the least-cost alternative because its review of the proposals was not “transparent.” It also contends that GRE should have used a present value rate of return (PVRR) analysis, as is used in the resource planning process, instead of GRE’s “all-in” calculation of cost. GRE has provided all the information necessary to conclude that its review of the proposals was reasonable, see Ex. 39 (Fang) at 3, and there is no requirement that the expensive modeling used for resource planning purposes be used to evaluate purchased power alternatives. In the absence of some reason more compelling than the desire to promote transparency, the Administrative Law Judge cannot say that a PVRR analysis should have been used here.
[86] Ex. 1, Table 4-3.
[87] Ex. 1, Table 4-3.
[88] Ex. 37 (Fang), Table 12.
[89] Ex. 1, Table 4-3.
[90] Ex. 1, § 3.23.
[91] Ex. 1, § 3.6.1; Ex. 41 (Griffing) at 6-7.
[92] Ex. 1, Table 4-3.
[93] Ex. 46 (Morton) at 5.
[94] Ex. 46 (Morton Direct) at 4-5; Ex. 1 at 1.
[95] Ex. 26 (Selander Rebuttal) at 14-15; Tr. 103-05.
[96] EQB Ex. 15, § 6.8.
[97] EQB Ex. 3, section 4.5.4; EQB Ex. 15, section 6.7.
[98] Ex. 3, § 3.8; EQB Ex. 3, § 4.5.4; EQB Ex. 15, §6.7.
[99] Ex. 1, § 3.8.
[100] Ex. 1, § 6.3.
[101] Ex. 37 (Fang) at 44.
[102] Tr. at 160, 164; Ex. 25 (Selander Rebuttal) at 10, Ex. SS-2.
[103] Ex. 25 (Selander Rebuttal) at 11.
[104] Tr. at 188-90.
[105] Tr. at 164.
[106] Tr. at 166.
[108] Tr. at 191.
[109] Ex. 1, § 5 and App. B.
[110] Ex. 1, § 5.
[111] Ex. 1, § 5.
[112] Ex. 1, §§ 3.14, 3.20, 3.21, & 3.24.
[113] Ex. 1., § 6.3.
[114] EQB Ex. 3, § 4.5.4; EQB Ex.15, § 6.7.
[115] Ex. 3, § 3.8; Ex. 1, § 2.4.
[116] Ex. 31 (Rakow) at 13-14.
[117] EQB Ex. 3, §§ 3.1.1, 3.1.4, 3.4, 4.2.2 and Fig. 3-1; EQB Ex. 15, §§ 2.1.1, 2.1.3 and 2.1.4.
[118] EQB Ex. 3, § 3.1.3 and Fig. 3‑3; EQB Ex. 15, § 2.1.6; Ex. 30 (Sulzer) at 3.
[119] EQB Ex. 3, § 3.1.2 and Fig. 3-2; EQB Ex. 15, § 2.1.8.
[120] EQB Ex. 3, § 3.1.4 and Fig. 3-4; EQB Ex. 15, § 2.1.3.
[122] EQB Ex. 3, § 4.2.2; EQB Ex. 15, § 2.1.4.
[123] EQB Ex. 3, § 4.2.2; EQB Ex. 15, § 2.1.4.
[124] EQB Ex. 3, § 4.4.3 and Fig. 4-1; EQB Ex. 15, § 6.2 and Fig. 2.
[126] EQB Ex. 3, § 4.4.2.
[127] EQB Ex. 15, § 6.4.
[128] EQB Ex. 3, § 4.3.
[130] EQB Ex. 3, §§ 1.1 and 4.5.4; EQB Ex. 15, § 6.7.
[132] EQB Ex. 3, § 4.5.3; EQB Ex. 15, § 6.5.
[133] EQB Ex. 3, § 4.5.1; EQB Ex. 15, § 6.3.
[134] EQB Ex. 15, § 6.11.
[135] EQB Ex. 3, §§ 4.1, 4.3 and 4.5.2; EQB Ex. 15, §§ 6.1 and 6.6.
[136] EQB Ex. 3, § 4.1; EQB Ex. 15, § 6.1 and Table 12.
[137] EQB Ex. 3, § 4.4.3; EQB Ex. 15, §§ 6.2 and 6.3.
[138] EQB. Ex. 3, § 4.5.3; EQB Ex. 15, § 5.5.
[139] EQB Ex. 3, § 4.6.2; EQB Ex. 15, § 6.8.
[140] EQB Ex. 3, § 4.6.4; EQB Ex. 15, § 6.3.
[141] EQB Ex. 3, § 3.1.4 and Table 3-1; EQB Ex. 15, § 2.1.3.
[142] EQB Ex. 3, § 4.6.3; EQB Ex. 15, § 6.3.
[143] Ex. 47.
[144] EQB Ex. 3, § 4.6.3.
[145] EQB Ex. 3, § 3.
[146] Ex. 1, § 3.
[147] EQB Ex. 3, §§ 4.3, 4.1 and 3.1.4; EQB Ex. 15, §§ 6.4, 3.5, 6.1 and 2.1.3.
[148] EQB Ex. 3, § 2.4.
[149] See EQB Ex. 3, § 3.1.2 and Fig. 3-2; EQB Ex. 15, § 2.1.8.
[150] EQB Ex. 15, Section 2.1 and Fig. 1.
[151] See EQB Ex. 3, § 3.1.2 and Fig. 3-2; EQB Ex. 15, § 2.1.8.
[152] Ex. 1, § 2.4.
[153] EQB Ex. 15, § 4.9.
[154] EQB Ex. 3, § 4.
[155] EQB Ex. 3, § 4.4.