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BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE JUNE 6, 1991
1. CALL TO ORDER
CHAIRMAN MIKE KELLY called the Bradley Lake Project Management
Committee to order at 10:10 a.m. in the Training Room at the offices of
Chugach Electric Association to conduct the business of the Committee per the agenda and the public notice.
2. ROLL CALL
Roll was called and a quorum was established. The following individuals were present:
Alaska Energy Authority
Charlie Bussell, Representative
Brent Petrie, Alternate
Chugach Electric Association David L. Highers, Representative
Tom Lovas, Alternate
Golden Valley Electric Association Mike Kelly, Representative and Chairman
City of Seward E. Paul Diener, Representative
Homer Electric Association Norm Story, Representative (arrived at 10:20 a.m.)
Matanuska Electric Association
Ken Ritchey, Representative
Municipal Light & Power
Tom Stahr, Representative
Hank Nikkels, Alternate
Others present:
Tim McConnell, Municipal Light & Power
Bob Hufman, Alaska Electric Generation & Transmission John Cooley, Chugach Electric Association
Jim Woodcock, Matanuska Electric Association Ron Saxton, Purchasing Utilities Terri Ganthner, Alaska Energy Authority Stan Sieczkowski, Alaska Energy Authority Dave Eberle, Alaska Energy Authority
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Dave Fair, Homer Electric Association Gene Borjnstead, Chugach Electric Association Mo Aslam, Municipal Light & Power Dave Burlingame, Chugach Electric Association Joe Griffith, Chugach Electric Association
3: PUBLIC COMMENT
There was no public comment.
4. MODIFICATION OF AGENDA
Under Item 8, Budget Subcommittee, Item b, Chugach Wheeling was modified to read "Chugach Dispatch." The modified agenda was approved without objection.
3: APPROVAL OF MINUTES - March 5, 1991
CHAIRMAN KELLY asked for objections to the approval of the March 5,
1991, minutes. Hearing no objection, CHAIRM. KELLY stated _ the
meeting minutes were approved as distributed.
6. TECHNICAL COORDINATING SUBCOMMITTEE REPORT
MR. DAVID BURLINGAME, Technical Coordinating Subcommittee (TCS representative, stated that the TCS has met twice since the last BPM
meeting and distributed copies of a summary meeting report for the benefit of Committee members. MR. BURLINGAME addressed items covered in the report:
Bradley Lake Constraints: Power Technologies, Inc., (PTI) has completed their study of operating restraints for the testing and commissioning phase for
Bradley Lake. PTI recommends that the system remain interconnected, with
no testing to be completed while the system is islanded. During the smaller load rejection tests of up to 60 megawatts, the system should have twice the
expected load rejection in spinning reserves. At the higher load rejections of up to 90 megawatts (MW), which AEA proposes to do, PTI has recommended at least 3 times the level of spinning reserve than the expected
load rejection which is roughly 2 % times what would normally be carried by
the utilities. Normal allocations would be shifted between the utilities, with Chugach, ML&P and AEG&T carrying all of the spinning reserve prior to the
test. Verification of sufficient machines available to supply spinning reserve would need to be made by the utilities.
MR. BURLINGAME recommended that the PMC direct the Dispatch and Scheduling Subcommittee develop a method for tracking and accounting for
costs associated with dispatching during generation tests from Bradley Lake.
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Interim Operating Study: PTI has completed the first phase of the interim operating study. This study sets the upper limits for operation of Bradley
Lake at 80 MW, with three turbines on-line at Bernice Lake. These restrictions were adopted by the TCS Subcommittee. Operation of the
‘oject at 80 MW is below the planned testing level by the Authority of 90 Mw. The TCS has requested that Stone and Webster Engineering Corporation (SWEC) gather all operating restrictions and recommendations related to Bradley Lake within the past 2-3 years into one document for
reference.
Bradley Lake Minimums: MR. BURLINGAME related that at a prior PMC meeting, the TCS had been directed to establish Bradley Lake minimums (i.e.,
maximum Kenai imports without a gas turbine on-line) for an expected reasonable level of load shedding. The TCS has agreed on the test cases
required to develop those minimums. PTI will complete the study with the
existing load shedding schedule and present the results to the TCS at a later date.
Islanded Operation: Studies determining constraints on Bradley Lake during
an islanded operation have not been started by PTI. It was noted that operation of all four Kenai area turbines would not prevent Kenai load shedding over 32 MW with the loss of one Bradley unit. The TCS will be
addressing these operating constraints over the next few weeks.
Transfer Tripping Installation: The TCS has approved the installation of
transfer tripping at Soldotna, Quartz Creek and Bernice Lake. Transfer tripping was also approved from Dave's Creek to Soldotna which would allow a higher operating limit for Bradley Lake prior to the SVS systems going on- line.
Testing/Commercial Operation: The TCS has requested that the PMC
address or delegate to a subcommittee the issue of commercial operation.
CHAIRMAN KELLY questioned DAVE EBERLE, Bradley Project Manager, if a start-up and test plan was being discussed at this time with the TCS. MR. DAVE EBERLE stated that the TCS has been briefed on the
planned tests and progress of the testing. There has been no feedback regarding additional tests from the utilities. MR. BURLINGAME stated the
utilities would need to develop operating or reliability criteria to schedule the
units at various loads and for certain periods of time. The Authority's planned tests deal only with commissioning and verification of control and are not considered normal utility operation.
CHAIRMAN KELLY questioned MR. EBERLE as to the intended
declaration of commercial operation dates, transmission capabilities and further testing of the units. MR. EBERLE stated that the current plan is to
synchronize the units the week of June 10. Load rejection tests will not be
completed until July. Based on the current schedule, all tests will be completed by July 26 and in terms of the Power Sales Agreement, the project could be declared commercially operational on July 26. AEA's intent,
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however, is to allow the utilities to test the system for 30 days and declare it commercially operational on September 1.
Status Transfer Tripping Installation: MR. BURLINGAME briefed the Committee on the remaining TCS items. Transfer tripping of the 115 lines which has basically kept Homer from energizing the line from Soldotna to
Bradley Junction has been delayed due to wrong and/or broken parts. These parts are expected to be in the week on June 10. Peas of the line, RTU and Bradley will be energized in the same week. The Bradley Lake RTU for
Chugach ee is installed and — the Diamond Ridge RTU installed by Homer and monitored by Chugach should be operational by the
end of the week of June 3. The SVS systems proposals have been received and are under review.
MR. STORY joined the meeting at 10:20 a.m.
Te OPERATION AND DISPATCH SUBCOMMITTEE REPORT
MR. STAN SIECZKOWSKI stated that the Operation and Dispatch Committee met March 27, April 11 and May 16, to discuss issues and develop plans for the following:
Load restoration procedures have been discussed with no resolution at this
time. A proposal from Chugach is currently under review by the Subcommittee regarding loss and billing procedures. MR. SIECZKOWSKI
distributed copies of an Agreement Schedule showing assignments and rogress dates for review of various agreements related to Bradley Lake. The
ubcommittee is recommending the acceptance of the Allocation and Scheduling Agreement dated May 17, 1991, subject to completion of the reservoir operation model and project operating criteria relating to unit condition mode operation, islanding and _ deflector modes. CHAIRMAN KELLY stated that this item would be placed on the agenda for discussion at the July 2 BPMC meeting. Spinning reserves and peaking operation has been tabled until more information is available.
MR. DAVE HIGHERS Chugach Electric, questioned MR. SIECZKOWSKI as to the current level of water and levels predicted for the remainder of the year. MR.SIECZKOWSKI deferred the question to MR.EBERLE.
MR. EBERLE stated that the reservoir level was at 1,093 feet and gaining
between 3-5 feet a week. Significant run-offs begin the end of June and
continue through July, with peak at the end of July and early August. The
snow pack is within 10 percent of the normal range; however, the Homer area is below the normal average and the far side of the Kenai mountains is above
normal. MR. EBERLE stated staff is continuing to monitor the situation and will have more information at the end of the month.
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8. BUDGET SUBCOMMITTEE
MR. KEN RITCHEY stated that the operating budget, to include a cash flow
analysis for the projection of debt service payments, was approved at the February 1991 meeting. At a meeting on May 29, Subcommittee members
noted that the cash flow analysis overstated the operating reserve fund by
$300,000. MR. RITCHEY stated that a recommendation of the Committee would be to use funds in the Operating Fund; another recommendation may
be to delay payment of certain expenses until January. A second issue facing the Subcommittee is payment dates; MR. RON SAXTON stated that the Committee is obligated to have funds available to make debt service
payments and operating payments when they are due and that the time of payment should be optional. An option for the Committee would be to have
each utility make an advance payment. MR. RITCHEY stated that this item would be on the July 2 agenda for further discussion by the PMC.
MR. RITCHEY discussed the Chugach Wheeling rates and cost components that make up the wheeling rate as proposed by Chugach. A handout of the
rates set by Chugach were distributed to Committee members. The second page of the handout was a worksheet used in a February 1988 analysis of
Bradley Lake costs. This document was used as a reference by Budget Subcommittee members in forecasting future rates and calculations.
Discussion on segregation of Beluga and Point McKenzie costs, applicability of the inflation rate for transmission services a and application of
wheeling rates were discussed. MR. RITCHEY stated that it was the feeling of the Subcommittee that the wheeling rate adjustment should be calculated
and implemented on each filing that Chugach makes with the Alaska Public
Utilities Commission which ultimately leads to a rate change, with a test adjustment made each quarter. The Subcommittee would be able to track
these costs easier on a quarterly basis.
MR. RITCHEY stated the Homer Wheeling and Chugach Dispatch items
would be discussed at the July 2 meeting.
9. INSURANCE SUBCOMMITTEE REPORT
MR. BRENT PETRIE stated that the Subcommittee, with the assistance of
the Division of Risk Management, is looking to Corroon & Black for a
provider interested in providing Boiler and Machinery as well as Business interruption insurance. The current insurance company would provide
coverage for flood, fire, earthquakes, etc. The Subcommittee will be
responding to two major questionnaires regarding this insurance; copies of the questionnaires were distributed to the Insurance Subcommittee at this
time. MR. PETRIE went on the say that the drought coverage had been discussed by the Subcommittee, with information to be provided to the interested providers. MR. PETRIE was questioned as to whether this
insurance included payment of debt service payment in the event of a loss at the project. MR. PETRIE stated that the Subcommittee is looking at
coverage of debt service payment and operation and maintenance debt
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service payment for at least one year. The company apparently is interested in writing a policy for 10 years that could be renewed on a year-to-year basis, applicable to each occurrence.
10. | REVIEW OF PROJECT STATUS
MR. EBERLE stated that overall, the project is 94 percent complete. This
percentage includes the remaining site rehabilitation contract and SVS
equipment purchase and installation. The work that controls commercial operation is actually 99 percent complete. The general civil contractor is
completing the diversion tunnel, gatehouse and fish water by-pass system. Punch list items and general clean-up of the site is also underway. Start-up
testing of the units is continuing, with both units having been rolled and the
first synchronization of the units is planned for the week of June 10. The units will be loaded at 5 percent, and upgraded at 5 percent increments. Unit
rejection tests will take place July 8; PTI will be on-site and will have
equipment in place to measure the response. The Authority's anticipated date for completing all tests is July 26. A falling head test to vetify the integrity of the tunnel and leakage was completed on May 22. Over a 12 hour
period, the average leakage from the tunnel was only 58 gallons per minute.: There are no plans at this time to dewater the tunnel. The reservoir filling
progressed slowly over the winter; after shutting down the fish water by-pass
system on April 26, the reservoir has been filling fairly rapidly. The current level of water in the reservoir is 1, 093 feet, filling a little over 20 feet since last fall. Spill level is 1,180 feet; an additional 87 feet will bring the reservoir to normal spill level.
11. | NEW BUSINESS
A. CHAIRMAN KELLY introduced MR. BUSSELL as the Authority's Executive Director and welcomed him to the PMC meeting.
B. Bradley Agreements Committee Appointments
CHAIRMAN KELLY stated that a committee would be selected to
identify all agreements that must be in place, set a time table and assign to certain individuals the responsibility of completion of these agreements. Individuals selected for this committee included
Stan Sieczkowski, Marv Riddle, Ron Saxton and Tom _ Lovas. CHAIRMAN KELLY charged this committee to meet as soon as
possible in order to consolidate these agreements.
C. Bradley Start-Up and Commercial Operation
MR. BURLINGAME stated two issues regarding commercial start-up and operation included 1) operation of the plant at 90 MW without
stability aids, with the risk of system losses to be shared by all the participants and 2) development of proposed operating scenarios from a utility standpoint by the TSC to insure the unit is available for
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commercial operation. CHAIRMAN KELLY stated he had asked MR. RON SAXT ON to look at this issue for timing of commercial
operation and what the PMC and AEA have agreed to. MR. SAXTON stated that the water level is not clear under the Power Sales Agreement (PSA), but that commercial operation is the date the
engineers reasonably declare the project is fully available to the operators at not less than 90 MW. Length of operation at the 90 MW
level, reasonable operation and scheduling output on a commercial
basis is required although the length of operation at the 90 MW level is not covered under the PSA. MR. EBERLE stated that the lack of
water should not be an issue relative to commercial operation - commercial operation states the unit must run at 90 MW. The PSA
recognizes that there may be variability in water over the years, but that the price paid for the energy is fixed regardless of the amount of
energy provide by the project.
MR. SAXTON also stated that under the revenue bonds, September 1
was listed as the date of convenience for payments to begin by the utilities to meet the debt obligations and service obligations. The bond
issuance did not include funds for capitalizing any further interest after September 1 and if the payments are not made by the utilities, there is
no source of revenue other than the reserve funds. Second, there is
the danger of damaging the bonds tax exempt status. MR. SAXTON eclieested that the Ritosty 's engineers have the right to declare the
project commercially ae and once declared, the contract
expressly states the utilities are obligated to begin making their payments.
CHAIRMAN KELLY stated he was concerned with limiting the project at 80 MW or having a potential out-of-step problem with the
loss of a unit and questioned the risk to the utilities above 80 MW.
MR. BURLINGAME stated that two utilities would primarily be affected, but that the TCS should not decide on the amount of risk allocation to the various participants. He stated the TCS should be involved in defining the operating and testing restraints they want the project to perform under to satisfy their general managers. CHAIRMAN KELLY questioned the method used by the Authority in testing the units; MR. EBERLE stated the Authority will test each unit separately to its full output (63 megawatts) and then load them in combination to the extent that the utilities are able to take the power.
CHAIRMAN __ KELLY __ instructed the TCS, _ through
MR. BURLINGAME, to develop operating scenarios with 80 MW and 90 MW caps. There was no objection by the Committee.
Discussion began on commercial output to be scheduled from Bradley. CHAIRMAN KELLY questioned the operation of the Bernice Lake turbine under an obligation by Chugach to Homer Electric. MR. HIGHERS stated this turbine would be on-line due to the
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absence of the second transmission line prior to Bradley Lake operation. MR. BURLINGAME stated that this turbine was not required with the operation of Bradley; this turbine is only required to expand the operating limits of Bradley. MR. STAHR stated that he does realize that the lack of an intertie limits output from the project,
however, stressed that the cost of burning fuel as opposed to using the spinning reserves was just as valuable and he expected his utility to receive this spin reserve. MR. BURLINGAME stated that the TCS has yet to establish the value of how much spinning reserve is available from Bradley Lake during normal operation of gas turbines but that Bradley was essentially able to contribute up to the 120 MW capacity
at peak for spinning reserve, limited only by transmission line constraints. After installation of the SVS', the project can be
scheduled at 120 MW. The minimum operating limit will not go away
for the life of the project.
CHAIRMAN KELLY adjourned the meeting for a short break at 12:20 p.m. The meeting reconvened at 12:30 p.m.
CHAIRMAN KELLY restated the issues as discussed previously by the Committee. Additional comments regarding load shedding, response time of the turbines and additional funds to correct any
design flaws were also discussed at length by the Committee. MR.TOM STAHR stated that once the project is declared
operational, the utilities would be responsible for projects costs after that point and suggested that a limited agreement between the
Authority and the utilities be researched and/or implemented until installation of the SVS system. MR. CHARLIE BUSSELL stated that
per the bonds, partial operation of the facility can not and would not be declared. MR. HIGHERS stated that the Authority has indicated they will provide funding for the SVS system and attempt to solve any
stability problems perceived by the utilities, but questioned support
from the Authority through encumbrance of funds to be held for
completing any additional required project construction. MR.SAXTON stated that there two separate concepts - the
declaration of the commercial operation date of the project and 50-50
matching funds tied to the cost and acquisition and construction which
are considered construction costs until the $350,000,000 limit is
reached. MR. PETRIE stated the earlier these project construction
funds could be released would be December 1992, and this must be completed through legislative action. MR. STAHR requested that a
resolution to encumber these funds as related to the commercial
operation date be prepared by the Committee. MR. PETRIE and
MR. SAXTON were tasked with the resolution, with MR. SAXTON to
prepare the first draft of the resolution for discussion at the next
meeting.
The Committee also discussed briefly the cost of operating gas
turbines to support project testing. Chugach will continue to run the
D.
turbine at Bernice Lake during the test period and should be
reimbursed for operating costs during this time frame. CHAIRMAN KELLY stated this issue should be placed on the July 2
agenda for further discussion.
Approval of PMC Expenses
MR. SAXTON stated that some utilities had not turned in the necessary backup for unreimbursed costs. MR. SAXTON handed out a memorandum from Marcey Rawitscher which stated that backup documentation is required and reimbursement will be made to Seward, Golden Valley and Ater Wynne. MR. HIGHERS moved, seconded by MR. DIENER for approval of PMC expenses. Roll was called and the
motion passed unanimously.
Two additional items were added to the agenda at this time.
MR. BURLINGAME distributed a memorandum stating these items for the benefit of the Committee. MR. HIGHERS summarized the
first motion for the benefit of Committee members. Motion 1 requests that the PMC authorize Chugach to install transfer tripping of its capacitor bank at Soldotna from Dave's Creek at a cost not to exceed
$30,000. Transfer tripping of the capacitors will enable a higher output of Bradley Lake during the interim ren re MR. HIGHERS moved for adoption of motion 1; MR. RITCHEY seconded _the
motion. Roll was called_and the motion was approved without objection. The second item was a motion for the PMC to authorize the
installation of transfer tripping on the Bernice Lake-Soldotna,
Soldotna-Quartz Creek 69 kV circuits at a cost not to exceed $100,000 for HEA at Soldotna and not to exceed $30,000 total for Chugach at Bernice Lake and Quartz Creek. MR. STORY moved adoption of the motion, MR. RITCHEY seconded. MR. HIGHERS amended the
motion to table this item to the next meeting. MR. RITCHEY agreed
to second the motion to table.
Schedule Next Meeting
July 2, 1991 Chugach Electric Association Training Room 10:00 a.m.
12. COMMUNICATIONS
MR. EBERLE distributed handouts to members of the Committee, informing them of the possible construction of an additional diversion in the Upper
Battle Creek Drainage Basin. The benefit/cost ration of the small diversion
looks very favorable, and could potentially be constructed this summer. A Federal Energy Regulatory Commission (FERC) license amendment is required and AEA is proceeding with this request to FERC. The diversion
will be
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discussed further at the July 2 meeting.
13 ADJOURNMENT
Having no further business to bring before the Committee, the meeting was adjourned at 1:55 p.m.
“MA.
Chairman Mickéel Kelly A
A ;
Secretary
Approved by PMC at meeting held July 2, 1991.
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Tape 1, Side 1
CHAIRMAN KELLY
TIM MCCONNELL:
CHAIRMAN KELLY
HANK NIKKELS
MO ASLAM
PAUL DIENER
myself.
KEN RITCHEY
JIM WOODCOCK
JOHN COOLEY
TOM LOVAS
DAVE BURLINGAME
DAVE HIGHERS
BOB HUFMAN
GENE BJORNSTEAD
JOE GRIFFITH
RECORD LOPY FILE NO
PRO 3-1,' m™ vd
ue /te 144
BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE MEETING JUNE 6, 1991 \ 10:00 A.M.
Let’s go ahead and call the meeting to
order. We have quite a few new players
today....Let’s go around the room since
we do have a lot of new players and
introduce one another. I’m a little
worried that Stahr who usually comes with
one representative has got Mo, he’s got
Hank, he’s got the clan then Chugach,
Cooley. Who the heck else? You know,
you’ve got Tim here...over here...what’s
going on here today?
I’m actually Cooley’s replacement or
successor since he’s irreplaceable but
Let’s go around starting with Hank.
Hank Nikkels, ML&P.
Moe Aslam, ML&P.
I’m Paul Diener from Seward all by
I’m Ken Ritchey with MEA.
Jim Woodcock with MEA.
John Cooley with Chugach.
Tom Lovas, Chugach Electric.
Dave Burlingame, Chugach.
Dave Highers, Homer .... Chugach.
Bob Hufman, AEG&T and I’m in bad company
here. Wait till Story sees me.
Gene Bjornstead, Chugach.
Joe Griffith, Chugach.
Bradley Lake Project Management
Committee Transcript
June 6, 1991
Page 2
TIM MCCONNELL
STAN SIEZCKOWKSI
TERRI GANTHNER
BRENT PETRIE
CHARLIE BUSSELL
RON SAXTON
MIKE KELLY
JIM WOODCOCK
CHAIRMAN KELLY
MOE ASLAM
CHAIRMAN KELLY
DAVE HIGHERS
CHAIRMAN KELLY
TERRI GANTHNER
CHAIRMAN KELLY
Tim McConnell, ML&P.
Stan Sieczkowski, Alaska Energy
Authority.
Terri Ganthner, AEA.
Brent Petrie, Alaska Energy Authority.
I’m Charlie Bussell, AEA.
Ron Saxton, attorney for the utilities.
Mike Kelly with Golden Valley. Let’s see
I guess, Jim with MEA, what, just to get
kind of familiar maybe you could let us
know what .... Jim’s the new face ....
Jim Woodcock with MEA responsible for the
administrative function. Prior to
joining MEA in April, I worked 16 years
with Portland General Electric, an
investor-owned utility in Portland,
Oregon. In fact, I was directed involved
in the decision to hire Ron’s wife, Lynn,
to work in the department when they moved
down from Alaska.
Okay, and Moe, you’re the new chief
Moe Aslam ... engineer ... appointed
Chief Engineer. I worked for Golden
Valley for 3 years and now at ML&P.
Okay, Tim McConnell we/’ve met.
We’ve got Cooley here ....
He’s a plant ... we all know that ... I
think you all know Hank - no job change
there and we’1ll go ahead and get started
on the minutes. DeAnna is not going to
be with today so we’ve got Terri helping
us and Terri, by that introduction, I did
what you asked me to do, didn’t I?
Thank you very much, I appreciate it.
Certainly. Would you take the roll
please?
Bradley Lake Project Management
Committee Transcript June 6, 1991
Page 3
TERRI GANTHNER
PAUL DIENER
TERRI GANTHNER
KEN RITCHEY
TERRI GANTHNER
DAVE HIGHERS
TERRI GANTHNER
CHAIRMAN KELLY
TERRI GANTHNER
TOM STAHR
TERRI GANTHNER
CHARLIE BUSSELL
CHAIRMAN KELLY
BOB HUFMAN
CHAIRMAN KELLY
DAVE BURLINGAME
City of Seward?
Here.
Matanuska Electric?
Here.
Chugach Electric?
Here.
Homer Electric?
Golden Valley Electric?
Here.
Municipal Light & Power?
Here.
Alaska Energy Authority?
Here.
Okay, thank you Terri. Anyone know ...
Norm plans to be here as far as you know?
Yes. I talked to him, oh, 45 minutes ago.
He was essentially on his way from Kenai.
Okay. Is there any modification to the
agenda? We passed out a slight revision
that Terri put in front of each place.
Without objection we’ll proceed with that
agenda. Is there objection to approval
of the March 5 minutes? Hearing no
objection, those minutes are approved as
distributed. Technical Coordinating
Subcommittee report, Dave Burlingame
would you take care of that?
I passed out a meeting summary report
did enough copies go around? Anyway,
basically the TCS has met a couple times
since the last PMC meeting. Nothing has
really be resolved ... we’re still
waiting on some on-going test reports
from PTI. There’s a couple of things
Bradley Lake Project Management
Committee Transcript
June 6,
Page 4
1991
that have come out during these test
reports ... they have completed the test
reports required for the testing and
commissioning of Bradley Lake ... and it
has been recommended that for the testing
and commissioning of Bradley Lake that
the system remain interconnected and no
testing be done while the system is
islanded. And during the smaller load
rejection tests of up to 60 megawatts,
the system should have twice the expected
load rejection in spinning reserves which
until you hit, you know, 45 or 50
megawatts in the summer, that essentially
what we have on-line now. The only
difference is that it’s going to be
shifted around. Fairbanks requested to
have no spin reserve on line with the
combustion turbines and the Kenai is
supposed to have extra spinning reserve
on-line. At the higher load rejections,
90 megawatts which is what AEA proposes
to do, the ... PTI has recommended at
least three times the level of spinning
reserve than the expected load rejection
which is roughly 2 1/2 times what we’d
normally be carrying. And again, that
will be shifted around different than the
normal allocation with Fairbanks carrying
none and Chugach, ML&P and AEG&T I guess
carrying all of the spinning reserve
prior to those tests. The utilities need
++. we need to verify that we’re going to
have that spinning reserve available ...
this is the biggest thing, and the
Dispatch and Scheduling Subcommittee
would recommend that the PMC direct them
to develop some method of tracking and
accounting for the costs associated with
the dispatch costs associated with the
generating tests from Bradley Lake.
PTI has completed the first phase of the
interim operating study. This phase of
interim operating study dealt with what
levels of export power or what levels of
Bradley Lake would be restricted to and
those cases were where the Kenai was the
net exporter of power. Those have been
adopted by the TCS with a couple of
clarifications requested and those are
Bradley Lake Project Management
Committee Transcript
June 6, 1991
Page 5
CHAIRMAN KELLY
DAVE BURLINGAME
expected to be finalized by the ...
within a week or two. Basically it sets
the limits at 80 megawatts with ... 80
megawatts is considering that all three
turbines are on-line at Bernice Lake.
And you should note that the 80 megawatt
is above ... is below the planned desired
testing level of 90 megawatts ... Bradley
Lake testing.
Dave would you explain that just a little
more.
Well there’s two studies. One study was
done to determine ... okay on a scheduled
basis, what would be the maximum level of
Bradley Lake power that could be
scheduled and to stay within the
stability and voltage restraints adopted
by the TCS and that was determined to be
80 megawatts and that’s the maximum case
on the ... I believe that’s winter loads
actually. In summer, it’s a little bit
less. In addition to that is a separate
study ... PTI was requested to determine
what kind of generation support is
required to ... for the Energy Authority
to be able to do the tests that they plan
for Bradley Lake. One of the tests they
plan is to be able to bring the unit up
to 90 megawatts. Short ... fail to bring
the units up to 90 megawatts and trip the
unit, you have to have the spinning
reserve we talked about before but while
you’re running above that 80 megawatt
level, if something else happened in the
system and there’s actually faults on any
of the three lines between Soldotna and
Bradley, Soldotna and Quartz Creek or
Quartz Creek and Dave’s Creek, the system
has the potential for going out of step
or incurring excessive voltage deviations
so the two are in conflict although one
of them ... the one study says for 90
megawatts you’re fine if all you’re going
to do is strop the unit but if you’re
running the unit at 90 megawatts and you
have something else happen, you’re in
trouble. The system is at risk any time
the units are run above 80.
Bradley Lake Project Management
Committee Transcript June 6, 1991 Page 6
CHAIRMAN KELLY
DAVE BURLINGAME
CHAIRMAN KELLY
DAVE BURLINGAME
Now distinguish between the test and a
normal operation situation. The 90
megawatt ... or the 80 megawatts is the
limits notwithstanding the triple blow
situation that you referred to before?
80 megawatts is the limit in terms of if
you want to find what is the limit in
terms of the system, you know, what the
system can withstand under any outages,
any contingencies. 90 megawatts with
three times the amount of spinning
reserve is the limit based on just
tripping Bradley. It’s the only study
that was done that it was studied at 90
And avoiding loadshed.
And avoiding loadshed. One of the things
that the TCS has requested SWEC to do was
to gather all of the studies and
limitations and recommendations made over
the past 2 or 3 years for Bradley Lake
into one document ... there seems to be a
lot of confusion running around that
these studies have been modified over the
past couple of years so we’ve requested
that they put together the latest and
greatest for a brief synopsis for
everybody.
On the Bradley Lake minimums which was a
--. PMC passed a motion directing the TCS
to establish the Bradley Lake minimums on
the expected reasonable level of load
shedding primarily by Homer. We have
agreed on the test cases required to
develop those minimums and PTI is running
them right now. We haven’t seen any
results of the load shedding study yet.
On the Islanded Operation which is kind
of tied in with the Bradley Lake
minimums, they haven’t started these
studies to look specifically if there are
any limits on Bradley Lake during
islanded operation. One of the things
they did when they were looking at the
testing case to determine if Bradley Lake
could be tested during islanded
Bradley Lake Project Management
Committee Transcript June 6, 1991
Page 7
CHAIRMAN KELLY
operation, there was, they started all
four turbines on the Kenai, gas turbines,
and even with all four turbines, Bradley
could only run at 33 megawatts if they
were going to survive the loss of the
largest contingency on the island ... on
the Kenai which would be Bradley. The
only difference being is that that would
be to take you totally out of loadshed
but it’s not a real good indication but
at least it gives you an idea of what we
could be faced with. The TCS will be
finalizing those limits within the next
month. The TCS approved transfer
tripping at several locations. Dave
Eberle asked me to tell you that it was
not unanimous and those were basically at
Soldotna, Quartz Creek and Bernice Lake.
They also approved transfer tripping from
Dave’s Creek to Soldotna which was
unanimous which would allow a higher
operating limit for Bradley Lake during,
before the SVS come up. One of the
Subcommittees to the TCS has requested
that the PMC either address itself or
delegate to a subcommittee to address the
question of commercial operation and I
... after we drafted this, I see it’s
already on the agenda. You know, a
couple of things that came up in the
subcommittee meeting was, you know, what
kind of tests were the utilities required
to say that yeah, everything’s a-okay and
also the question as to do you test it
above the stability limit of the system?
Do you run it at 90 megawatts if the
stability limit is in the winter 80 or
any particular generation it
might be 65. Do you run it above the
stability limit? The TCS is requesting
the PMC for or asking the PMC for
direction either to itself or to another
subcommittee.
Just on that issue, Dave, to Dave Eberle,
we had talked about a start-up and test
plan ... is that something that has been
shared at this point with the TCS or have
we got that ....
Bradley Lake Project Management
Committee Transcript
June 6, 1991
Page 8
DAVE EBERLE
DAVE BURLINGAME
CHAIRMAN KELLY
DAVE BURLINGAME
CHAIRMAN KELLY
DAVE BURLINGAME
CHAIRMAN KELLY
I think we’ve been keeping them briefed
on what tests are planned and what the
progress of the testing is. There hasn’t
really been any feedback in terms of we
want to see this additional test or
anything like that but ...
They just ... we got this with the, a
detailed procedure on the tests they are
planning to run for the units.
Okay, that’s the document I guess I was
cece
But that doesn’t ... I guess what we’re
questioning, what we’re asking is are the
utilities going to develop something
which they would like to see ... some
type of operating or reliability type
thing where you run the unit for so many
periods and so much time. The AEA tests
essentially only deal with commissioning
and verification of control; they don’t
deal with what would be considered to be
normal utility operation of the
scheduling units, different load levels -
run them up and down making sure they can
consistently go up to that level of go
down to that level or be controlled over
a range.
It seems there’s two issues. One is an
issue where certain tests might be
required to meet the contractual
obligations and then another level of
testing that might be desirable for the
utilities that we could work out with AEA
++. do you see those two?
Yes.
And another thing that, I agree, and I
think we’re going to have to address that
task but maybe from AEA have we ... do we
have a plan yet on what you intend to do
relative to the declaration of commercial
operation ... we can get to that a little
bit later but that would be another input
that I don’t ... have we got that yet,
Dave?
Bradley Lake Project Management
Committee Transcript June 6, 1991
Page 9
DAVE EBERLE
CHAIRMAN KELLY
DAVE EBERLE
We have a plan in the sense that what
date, do you mean?
Dates and just how you’re going to do it.
In other words, at one time we had talked
about trying to get the 90 megawatt
demonstration and then we talked about
the limited transmission capability may
be hampering that to some extent and then
there was some talk about testing 45
megawatts each of the two units up to
speed and I just think at some point here
we’re going to need to know what it is
from the contractual side that the
Authority has to ....
Okay, maybe I can give a little bit of a
briefing here. The current plan is to
synchronize the units next week and start
putting some load on them. We won’t do
any load rejection tests till July and
based on our current schedule, we would
be completed with all our tests by the
26th of July and I think in terms of
power sales agreement, we can declare it
commercially operational on that date.
Our intent, however, was and this goes
back over a year ago that there was some
interest from the utilities in going
through this ... running it up and down
trial dispatching for a period of time so
we more or less said okay, we’ll allow
probably 30 days to do that. Our intent
would be on the 26th of July to basically
turn it over and play with it as you see
fit and go ahead and declare it
commercially operational on September 1.
The real question that Dave’s getting to
is what the utilities need for a comfort
level to say yeah, we’ve run it through
it’s paces ... we’re in agreement it does
everything. That seems to be tied to
it’s maximum level. We can run it at
whatever level you want it. By July 26,
we’ll be comfortable and we’ve run it
through all the tests, we can run it up
to 120 megawatts if you want. The
question really is what limit are you
willing to accept; what output are you
willing to put into the system so it’s
crossed over that line if you will from
Bradley Lake Project Management
Committee Transcript
June 6, 1991
Page 10
CHAIRMAN KELLY
DAVE BURLINGAME
what we feel is necessary to what you
feel is necessary.
Dave were you done?
Well I was just going to give you a
status of other things external to the
actual project itself. The transfer
tripping of the 115 line which has
basically kept Homer from energizing the
line from Soldotna to Bradley Junction
has been delayed due to some wrong parts
and then broken parts and those should be
in next week and as soon as they get in,
it looks like we’ll be energizing the
line and RTU and Bradley Lake all in the
same week which is something we wanted to
avoid but ... The Bradley Lake RTU for
Chugach Dispatching is installed and
operational. The Diamond Ridge RTU which
is installed by Homer but will be
essentially monitored and controlled some
functions through Chugach is operational
+--+. will be operational, should be
operational by the end of the week. And
the SVS systems, proposals have been
received and are under review and I think
Dave tentatively scheduled price
proposals for July 2.
NOTE: NORM STORY, Homer Electric, joined the meeting at
10:20 a.m.
NORM STORY
CHAIRMAN KELLY
STAN SIECZKOWSKI
Good morning. It’s the time I’ve had my
luggage lost between Kenai and Anchorage
Okay, are there any questions of Dave on
the TCS report? Okay, Operations and
Dispatch Subcommittee report. Stan?
Okay, the Operation and Dispatch
Committee met March 27, April 11 and
May 16 to discuss the issues and develop
plans to resolve the following:
The allocation method to be used for
Bradley prior to commercial operation
consisting of during the test period and
during the period of operation when
Chugach Electric is dispatch and control
Bradley Lake Project Management
Committee Transcript June 6, 1991
Page 11
RON SAXTON
STAN SIECZKOWSKI
UNKNOWN
STAN SIECZKOWSKI
RON SAXTON
STAN SIECZKOWSKI
UNKNOWN
STAN SIECZKOWSKI
and we’ve received a proposal from
Chugach and that is currently under
consideration on how to resolve that.
Another issue, spinning reserves and
peaking operation and that’s been tabled
until we get more information than we can
coordinate with the TCS committee. We
discussed the Allocation and Scheduling
Agreement and I believe that was sent out
to all the utilities on May 17 for their
review and I’1l make a recommendation for
that at the end.
Make sure, my notes show that we sent it
out May 17. Didn’t that go to all of
you? Did anybody receive it? You must
+-. we do some other copies for the table
-.-- let’s make sure ...
If you don’t have ... I have copies ... I
don’t copies enough for everyone but I do
have enough copies ...
What was the distribution date on that
Stan?
May 17.
I got that it went out of my office on
May 17.
That’s what I show ...
What’s the title on that?
Allocation and Scheduling procedures.
Okay, other issues that we’ve resolved
have not come to any resolution is load
restoration procedures and we have no
action there; unit condition mode
operation, idling, gritting, deflector
mode - we’re working with TCS on that or
will be; loss accounting/billing
procedures. CEA has submitted for our
consideration a procedure, we’re looking
at that. And then we’ve developed an
agreement schedule where we are looking
at all the agreements pertaining to
Bradley Lake; we’ve assigned various
individuals and assigned dates for
progress to this. To date, the committee
Bradley Lake Project Management
Committee Transcript
June 6, 1991 Page 12
CHAIRMAN KELLY
STAN SIECZKOWSKI
CHAIRMAN KELLY
DAVE HIGHERS
CHAIRMAN KELLY
DAVE HIGHERS
STAN SIECZKOWSKI
DAVE EBERLE
is ready to recommend the acceptance of
the Allocation and Scheduling Agreement
dated 5/17 subject to completion of
Exhibit A which is in the rear here and
that pertains to the reservoir operation
model. We are currently gathering data
from the contractor and going to develop
a model on how to allocate in the future
and Exhibit B, which is the project
operating criteria again consisting of
the unit condition mode operation, the
islanding, the gritting, the deflector
mode which we need more information on.
We have another meeting scheduled June 20
to pursue these so with that, I will pass
out the Allocation Scheduling procedures
to each utility and again recommend that
this be considered for adoption.
Okay, let’s go ahead then, Terri, and
schedule that as an agenda item for the
next PMC. Would you, Stan would you
envision if we approve this without the
schedules completed or will you have them
completed by then?
I won’t have them completed within a
month; within 2 months we expect to have
it done or at least I anticipate it being
done. I would like to have this approved
prior to 2 months from now.
Okay let’s approve the body at the next
meeting.
Mr. Chairman.
Dave.
Stan, I’m curious if you could give us
some idea of the current level of water
and what you think the level will be and
what we’re going to be looking at this
year for water.
I personally can’t, Dave, I’1l ask
Dave Eberle to help me out here.
Right now we’re not at 1093; we’re
gaining between 3 and 5 feet a week. The heavy run-off is going to start the end
Bradley Lake Project Management
Committee Transcript June 6, 1991 Page 13
DAVE HIGHERS
DAVE EBERLE
DAVE HIGHERS
CHAIRMAN KELLY
STAN SIECZKOWSKI
CHAIRMAN KELLY
RON SAXTON
STAN SIECZKOWSKI
CHAIRMAN KELLY
KEN RITCHEY
of June and through July; the peak is the
end of July and early August. The latest
snowpack, I just looked at this morning,
we’re about within 10 percent of normal.
It’s kind of hard to say because the
Homer area is below normal; far side of
the Kenai mountains are above normal or
in that middle area so we’re guessing
right now about within 10 percent of
normal but it has come up quite a bit in
the last couple of weeks.
Ten percent lower than normal.
That’d be my guess right now. It’s a lot
better than it looks in the middle of
summer but we’1ll know more a month from
now we’ll know a lot more ....
It kind of looks like if we had a surge
tank we won’t have enough mud to fill it.
Okay, anything else Stan?
That’s it sir.
Questions of Stan on the Dispatch and
Operations Subcommittee report?
You might note, Stan, that the agreement
being handed out is essentially the same
one you saw in the draft.
That’s correct.
Yeah, I think at the next meeting this
will be on the agenda and I expect we/’1l
be able to go right through it. The
tasks which are not complete we’1l follow
up as soon as we Know enough about the
islanding of the operation. Thanks,
Stan. The Budget Subcommittee Report,
Ken.
Okay, a couple of items ... it’s listed
on here Homer Wheeling and Chugach
Dispatch ... actually I’m going to talk
about two things - a cash flow analysis
and then the Chugach Wheeling. Whatever
we presented at the February meeting ...
we presented the budget and the budget
Bradley Lake Project Management
Committee Transcript
June 6, 1991
Page 14
CHAIRMAN KELLY
KEN RITCHEY
was approved. Along with that, we passed
out a cash flow analysis of ... and
unfortunately in our last meeting on
May 29, just a few day ago, we noticed
that the cash flow analysis had a bit of
a bust and we have a bit of a problem ...
frankly we prepared the cash flow
analysis to address one specific problem
and that was out debt service payment is
due in December and that’s precisely the
problem that we ended up having. So we
looked at it; we looked through all the
paces and we blew it a little bit ‘cause
we ended up and it wasn’t apparent on the
form that we had that we went into the
red in the operating reserve fund by over
$300,000 ... well we can’t do that ...
Ken, I’ve got to make a comment here. In
case you think that by demonstrating that
you screwed up that you’re going to get
fired from the budget committee, there’s
no chance.
You just never know ... you can always
try. Anyway, so we had to regroup a
little bit. We are looking at several
things to address that problem. There
are some related issues involved in that
too, and one of which Ron and I talked
-.. well we talked at the meeting and Ron
and I talked earlier today is when the
payments are due. I mean on the one
side, you would kind of like the idea to
pay as late as you can, that seems to
have a nice touch to it except that right
now we presumed we have our first payment
September 1 and if we don’t make that
payment, which is what we presume, it
only makes our problem worse because we
have that big payment due in December -
we’ve got to make that payment. And of
course one of things we’ve been juggling
in this cash flow analysis is we’ve been
trying to keep, course it requires that
the payments are level throughout the
period of time that the ... the ten
months ... and we, the PMC, have directed
our committee to try to keep that number
as low as we can which we’ve accomplished
that a little to well so we have this
BRADLEY LAKE PMC MEETING June 6, 1991 Side 2
MALE VOICE: To set the levels of whatever the level PMC decides to set
it at. So this is a somewhat unusual approach but it is a very, very short
term problem. The other thing we're looking at is trying to delay the
payment of some of these expenses. For example, CVA dispatching, Homer
operating costs. Instead of paying those September, October, November
and December, perhaps delaying those until January. That should help us
out some. We're looking at a couple of those, and also it will require the
operating fund, it will require coordination of the escrow ... Security Pacific.
Again, we don't know what the outcome of that will be, but we're checking
into that too.
MALE VOICE: Could we just elaborate a minute ... the time of month
question. We'll be taking that in another budget meeting.... might want to
think about it and get views to Ken and... The issue was if the project
becomes commercially operable September 1, is your first payment
September 1 or the end of September? The answer turns out to be
whichever you want. Your contracts obligate you to make sure there is
enough money in the bank to pay the debt service when the debt service
is due, make all the operating payments when the operating payments are
due, but as long as you live within those constraints, you can probably pay
any time during the month you want. Now the problem that occurs here is
if you don't pay until the end of September, you basically have one month
less revenue by December which makes it very, very difficult to make the
December debt payment unless you raise the first months' payment
substantially. It is purely an internal thing for how you all want to handle
that, but you'll be dealing with that. If there are strong preferences, think
about it, get some ..... I think too, that you sure wouldn't want to, at this
very early stage, shake up any bond holders or trustees or anything like
that. So I think even to include, this is only a "test year problem".
MALE VOICE: This is a first trip operation problem.
MALE VOICE: And then we get other problems. But, clearly this is just
simply because we're only having payments September 1, October,
November and December. If we had had this thing a couple of months
earlier, we wouldn't be in this situation.
MALE VOICE: And that's payment of the thing, is something else
utilities could look at, each one of us making that payment enough early.
MALE VOICE: Whenever you say advance payment, are you talking
about a payment like on August 1?
MALE VOICE: Either that, or making the January payment early in
December. I'm just talking about any way, except causing alarm out there,
right off the bat.
MALE VOICE: Well, yes. We understand that problem.
MALE VOICE: We've been driven by the overriding guide that you want
your first year payment obligation as small as possible. And an easy way
to solve all of this, is a cushion payment. That money would all flow from
year one into year two and be there for your benefit. It wouldn't go to
anyone else. But it is contrary to your goal of having the lowest first year
payment.
MALE VOICE: Right.
MALE VOICE: Just so you're aware of that. I'm sure you are.
MALE VOICE: OK. So we're not asking for any particular action by the
PMC or anything like that. We are asking for some input if you have some,
and also to prepare you for what's coming on July 2. The second thing, and
I'm just going to distribute this. We decided at our, and I'll have 12 copies
so keep that in mind. Chugach has seen this before, since they prepared it.
It has to do the Chugach wheeling rate and the cost components that make
up the wheeling rate as proposed by Chugach. This is based on year-end
1990 information and
MALE VOICE: Actually that's September 30, 1990.
MALE VOICE: OK. September 30. So there will be some other
information, maybe year-end 1990. But this is designed to get the mind
cells going and see if you have any thoughts and questions, etc. I would
ask that if you could direct those questions to me and we'll be again, taking
a look at this and reviewing it in a little more detail at our meeting coming
up at the end of June.
MALE VOICE: Ken, if you could, just to put this in context. These are
the rates that Chugach is charging for wheeling services provided under
the Chugach service agreement. This committee asked the budget
subcommittee to look at those and determine whether they were correct.
If you go back and look at this, have your people look at the formulas and
the agreements and ..... There are two things that happened. One, Chugach
has to segregate its costs to exclude certain of the costs ...... and the second
thing that happens is with phasing .... so that after Chugach determined the
rates, it starts out ... a third of that ..... The calculations that are happening
on this page are supposed to determine the costs associated with providing
this service and then .... formulas.
MALE VOICE: In the first page that we passed up, that is the calculation
based on the information off their operating report. That's the one I think
you want to concentrate on in terms of if you have any ..... The way this is
supposed to work, this first page is carrying out the calculation that was
mentioned in the agreement. So that's basically where we need to throw
the darts at if we have some disagreement. Hey, that was the formula that
just doesn't seem to be carried out the way we feel it ought to be, then we
have to home in.
The second page that we passed out is - let's see. Where was this included,
the second page?
MALE VOICE: The second page was a work sheet that was used in a
February 1988 analyses of Bradley Lake project costs. It was prepared at
Chugach. It was distributed to the Project Budget Subcommittee sometime
last fall. We've had it as kind of a reference document, although it was
done on a forecast basis out into the future and was done for Chugach's
internal use purposes. It was distributed because there was an indication
of where we thought the rates were while we were in the process of
putting it together and getting calculated .... formula. Chugachs' position is
that the first page there is really the one we'll be operating off of. I might
mention also that ML&P of the Budget Subcommittee suggests that they
would like to have the personnel come over and sit down with our rates
people, to review those accounts in the segregation of the Beluga to Point
McKenzie costs. We've accepted that. Currently there's some plan for an
ML&P person to come over and sit down and go through a quote/unquote
"audit". The allocation is we'd like to welcome additional representatives
of other utilities who may be interested.
MALE VOICE: There may be relevant numbers, if you could focus on the
first page. The .... that's the wheeling rate that we can charge under this
formula. The second page, the second column is the phase-in percent ....
Das
MALE VOICE: I guess we'll have to look this over.
MALE VOICE: And again, what I'm looking for is ....
MALE VOICE: This page does not directly relate to ....
MALE VOICE: No. No. The calculation was done earlier and distributed
earlier and just used to refresh people that ... earlier looked at and started
out with the 3 mil. rate, which is very nearly what we have now. A 2.7
rate.
MALE VOICE: Just out of curiosity. So I can know how to think about it,
if you had a 91 rate of a third of a mil there and a .... here to 3 mils.
MALE VOICE: 3 mils is .... to the. Well.
MALE VOICE: What does that end up reflecting in the front page? what
are those numbers? You've got 2.7 .... to ?
MALE VOICE: I think that's where some of the confusion came about.
That particular second sheet had the phase-in factor incorrectly treated.
If, in fact, you looked at the grade today, the 2.7 mills, it would phase up to
the 8 mills number, I think it is on the bottom line.
Several people speaking at once. Could not track conversation about mill
tates and time periods.
No. No. It remains at 90% for the life of the agreement.
MALE VOICE: There was some concern over this before and as I've
been worked through, what you're saying Ken, is that you want that to
come to your committee.
MALE VOICE: Right.
MALE VOICE: I guess you need to think about this. The ramp-in is a
given. That's in the contract. The contract requires that we segregate out
the Beluga to Point McKenzie costs. Issues we discussed are if you think
we did the right segregation of the Beluga to Point McKenzie costs to make
up their .... millage rate, how they did that. You could also disagree with
the total cost itself.
MALE VOICE: There also was a discussion in that subcommittee meeting
on the inflation rate as to - do we agree upon the source that we're going
to use if the numbers are a little bit higher than other numbers you see
around today.
MALE VOICE: Well, the inflation rate only applied to a forecast of the
wheeling rates in that 1988 study, and it would not, in fact, apply under
the transmission services agreement since you're operating on a rate
period that is based on each filing, or each rate adjustment that Chugach
makes with the APUC.
MALE VOICE: So it's strictly actual? Historical?
MALE VOICE: Yes. Yes.
MALE VOICE: We also discussed the application of the wheeling rate
and the changing process. One suggestion was what the timing of this
wheeling rate adjustment should be, and it was the feeling of the
subcommittee that we should calculate and implement it on each filing that
Chugach makes with the APUC, that ultimately leads to a rate change.
Right now, with the simplified rate filing procedures, we make a test
period adjustment every quarter. So essentially, the wheeling rate would
change quarterly.
MALE VOICE: Ken, anything else?
MALE VOICE: The alternative that was suggested was to do it once a
year. For administrative ease and it seems like we do an annual cost of
service update and we could time it with that. The feeling of the
committee was that they wanted to track it on a quarterly basis in order to
look at that and administratively, if you are already calculating it and
dealing with it quarterly, it's just as easy to charge it on a quarterly basis.
MALE VOICE: The agreement refers to the adjustment being made at
each Chugach rate proceeding. The agreement was written before the
simplified rate filing process started so you have to make some decision
about how to ... the process on filing ...
MALE VOICE: On the Homer wheeling.
MALE VOICE: We received information from Homer on that and we're
taking a look at that. I didn't have any comment on that. We've asked the
other committee members to take a look at those costs and get back to
their own people and we had a number of questions, but really haven't
had time look at it in detail and so we'll make some comment at the July 2
meeting.
MALE VOICE: You'd like to carry both of those items forward?
MALE VOICE: Yes.
MALE VOICE: Any questions of Ken on the budget report? The
insurance subcommittee status, Brent.
BRENT PETRIE: We're proceeding with the state Division of Insurance to
shop for insurance for the project through the state's ..... Based on the
recommendations .... the new information .... that we have is re-visiting the
business interruption part of this project proposed coverage. We elected
not to insert anything into the budget for that because the provider of
business interruption would have been the people providing the property
coverage. The only business interruption they would have insured against
was property losses - flood, fire, earthquake, and that sort of thing. We
have found another provider that may be interested in writing coverage
that would include basically the boiler and machinery lists as well. We
have two major questionnaires here that we're in the process of filling out.
I will provide copies of those to members of the insurance subcommittee,
and Ken's also on the budget subcommittee, so we'll be able to address it
there as well. Basically, we're going to have to give quite a thick document
packet. If you think it is worth proceeding, we'll do that. Otherwise, it is
probably going to take us a few days in our office to prepare this response
to this questionnaire. The other thing that did come up in the budget
committee, that we are asking this provider, is ? coverage. Basically, the
Situation with the reservoir level this year has raised some questions
about whether or not we have a water problem. That's not completely
clear in the information we have so far, so we're going to ask that question
of the provider; then be prepared to have them ask us more questions if
we ask them a question on that.
MALE VOICE: This insurance was basically, if something goes wrong on
the project, covers the debt service during that period?
MALE VOICE: What we were looking for is to cover the debt service for
at least a year. $16,000,000 was the debt service and O & M for one year.
That's the level we were looking at. This company apparently has an
interest in writing something for 10 years that would basically be
renewable on a year to year basis.
MALE VOICE: Would that year be applicable to the entire period or
would that be each occurrence?
BRENT PETRIE: That would be for each occurrence, I expect. I don't think
that they'd expose themselves to that entire 10 year period.
MALE VOICE: They might then have given the .... year to year and after
you've had your first .... and when you have the second renewal.
MALE VOICE: Well, no. The thing is, you might end up one for a ten
year period. That's usually what they, if you have a ten year period, you
may have a maximum of one year.
MALE VOICE: But I will distribute this to all the people on the
insurance committee. If you have any questions on it, or comments,
especially of things you think we should ask, please get back to me. We
want to get this filled out and back within the next two weeks.
MALE VOICE: Do you have that on the 4-Dam Pool Project?
BRENT PETRIE: No. The situation is different. The 4-Dam Pool utilities
only pay for energy when they get it, so there's ....
MALE VOICE: I think that has changed a little bit too, is the cost. We
weren't even looking at this for awhile and then the cost ....
BRENT PETRIE: The cost on the earlier quote was $160,000 for
$16,000,000. But again, only covering the major property ....
MALE VOICE: Including boiler and machinery?
BRENT PETRIE: No. It did not cover boiler and machinery and that's why
after discussion, that's where we think most of our risk might be, and if we
can't get those covered, it wasn't worth the money .... I don't know about
the quote. We don't have a quote back yet. We have interest, which is
something we were never able to get before.
MALE VOICE: Any questions of Brent, on insurance?
MALE VOICE: Is one of our options to be looking at self-insurance,
establishing some sort of .... fund, once you know ....
BRENT PETRIE: We kind of do have self-insurance on the project now
through the renewal and contingency funds. That's funded to a $5,000,000
level. So that's where our deductible is. Above that, we're looking at
buying commercial coverage.
MALE VOICE: Develop a debt service reserve bank is a self-insurance of
sorts. .....
BRENT PETRIE: Of course the transmission lines are 100% self-insurance.
What we're not finding is people ....
MALE VOICE: The project status review - Dave Eberle.
DAVEEBERLE: Overall, the project is 94% complete. That 94% is
measured against 100%, which includes the site rehab contract and also the
SVS equipment. So in terms of the on-site work it really affects,
commercial operation date, we're about 99% complete. The general civil
contract - he's finishing the diversion tunnel, gatehouse work, and the fish-
water by-pass system - all his other work is done. He's basically working
on punch list items, doing some grading and some clean-up work. His last
barge out of there is June 14th, so all the major work will be done and the
equipment gone. All he has is minor punch list work. On the power house,
he's down to punch list items only, and supporting our start-up. It's the
final clean-up of the power house, and we're continuing with our start-up
testing program. The status of the tests is that both units have been rolled.
The exciters and ABR's have been checked out. Governor testing is
complete. We're planning the first synchronization of the units next week
and we'll load them at 5% and then bring them up at 5% increments. as I
mentioned, unit rejection won't take place until July 8 when PTI is up here
and has the equipment in place to measure responses. Right now, July 26
is our anticipated date for completing all of our testing and we can
basically turn it over for trial dispatching.
We did a flowing head test on the tunnel on May 22, to test the aggregated
tunnel and leakage. That turned out very good. Over a twelve hour
period, the average leakage was only 58 gallons per minute. If we had
reached 1000 gallons per minute we'd still consider that very good, so the
grouting has really paid off. Virtually no leakage in the tunnel. And given
though the results of the FERC board down there, the decision was that
there's no need to de-water the tunnel. In fact, it'd probably cause more
damage by de-watering than leaving it alone. At this point we're not
planning to de-water the tunnel. Reservoir filling - progressed pretty slow
during the winter. We finally were able to have enough water in the lower
Bradley River to completely shut off the fish-water by-pass on April 26
and the reservoir has been filling fairly rapid since then. We're 1093 now,
which means the reservoir has filled a little over 20 feet since last fall, but
the bulk of that has occurred since we shut off the fish-water by-pass.
MALE VOICE: What's the spill level?
DAVEEBERLE: The spill level is 1180, so 87 feet will take us to the spill
level. So I'd say another month and we'll know a lot more about where
we're going to be this fall with the reservoir level and that's about it on the
status. Are there any questions?
MALE VOICE: OK. Thanks Dave. Under new business, I just want to
mention that Charlie Bussell introduced himself as the new Executive
Director of AEA and I wanted to let you know that when I was working for
the interties down in Juneau, I spent about nine days solid down there at
the end of the session and you couldn't have asked for a better advocate
than Charlie. With those interties evolving, going back and forth, between
and among House people and Senate people, but also direct access to the
third floor was easy to obtain with Charlie. I just want to pass that on to
you. I think most of you that were involved are already aware of that, but
I sure appreciated the fact that he hit the ground at 60 cycles, he was
moving right from the start. I appreciated that.
MALE VOICE: You want to go ahead and tell us how you did?
MALE VOICE: Well, we had Dave Highers kick this off and now I'm
going to slam him right in the chops.
MALE VOICE: The Bradley Agreements committee appointments -
there's a couple of areas where I think, as we get down to the short stroke
here on Bradley, you've got to make sure that things are coming together
and the Bradley Agreements - there are several agreements that have to
Some of them between, like AEA and Chugach - they've been making
progress on their dispatch agreement. But there are probably six or eight
other agreement areas, not necessarily will we have that many
agreements, Ron has talked about trying to consolidate them as much as
possible. Most of this, in one respect or another, is with Stan, but Dave, I'd
sent you a note about having somebody from your shop help on that. I've
asked Ron to serve on it, and Stan, and Mark Riddle. Just to take all of the
areas where the agreements are - you'll have legal assistance, you'll have
Stan as the one that's overseeing that from AEA's standpoint. What I'd like
to charge that committee with is we need, as soon as possible, certainly
before the end of June, I'd prefer that they meet within a week. To
discover each and every agreement that must be in place, put time tables
on it, make sure the assignments are there, get Ron working on any
drafting that you need, but make sure that we are up to speed there.
Several of these agreements are moving ahead. The dispatch and
operations thing, Stan reported on the allocation of the scheduling, AEA's
dispatch with Chugach. This is not to imply that there hasn't already been
a lot of work in progress, it's just that I would like to get a committee that
would report to us, that has the elements that I described. So if there is no
objection, Dave, is that your area? Who are you ... Tom ... So Stan, would
you pull the trigger on the meeting?
MALE VOICE: Yes. What is this thing?
MALE VOICE: The name of the committee is , and this is not very
damned .... but it's the best we could do. We thought a lot about this and
probably paid Saxton at least $37 just to talk about the damned
agreement, but the name of it, but it's called the Bradley Agreements
Committee.
MALE VOICE: Oh brother. Sorry I asked.
BRENT PETRIE: We did prepare a punch list of all these outstanding
groups. We've got a list here in case people .... We've got about 15 of
them.
MALE VOICE: Could we get copies of that?
MALE VOICE: Again, the goal will not be have that many agreements,
but to attempt to consolidate them.
BRENT PETRIE: Some of these are just rights of entry. Little things
between Chugach and AEA.
MALE VOICE: Gas turbine peaking modes for Bradley - that was
something that I think that -
MALE VOICE: What happened to the warm-up? You skipped the
Bradley start-up.
MALE VOICE: Yes I did. Excuse me. Bradley start-up of commercial
operation - this is an area that I had asked, again talked to Dave Highers
about some, but had discussion too, a little bit, with Dave Burlingame. We,
at that particular point in time, the thing that triggered it partially was the
low water situation. The other thing that triggered it was the stability aids
not being present on the system. But the whole issue of start-up of
commercial operation - to assign that back to Dave. Thoughts on that
Dave? I mean, we were looking at the, we need to get into this whole issue
because it relates to what the utilities’ position is going to be, what AEA's
position is going to be. I think Dave Eberle has stated what his deadlines
are ahead, and I'd like to kind of kick this around a little bit first before
we do anything related to the TCS. Dave, you want to give me your
thoughts on that whole area?
MALE VOICE: I think there are a couple of questions that are
interrelated. Number one - are you going to operate the plant at 90
megawatts, first of all, without the stability aids? That's a risk decision.
Primarily right now the risk is associated right with either Bradley Lake
turbines or Chugach or AEG&T turbines. I assume that if that decision was
made that there had to be something worked out where the risk was
shared among all participants. I guess that's one of the questions that we
are asking. If Bradley Lake is allowed to operate above the stability limit
of the plant. Number two is - what do you want the the TCS to develop
some proposed operating scenarios from a utility point of view that we
want to see done to insure that the unit is available for commercial
scheduling.
MALE VOICE: Just so we can kind of get the cards on the table - the low
water thing which Dave has responded to, sounds like it may not be quite
as bad as we originally thought. Maybe from Ron's standpoint, is low
water an issue relative .... contractual obligation and maybe you can fill us
in a little bit on that.
MALE VOICE: I've asked Ron to look at this issue, by the way. Both
from a timing of commercial operation and as to what we have agreed to.
RON SAXTON: Let me answer a couple of thing. The contract doesn't say
anything about water, so it is not ... so that's clear. Commercial operation is
the day that the engineers declare, the engineers reasonably declare, that
the project is fully available to the operators at not less than 90
megawatts. For how long it has to operate at 90 megawatts and whether it
passes back to the operator or just some reasonable declaration that it
could operate, those are all losses on the language and leave it open to
debate, so the answer is that it doesn't say anything about water, it does
say it has to be a reasonable declaration that it can be operated - available
to the operator.
MALE VOICE: .... talk about commercial scheduling.
RON SAXTON: Yes. And that it's output can be scheduled on a
commercial basis. the given sentence construction, again you have room
about whether its 90 megawatts would have to be either scheduled
commercially or whether it has to operate at 90 for a short period and
then commercially schedule some other level. _..... As in most of these
arrangements, nobody having thought about the water situation being a
problem, you got .... question of what the facility would be .... at the time.
How you take that language and apply it to a lack of fuel and both sides of
the debate and the debate is coming and that .....
DAVEEBERLE: Mr. Chairman, maybe I can add some clarity to that. The
lack of water should not be an issue relative to commercial operation.
Commercial operation only talks about 90 megawatts. You can do 90
megawatts at that plant at low pool. So we can exceed 90 megawatts right
now. The rest of the contract recognizes that there may be a variability in
water years but the price paid for the energy - basically you're buying
capacity - so the price is fixed, regardless of the amount of energy that
comes out of the project for a year. I don't think the lack of water or
whether we're low reservoir or not even plays into the declaration of
commercial operation at all.
MALE VOICE: There are a couple of ways we can ... this element. We
could do something in the way of marking down commercial issues. This is
a big question that we need to get, I want to make sure that everybody in
the room gets their two cents in now rather than on the phone with me
later. Charlie's here so I want him to make sure and get a ... report. I'm
not saying that we've got a humongus problem or anything, I just want to
learn - we're getting down to it here - the man says he's going to have his
testing done by July 26 - I don't want to wait until the next meeting so - if
we could - Riley, could you be the scribe for us.
MALE VOICE: Commercial scheduling .... commercial operation
MALE VOICE: I think Ron, maybe the two things we've already
mentioned is - must it be tested at 90 megawatts? The trouble with
having Saxton as a scribe, that I've found before, is it would be much
better if you could cut his tongue out before you had him be a scribe
because he is not going to accept everything you try to get him to write.
So you're going to have to work with a little on the problem.
RON SAXTON: I just want to make sure of my definition - you've got
some key words - the first thing is you have to have an engineer's
declaration.
MALE VOICE: And that is by AEA. Is that right? That is an AEA
engineer or is that some other?
RON SAXTON: An engineer retained by AEA. You did have some
discussion earlier about whether it had to be somebody specially retained
for that purpose or just one of the engineers who are out there. The
engineer has to make a declaration that is reasonable. The declaration has
to say that the project is available - available ..... 90 megawatts, and the
second condition, that output can be scheduled.
MALE VOICE: The engineer signs on all of these things?
RON SAXTON: The signs ..... At a minimum, this will mean that whatever
output is there has to be commercially schedulable. You can debate about
whether that has to be 90 megawatts .... or just whatever is there. Those
are two distinct tests. They were put there to .... an instantaneous
declaration that it could operate at 90 megawatts but then it collapses and
is unable to ever run again isn't what we want. It has to be able to operate
at 90 megawatts for some reasonable time and the output of it has to be
commercially schedulable. Those are the tests. If you want .... whether the
project can meet it or not, ....
MALE VOICE: I think at this point in time Dave Eberle - what I heard
you say is that your testing will be done, and I assume that that is that
testing which you determine is necessary to, in your mind, to declare it
commercially operable. Is that what that means?
DAVEEBERLE: That the would be the testing that we, and the engineer
have agreed is the testing that we want to do on the units - verifying for
ourselves that everything is operable.
MALE VOICE: OK. Then you would do some future test, like this, prior
to September 1, to declare it commercially operable?
DAVEEBERLE: Well, we wouldn't do anything. Technically, I think we
could declare it on July 26. But last year we went through this argument
and there was a request that there be a trial period here, trial dispatching,
and we said we'd try to accommodate that and try to give you 30 days.
Right now we're projecting 5 weeks worth of that.
MALE VOICE: During which we can load it to any level up to its
maximum output?
DAVEEBERLE: Any level you want to load it to. Use it any way you
want. And we'd have the engineers standing by if anything came up.
Then we could analyze it and see whether it was a problem and what the
cause was.
MALE VOICE: Dave, when September 1 rolls around, who is it that
would actually make the declaration?
DAVEEBERLE: Stone and Webster is who we would envision doing that.
They're the logical people to do it.
MALE VOICE: Dave, are there other tests involved, where we're testing
equipment, concerning any manufacturer's warranties or anything that we
. equipment?
DAVEEBERLE: We will have tested all the equipment by July 26. In
fact, we're basically past that point already. The July 26 date is also
basically the date when the warranty would start with the contractor on
the powerhouse.
MALE VOICE: For those of you who maybe weren't in the discussion a
year ago - the Energy Authority will perform the tests it thinks are
important - and be done with this by July 26 .... however their
concerns...warranties..... The utilities requested, maybe insisted on,
additional ability to test for longer periods, ... tests that were designed by
the utilities, so that's what the extra month .... September 1 as the date of
convenience.
RON SAXTON: September 1, date of convenience. It is my
understanding is that that is the date, via the revenue bonding, that
requires payment to begin. Within that month's period of time, which I
guess is still up in the air. But the key to the September 1 date is to insure
that the utilities are now paying into the state in order to meet the debt
obligations and the service obligations that are the revenue in the bonding
consideration, rather than a date vis a vis project operation or any other
contractual ...
RON SAXTON: September 1 was the date used for all the assumptions in
the finance. If the September 1 date isn't met, a couple of things happen.
The bonds that were issued did not include any money for capitalizing any
further interest after September 1 so if the utilities are not making
payments, then there's no source of revenue for paying that, other than
going to the reserve funds. ..... that's an issue the state would have to face.
MALE VOICE: Ron, are we up against the cap on cap interest, ...., IDC?
RON SAXTON: My memory is that we had room for a month or maybe
two months or more of cap interest - that the money to pay it isn't there
but if the state found the money somewhere, we wouldn't run into a tax
problem for another month or two. At some point, if you delay it long
enough, even if the state finds the money to capitalize it, you run into a
danger in your tax exempt status - ratios of money used - the fact is I've
pulled .... how additional capitalized interest could flow back to the utilities,
is a question that we could talk at length, but since you're well the
$350,000,000 price of the project, some of the additional costs would come
to the utilities as ....
MALE VOICE: If there was a question about all of the things from the
operating level to the ability to schedule commercially, if the utilities were
making the payments, possibly not within the, maybe in another kind of
interim agreement, does that satisfy the bonding problem.
RON SAXTON: Well, there are two ways to ... that, one is a friendly way,
and one is a not friendly way. On September 1, or whatever date the state
chooses to do it, their engineers can declare this thing commercially
operable. That's not a discussion item or anything else. That is something
they get to do. The contract expressly says that once they do that, you
have to make your payments while you dispute it. So one scenario is - if
September 1 ... commercially operable, the utilities say absolutely not - we
would probably then go to court for some kind of declaratory judgement
that it wasn't commercially operable, some type of injunction against them,
but while we fought in court, you'd have to make the payments. If you
won in court, you'd get your money back. But you would have pay while
you were fighting. So that is one scenario.
MALE VOICE: Ron, while you are one that scenario - let's say that that
did work to delay it, are we still obligated for fixed costs, costs of fixing, or
whatever, let's say that they couldn't declare it - Stone and Webster says
no, they need to do something else. If you say we get our money back,
what we get back is our money, we'd get back debt service money that you
had made, your payments would come back because you wouldn't have
been obligated to make them, but, if the state had to incur additional
expense to fix it, or even additional expense to capitalize the interest for
that period, as long as it's under the $350,000,000 cap, you'll wind up
paying that.
CHARLIE BUSSELL: That is purely an assumption on your part. You'd
get back what was court decided, .... it may be all or none of what he said.
MALE VOICE: Absolutely right. Well, what I tried to say though, is
you'd probably get if back in one hand and you pay it with the other. I
absolutely do not believe that you walk away with no payment as a
consequence of the delay.
MALE VOICE: That's what I mean. If there is a delay, the costs that go
on would be added to the project.
MALE VOICE: They would be added to the project and you would pay
for them over time. What the court might give back to you is the money
you paid in that particular month. It might be added get on to the
principal amount you paid over time instead .....
RON SAXTON: Other scenarios that let you deal with delay, if you want
to deal with delay.... by day .... is one that you could agree - if you delay
commercial operation for some period, but that the utilities would make
payments monthly for the .... power. The power period before it is
commercially operable, and the amount you agree to pay would be an
amount of money equal to what your payment obligation would have been,
so that the debt will .... and the operating costs covered. That doesn't do
anything to reduce costs to the utilities, but it does put on to Dave ....
That's not something utilities can unilaterally .... but I think that's what
you were asking , basically, there are ways where you can pay the money,
service the debt, pay the operating costs, get ...., but not have had the
declaration of commercial operation ..... That's only something that would
work out if it was negotiated with the Authority ....
CHARLIE BUSSELL: I don't believe that, Councilor. I think you'd have
to go back to the bond holder, before you .... That commercially operational
date is tied to the notification of the bondholders. I think you'd default on
the bonds, even if you put the money up, unless you went to the
bondholder and got a different date. I think that's clear. Not only is it
clear, ....
MALE VOICE: It is clear that it is not easy to ....
END OF SIDE TWO
Bradley Lake Project Management
Committee Transcript June 6, 1991 Page 15
Tape 1, Side 3
CHAIRMAN KELLY
DAVE HIGHERS
DAVE EBERLE
little problem. It’s a very short term
problem; it’s not like there’s any
problem with the budget or anything like
that, it’s just that we have to meet that
December payment without running all of
our other funds into the red so we’1l be
proposing ... this is just sort of a
preview of what you’re going to see on
July 2. We’re probably going to have a
couple of recommendations to try to
address that problem one of which is to
ask that the operating fund be run down
to zero.....
I’m a little worried about limiting it to
80 megawatts or having a potential out of
step problem I assume with loss of unit
-.. what ... let’s hit that for a minute.
Dave, you’re looking to this group to say
okay, there is some risk and this group
will have to agree to waive that limit of
80 let’s say it is, and go up to the full
test. We’ve talked about this as long
ago as maybe a year ago. Dave Eberle is
saying test it to 90, test it to 120 if
you want during this month that you can
play with it; we’ve got enough water to
do so. What I think we ought to do is
figure out how we get an answer to your
question on whether we exceed that limit
or not. Dave.
I’d like to add something before Dave,
sir. The whole situation is the two
sides acting honorably and with
legitimate concerns that they have. The
thing with, and I know Dave’s right, is
that we can run 90, 120 megawatts and say
it’s there. The things that are not
clear and maybe less of the situation
with the AEA is that the system is not
stable and the damage that could result
is to turbines ... very expensive
turbines ... and the system will go
stable I think, Dave in ’92 when the SVS’
come on?
That’s the intent of the SVS is to sort
of short out the Kenai transmission
Bradley Lake Project Management
Committee Transcript June 6, 1991
Page 16
DAVE HIGHERS
DAVE EBERLE
DAVE HIGHERS
CHAIRMAN KELLY
DAVE BURLINGAME
CHAIRMAN KELLY
system so that you could run it all the
way to 120.
And that would be in ’92 though?
That’d be the end of ’92, right.
And that’s ... I mean there’s issues
there of anyone that’s got generation
knows it very expensive machines.
Is the TCS essentially saying that the
risk is to great beyond 80, Dave? I mean
can we get a sense of what that means.
Well, I think within the TCS you’ve got
to remember there’s only two utilities
which are primarily affected by the risk
and I guess the thing that I’d request, I
think it would be easy for the TCS to
develop the testing criteria if you’re
going to go above 80. I don’t think
that’s a problem. I think the thing that
should be kept out of the TCS is any type
of risk allocation on the various
participants; I don’t think that should
be within the TCS. I think the TCS could
well define what operating and testing
restraints they want the project to be
able to perform to be able to satisfy to
our general managers that yeah, we think
the project is commercially available at
90 megawatts. We believe that. I don’t
think that’s a problem getting the TCS to
make those definitions; I think there
would be a real problem trying to get the
TCS to do that if the TCS was also
supposed to hammer any type of risk
allocation if, while you’re operating
above the stability point if something
else happened. I think that’s something
I believe it would be hard for the TCS to
settle.
Just as an obvious alternate to that is
to spin one up to 45 as we discussed a
year ago; spin the other one up to 45 or
both of them up to 60 each and then spin
them both 40-40 to get a total of 80.
There’s an obvious number of combinations
there but what I’m hearing from Dave is
Bradley Lake Project Management
Committee Transcript June 6, 1991 Page 17
DAVE EBERLE
CHAIRMAN KELLY
DAVE BURLINGAME
CHARLIE BUSSELL
DAVE BURLINGAME
CHARLIE BUSSELL
DAVE BURLINGAME
that they intend to declare it available
at 90 megawatts by some method. Dave is
that method that will satisfy you if you
can’t get 90 out and using ... load one
and then load the other?
That’s our plan is loading each unit
separately and then load them in
combination to the extent that the
utilities are willing to take power.
So that’s the intent of the Authority.
The intent of the Authority is load to 90
and do a load rejection at 90 and our
concern with the TCS is you can load
individually, load in combination of 80
but then if somebody asks you are you
willing ... say you’re general manager if
this thing can run at 90, commercially
scheduling even though it may have never
run at 90, you know, I could say on paper
yeah, no problem but in ... based on any
type of comfort level I don’t think
anybody would say yeah, I think it can go
up to 90. It’s purely a theoretical
exercise.
Rather than trying to say can it run at
90, can you tell us why it wouldn’t run
at 90?
No, I don’t think we can say that ...
It’s a ... Dave said it’s a matter of
somebody saying it’s good faith on both
parts. It’s good faith on our part ...
we’re willing to entertain anybody’s idea
of why won’t it run at 90. If you track
that out, we’re willing to address that.
I don’t know how much more good faith the
Authority can put on the table. We/’re
saying if you can tell us why it won’t
run at 100...
I think the only thing we’re trying to
deal with is we‘ve all gone through
turbine rebuilds and you go through a
turbine rebuild and you say okay this
thing is good for 90 megawatts and you
know, all utilities have done it where
Bradley Lake Project Management
Committee Transcript June 6, 1991 Page 18
CHAIRMAN KELLY
DAVE EBERLE
CHAIRMAN KELLY
STAN SIECZKOWSKI
DAVE BURLINGAME
you get to some megawatt level and you
can’t think any reason why in the world
it won’t go there and all of a sudden it
goes there and it trips off line and we
don’t know why. It takes a while to go
back and figure out why it won’t and fix
it and that’s all we’re concerned with is
because we’ve all gone through it before.
Dave by a combination of spilling and
running through one unit of up to 45 for
example, you can test your tunnel
characteristics? I don’t know enough
about this ...
Right, we can do testing on the tunnel
and it’s all been simulated already and
we can compare what we’re getting on
actual ... simulation is ...
Okay what I’m reading loud and clear from
the Authority is that you intend unless
you find something that’s haywire,
obviously, that your engineer would then
not be able to declare it. So your
intent is to declare it commercially
available for 90 megawatts based on a set
of tests you’ve identified. Then what
we’ve got to do at the TCS level is that
we’re going to have a month to play with
it so we’ve got to determine what we’re
going to do to satisfy ourselves,
operationally, that’s the distinction
here ... it’s not really whether we’/re
going to be able to convince ... is that
accurate? Is that your intent? If that’s
the case, Dave, it seems to me that what
we ought to do is give to the TCS that
job of defining the tests we want to do
during that period. Stan does that bump
on any other committee or is that or
maybe they have to work together with
Allocation and Dispatch?
I think we should work together with them
on this, yes.
The only other question, Mike, is that
you as soon as the TCS is on level and
you’re leaving to the TCS to decide
whether to test the unit above 80 and I
Bradley Lake Project Management
Committee Transcript June 6, 1991 Page 19
CHAIRMAN KELLY
TOM STAHR
don’t think the TCS really has a problem
testing above 80, I mean I know I don’t.
If there’s some type of agreement worked
out that, you know, I mean, I’m not going
to the TCS as a member of Chugach and
recommend it above 80 because all of the
risk is for Chugach, you know, and
that’s, you’re going to get a no from us.
I think that until we resolve that issue,
the testing will be restricted to below
the stability limit of the system.
Yeah, I guess that’s the question and I
agree with you, I don’t have any problem
with that. The risk assessment is going
to have to be left up to the owners of
the machine and that’s easy, I mean we
can probably ask the two owners whether
they would want to that otherwise maybe
if they intend to declare by methods that
they have that really are independent
from what we decided to do relative to
90, then I’ve got to determine for my
share just for my vote whether I’m
comfortable with 80 and run each unit to
maximum, well, I’ve got to say my
instinct is that I’m probably
uncomfortable with that although I don’t
have a machine in the game. If we find
if can convince Stahr and Highers that 90
is okay, I’m all for that.
Well, I think I bought a little more than
90 megawatts, I really do, I think I
bought a machine that had spinning
reserves, the license application says
they build it that way to produce, I know
every utility evaluated that machine,
evaluated it if it could act in the way a
normal machine operates so I mean there’s
other things than just 90 megawatts or
25.9 percent that’s worth more than 90
megawatts that I believe I bought in good
faith. It wasn’t until well after the
contract was signed that we’re find gee,
you’ve got to run a turbine in parallel
with it and all of that. I don’t want
ML&P down the line to have to pay for
running that turbine in parallel with it
and all these other things. I still
believe that is what we bought and that
Bradley Lake Project Management
Committee Transcript
June 6, 1991 Page 20
CHAIRMAN KELLY
TOM STAHR
CHAIRMAN KELLY
TOM STAHR
CHAIRMAN KELLY
TOM STAHR
CHAIRMAN KELLY
is what we should get and yet they
probably can meet the definition at least
for that first part under definition of
commercial operation. I’m not certain
the can and I think that’s what a good
faith, I don’t have any doubt that the
don’t think it can’t produce 90 megawatts
and I think you can test it ... it’ll
probably produce 120 but will it do, will
it provide what we, in good faith,
believed we bought and I think there is
where the serious question comes in.
And I think back to not, I just want to
take it an issue at a time and I think
maybe, Tom, what you’re saying may come
under 3?
Yeah ‘cause output is more than just
kilowatts as far as I’m concerned.
Well relative to the output question, if,
as long as we develop a regime with
staying within the stability limits, what
I want to do is send Dave out of here
with an assignment related to 90 or 80 of
if there’s a question we have a way to
resolve it. My instinct is that probably
the 80 megawatt is okay and if I hada
motion to that affect maybe we can get
the thing out on the floor and discuss
Tt.
I really urge that we wait, we don’t have
to 80 or 90 are adequate yet but
pretty close.
Okay but what task, I want to give him a
task that gives him some direction
because all we’ll be doing is sitting
here looking at each other a month from
now if we don’t.
I don’t mind giving him direction but I
don’t want, I urge this body not to make
the decision. They still keep their
options as to whether we’re going to test
these...
You mean like maybe two options, Tom, we
can do that. Is that okay?
Bradley Lake Project Management
Committee Transcript
June 6, 1991
Page 21
DAVE BURLINGAME
CHAIRMAN KELLY
DAVE BURLINGAME
CHAIRMAN KELLY
TOM STAHR
CHAIRMAN KELLY
TOM STAHR
CHAIRMAN KELLY
It would be fine with me.
Without objection, the TCS through Dave
will be instructed ignore the risk, the
acceptance of the risk not ignore the
risk, but the acceptance of it, and
develop scenarios that has an 80 cap and
a 90 cap.
Okay.
Any objection? Without objection, we/’1l
do that. The next issue is related to
the output being able to be commercially
scheduled and Tom Stahr has just brought
up some of his concerns relative to
spinning reserves, operation of the
turbines, etc. We need to get started on
that, Tom, anybody that wants to...
Well I think we have to quantify what all
we believe we reasonably bought and look
at what has to be done to determine
whether we’re getting it ... that’s what
we’ve got to decide and what we’re going
to do about it, I guess then it’s a
question of whether we’re going to fight
or work out something agreeable. I think
it’s serious ... we bought more than just
something that’s 90 megawatts ... we
didn’t buy, I don’t believe, if I’m wrong
just tell me, we sure as hell did not
evaluate an energy source. We evaluated
energy and capacity sources; we evaluated
it just like any other normal generating
unit and that means spinning reserve ...
that’s a big thing economical to ML&P, we
pay a real high price for gas, spinning
reserve is very expensive. That’s one of
the things I believe I bought in the
project is spinning reserves.
To speak for myself, I think I know I
didn’t buy a combustion turbine in load
response ...
No, I know that ...
I bought a piece of a hydro plant ...
Bradley Lake Project Management
Committee Transcript
June 6, 1991
Page 22
TOM STAHR
CHAIRMAN KELLY
DAVE HIGHERS
CHAIRMAN KELLY
DAVE HIGHERS
CHAIRMAN KELLY
DAVE HIGHERS
CHAIRMAN KELLY
DAVE HIGHERS
But I’ve with other
people, I’ve talked to people from
Norway, we entertained some the other
day. It’s a 100 percent hydro, they
don’t seem to have any problems like they
don’t have to run diesels or turbines in
parallel with them.
Okay, is that a situation as far as
running the turbine, you’re talking bout
the Bernice Lake turbine that you’ve got
an obligation to Homer to run for now
anyway. Is that an endless obligation or
ends with Bradley in that order or what.
I’ve never run ....
Well, no the agreement was until Bradley
was up ... I didn’t say this but I like
these words commercially available ...
That’s how it is in the agreement.
Yes.
So essentially ...
There’s not really, I mean that was a
verbal commitment we’ve left on, we
stayed on all along. We have an
agreement that we’d have a turbine down
there until Bradley comes on but the
assumption back when that was all done
was a little like Tom’s saying was that
Bradley was kind of a euphoric thing that
we all wanted and there was not going to
be a need for anything ... it was going
to be spinning reserve capacity and the
whole thing and that, we started
discovering more about stability and
everything else was done. That really
had to do with voltage stabilization on
the Kenai.
So now if the second transmission ran
just so I can understand all of this, if
the second transmission line were in and
Bradley was on-line, is the Bernice Lake
turbine required?
We don’t ...
Bradley Lake Project Management
Committee Transcript
June 6, 1991 Page 23
DAVE BURLINGAME
CHAIRMAN KELLY
TOM STAHR
CHAIRMAN KELLY
TOM STAHR
CHAIRMAN KELLY
TOM STAHR
DAVE BURLINGAME
CHAIRMAN KELLY
DAVE BURLINGAME
TOM STAHR
I can clarify that. The Bernice Lake
turbine is only required due to the
absence of the second line.
Okay the question then becomes if the
line is in, Tom, that solves that part of
your problem or your question.
My concern with the turbine, I’1l be very
pragmatic with you is surely, I mean I
don’t think we ever signed up to pay for
spinning another turbine ...
Is this another one or the same one?
In order to get our energy and capacity
and that includes spinning reserve out of
the Bradley Lake project and I don’t know
how it could be played out ... maybe
Norm’s quite happy with the bill ...
You say another turbine, you mean
continue to spin the one, one is
now required ....
I don’t know whatever it is ...
Maybe this needs some clarification. The
Bernice Lake turbine is not required with
the operation of Bradley. The Bernice
Lake turbine is only required to expand
the operating limits of Bradley, that’s
eee
Beyond the, okay, let me ask it real
simple. If you loaded it just the
ability to get the energy out of it which
is 45, 50, 60, do you then have to
operate the turbine on the peninsula?
It depends on the winter loads, you’11
probably have to in the winter based on
the criteria. Basically the gas turbine
on the Kenai only expands the operating
range of Bradley especially during the
interim here ...
Dave, I don’t, I’m trying to understand,
can we get, we I mean collectively, we
and the other purchasers get both our
Bradley Lake Project Management
Committee Transcript June 6, 1991
Page 24
DAVE BURLINGAME
TOM STAHR
CHAIRMAN KELLY
DAVE EBERLE
UNKNOWN
DAVE EBERLE
CHAIRMAN KELLY
energy and capacity out of Bradley
without spinning that turbine?
You can get the capacity after the SVS
installations are done ... you can get
your energy right now ... it’s just that
the way you us da have to take that energy
is not the way your utility requested
that energy. Bradley Lake right now has
an operating window that’s fairly
restricted. With the gas turbine, that
operating window gets very large and
that’s really the ...
This is oversimplification but until the
SVS is in, we cannot necessarily get what
we purchased without spinning a turbine.
Okay let’s ask a question. Is
that AEA’s problem? Or is that our
problem? I mean I’m not asking you I
just happened to be looking at you ...
I’1l gladly answer that ...
I can guess what you’re going to say ...
I mean you look at that power sales
agreement it describes the project. Now
I’d like to see anybody tell me where in
that the power sales agreement or where
in that description of the project all
these great expectations have been laid
because I don’t think Tom Stahr right now
could tell me what his expectations are
and I don’t think anybody else here can
tell me what they are ... in fact when we
tried to design this thing and during the
planning stages, we couldn’t get anybody
to tell us how they wanted it to operate
and you can’t to this day so I’ve gota
real problem with Tom sitting over there
saying this isn’t what I signed up to
buy. What we were building was well
known ....
It’s a wise idea to talk in here even
though it’s a tough subject, it’s a heck
of lot better here than between two
attorneys so let’s just hang in there and
arm wrestle all we need to here because
Bradley Lake Project Management
Committee Transcript
June 6, Page 25 1991
that’s a lot more productive than if they
grab an AG and we grab an attorney and we
start fighting like heck ... I’1l tell
you I guarantee none of us will come out
where we want to be .... I urge everybody
to hang in here. What I expected, as
this thing as unfolded, Tom and I are the
only players from the beginning, not a
one left but he and I and we don’t
necessarily agree on these issues but we
are the original cats and I occasionally
accuse him of short-term memory loss
because he’s getting to be an but
never long-term, so what I think we
agreed to get is this: We were ata
meeting where we had to give up the
interties being tied like this to the
project. I was in that room; Tom and I
were two of the guys that went out in the
hall and thought it was a horrible thing
to separate the interties from this deal.
We were over a barrel, everyone
reluctantly agreed and I don’t think it
was unanimous or cozy or anything else.
What I knew on that day and then I’m not
a southern utility so I’m not pretending
to know as much about the southern system
as Tom by any means, but I thought that I
was getting less than I wanted because of
an intertie problem not because of a
turbine problem. I’m just speaking
strictly from my feelings about this. As
we went forward, the Energy Authority,
and I thought it was a fairly, it was
move that maybe they didn’t have to make,
was the Authority, without going back to
the Legislature or anybody else agreed to
help the southern system with these SVS
but they won’t be on-line in time. My
feeling is that if we can’t commercially
schedule 90 megawatts anytime during
8,760 a year, that does not shatter my
expectations. I did not expect to be
able to do that until after the SVS’ are
in and actually, did not expect perfect
operation of Bradley until the second
intertie is in. But what I did expect
was I would get every stinking kilowatt
hour out of there by some manipulation of
lower generator output levels or
whatever. That’s my honest assessment of
Bradley Lake Project Management
Committee Transcript
June 6, 1991 Page 26
TOM STAHR
CHAIRMAN KELLY
hundreds of hours of sitting in meetings
and negotiating so when I approach it at
this point in time, and I’m not as
familiar with that #3 as maybe Dave and
Gene and people like that are as far as
scheduling goes, but those were my
expectations and Tom you’ve got to kind
of tell us what you think.
I realize the lack of having an intertie
does limit what we can ... I don’t care
if its 80 or 90, but I’11 go back to
spinning reserve as one. We pay a lot of
money for spinning reserve despite what
Allen Mitchell says ... I still believe
and it’s pretty expensive to
market and I have suspected all along
that Bradley Lake could be used to supply
that whatever our capacity of that taking
into account certain transmission lines
limitations, we could use that as
spinning reserve. Now maybe we still
can, that’s one of the things I think the
TCS should look at. If we can’t I
certainly then feel I do have a real
reliance problem here because I think
that’s a valuable, damn near as valuable
as the energy itself. The capacity
itself for kilowatt for kilowatt sakes
for ML&P does not make a heck of a lot of
difference for quite a while. But
capacity for the sake of the spinning
reserves what we have to burn fuel at a
computed rate of 5 to 7,000 BTus for
kilowatt hour for spinning reserves is
almost as valuable as energy and I
expected from the beginning to get it;
I’ve always expected to get it and as I
say, even the license application the
Power Authority prepared implies that
we’re going to get it. Now if we’re
getting it, fine and I’1ll shut up. The
TCS says that fine but I don’t want Dave
to come back in six months to a year and
say gee you’re really not getting it from
Bradley you’re stealing it from me and
you can’t have it ....
Response to that, Dave, as far as, again,
let me ask one distinct, distinguishing
question, Tom. You are speaking of this
Bradley Lake Project Management
Committee Transcript June 6, 1991 Page 27
TOM STAHR
CHAIRMAN KELLY
DAVE BURLINGAME
CHAIRMAN KELLY
DAVE BURLINGAME
CHAIRMAN KELLY
expectation as it relates to a post SVS
and intertie scenario or three or both or
ceee
I’m expecting that part of commercial
operation is being able to schedule that
output and part of the output is spinning
reserves.
Do we have that ... after, assuming an
intertie, and assuming an SVS system in
place, do we have the ability to get what
it is that Tom is saying he expected?
Well, the intertie and SVS’s have little
to do with spinning reserve ...
Response of the turbine.
Right. The TCS has yet to determine the
value of how much spinning reserve is
available from Bradley Lake during normal
operation of gas turbines so ... I think
they did some preliminary ... Saleem at
PTI did some preliminary stuff when he
was working for the Power Authority or us
or somebody, I don’t know, and said that
Bradley was good for somewhere between 20
and 30 megawatts of spinning reserve by
itself and that by utilizing the peaking
of turbine, Bradley was essentially able
to contribute up to its 120 megawatt
capacity for spinning reserve, again,
that upper limit would be limited by
transmission constraints. The other
issue I think is mingled in here is the
minimum operating level is , I think
everybody including Golden Valley of all
of the energy allocations requested from
Bradley Lake since I’ve been connected
with it, it was always assumed Bradley
Lake at some minimum level at 10 or 15 or
20 megawatts, in fact, during a lot of
the summer, Golden Valley was the only
one scheduling 10 megawatts or something
which is not a possible operating
scenario without a gas turbine. That has
not been defined by the TCS but we/1l
probably follow-up on it ...
Is that pre- or post-SVS intertie.
Bradley Lake Project Management
Committee Transcript
June 6, 1991 Page 28
DAVE BURLINGAME
TOM STAHR
DAVE BURLINGAME
TOM STAHR
DAVE BURLINGAME
CHAIRMAN KELLY
DAVE BURLINGAME
The SVS’s don’t make any difference just
... the intertie would eliminate that
restriction on the ... does that answer
ee ee
I’m not even terribly familiar with the
minimum output ....
I don’t think you were here at the last
PMC ...
Right, I missed some of that and I/11
admit ... it’s another restriction that I
did not ...
Besides restriction in the interim, in
the interim, the restriction will be on
the maximum case which everyone is
focusing on prior to the installation of
SVS’s. After the installation of SVS’s,
that maximum restriction essentially goes
away. The SVS’s will allow the project
to be scheduled at 120 megawatts during
the worst case. The minimum operating
restriction will not go away for the life
of the project until the second tie line
is built.
Just slipping real quickly to the gas
turbine peaking mode for Bradley, that
question that was brought up by
Bob Hufman at the last meeting that he
essentially felt that it had been left
hanging - have we investigated it, yes we
had. Have the owners consented to the
peaking mode?
I don’t know if they, the utilities made
a formal presentation. I think it was
left that ... the way it was left with
TCS is the TCS will establish how much
spinning reserve is available to the
system should that spinning reserve be
from Bradley Lake. Should that spinning
reserve displace spinning reserve which
is acquired through the peaking mode of
gas turbines, it was up to each
individual utility to assess whether or
not they want to do that or whether
through this, through some peaking period
Bradley Lake Project Management
Committee Transcript
June 6, 1991 Page 29
CHAIRMAN KELLY
DAVE BURLINGAME
CHAIRMAN KELLY
TOM STAHR
HANK NIKKELS
they want to start another gas turbine
themselves to supply spinning reserve,
that was left to each individual utility.
I think Chugach decided we were
interested in peaking reserve for at
least some of the units. Peaking mode
fOr, sac
Peaking mode and that occurs for 3
minutes or 1 1/2 minutes ...
About a 1 1/2 minute ... you can ramp all
the way up ...
Tom is that the problem for you guys?
We’d pretty well determine when we’re
running but that’s only the winter months
--- it’s not a big preblem ...
I defer to Hank here, I think in general
it’s not a problem so long as we aren’t
up against so many other restrictions and
limitations that we really can’t count on
it very much, I believe the question is
you know, if help is on the way real
fast, just as fast as Bradley can
respond, then that’s, that response, but
limitation ...
I owe this committee a report because the
Machine Reading Committee met and
discussed this ... Olsen and Abeck and
that was six months ago and it’s still on
my desk, but to summarize many of the
machines on the system there have been
restrictions placed by the owners. The
machines have not been tested in the peak
mode; it is an option but the costs for
doing that, PTI indicates it’s a simple
throw-the-switch thing, it’s not. It
requires effort, it requires testing and
it goes from one utility being willing to
do it to I believe to Golden Valley not
believed to do that ... and
BRADLEY LAKE PMC MEETING June 6, 1991 SIDE 4
MIKE KELLY: .... Nor are the expectations addressed by the PTI report.
We felt the PTI report was complete in terms of generator and voltage
response. It is still somewhat lacking in terms of an understanding of
governor response. It made some generalizations that really were not
true.
MALE VOICE: Mike, when you say you kicked it around up there, is that
the position of Golden Valley?
MIKE KELLY: Well, I can't honestly say that, Dave, because I know
there was some concern and then, as I understood it, that concern was less
and it looked like, if everybody was going to bite the bullet and do it, that
we'd probably be able to do it. But, we're probably right back where
Huffman asked the question - it's just kind of a hanging thing again. I
think that it is critical to this decision in that the only thing that helps the
minute and a half response or the help is on the way thing is if we can
somehow go into over boost for a second on these turbines. If that works,
and can be swallowed, then it solves that, but...
MALE VOICE: I'd like to make an editorial comment, if I may. I think
probably we'll do it, we have no choice to it. But I don't think it's
something in good design that we have to do.
MALE VOICE: .... Clarify that. The TCS was going to set the level of
Bradley Lake's spinning reserves that can be counted on. What the
utilities, without peaking .... So if the utilities opt not to peak, that's their
choice, it's not a problem. But that just means they can't count on any
more of their spinning reserve allocation from Bradley then what it said by
the TCS for that level. They would in turn have to waive that risk of going
to peaking mode versus the risk of starting the turbines and paying their
own spinning reserves by .... turbines. Each utility needs to weigh the risk
of starting the turbine versus going to peaking.
MALE VOICE: With a minute and a half response, how do you start a
turbine?
MALE VOICE: You would have to have your turbine on line and running
during that period of time when - you'd have to spin a turbine - even if
you were going over the peak load, where you'd only need maybe to put
your turbine in peak for four hours a day, you would have to start your
turbine four hours a day to determine the base load. I just want to make
sure that everybody understands that. The option of not going to peaking
is starting another turbine.
MALE VOICE: I expect that ML&P will probably be doing what Chugach
does. We'll be going through all those ... expenses. .... to know yet, to know
whether we are getting what we bought, or not. Maybe if all that works
out and we get enough ..., spin, then we don't have a problem. It's not
ML&P's problem, it's Homer's problem, if the damned thing can't carry a
normal load by itself.
MALE VOICE: Let me ask your question to Ron. Again, I think we can
dodge this off at any time. I think that it is only in this room, with all the
players, that we're going to get through some of these things. I think a
follow-on question we need to ask you - Is the operation of Bradley, as far
as the utilities are concerned, no, is the responsibility ... of AEA. as far as
the transmission line and the SVS timing thing, something that we have
the contractual right to hold their feet to the fire on ...
MALE VOICE: If we can't something that we could otherwise with the
SVS in, that they intend to pay for, or the transmission line which we keep
fighting for, are they to be held responsible and is that a number three
thing that we can tell them - no, we're not going to pay because we can't
do this?
TOM STAHR: These are not yes and no answers. Let me read you the
definitions, they're all tied together .... What you buy - the Authority sells
to each purchaser that purchasers percentage share of project capacity
together with associated energy from the project. That's what you all buy.
Actual delivery, if any, of electricity and electric capacity, and associated
energy purchases from the project shall be made ... scheduling. So what
you've bought is project capacity together with associated energy.
MALE VOICE: Tom, before you switch from there. Does the Bradley
junction location have anything to do with that?
TOM STAHR: Yes, that's the delivery point, Dave. What they have to do
is deliver it to the delivery point, which is Bradley Junction. What you've
bought is project capacity, together with associated energy, to be delivered
to Bradley Junction. So then you turn to the definition of project capacity -
project capacity means the amount of electric capacity capable of being
produced by the project at any time, and all times, at any and all times,
from the date of commercial operation until the termination of this
agreement under the operating conditions that exist during said times,
including periods when the project may not be operating, or inoperable, or
the operation has been suspended or interrupted, ...., abused or curtailed.
In each case, or for any reason whatsoever, after .... So, on an ongoing
basis, what you bought, is whatever capacity the project .... be it a lot or be
it none. The focus comes back to the date of commercial operation as the
sole date on which you may have some difference in expectations.
leading to that date. Three years from commercial operation and the
project produces no capacity and no energy and .... but that make the date
of commercial operation the whole focal point - that date - you have to
have the confidence that you've got what you bought. If the engineer's
reasonable in declaring "here it is, it's what you bought" you've got risk
after that. On that date, you have the question of ‘can the output be
commercially scheduled?’ That output is, the output the project is
designed or reasonably expected to produce. Whether or not that is 90
megawatts all the time it can be scheduled or not. You can make an
argument - yes. Whether it is just that it is commercially scheduling
whatever happens to the unit, even if that be zero. I imagine the
Authority .... that argument. All you have here is a definition of what you
bought, and on a day, an engineer has to say to say ‘it's all there today’.
MALE VOICE: Now, if we challenge that, who do we challenge? The
engineer?
MALE VOICE: Yes. The lawsuit, if the engineers declares the thing to be
commercially operable, you must start making the payments, and your
choice is to sue. The theory of the law suit is that the engineer has not
been reasonable, it is not a reasonable declaration. Whatever happens
after that .... whatever they want. .... was the engineer reasonable in
making a declaration. You go back to Tom's question on ... if output can't
be scheduled does require, it should provide some reasonable definition of
what the output is ....
TOM STAHR: Well, I bought 25.9% of 90 megawatts, or something like
that. By my way of reckoning, if I've taken, if the project's running, I
realize, running time and all this stuff. ... 1 megawatt - I've got 24 some
megawatts to spin. That I would like to commercially schedule from Day 1.
Schedule it just like I schedule spins from our unit number 4, 5, or other
unit ..... To keep my commitment to the intertie spin requirement, I don't
have to burn fuel. I can schedule Bradley Lake. Now if, in the
undetermined yes, that's what we can get at Bradley Junction, not at
Anchorage, then I have no problems saying we got what we bought. But, if
there's a determination that we can't get that at Bradley Junction, I think
we haven't got what we paid for and that potential lawsuit may become a
reality.
MALE VOICE: Ken, that is a response situation, so that if it takes it a
minute and a half to respond now, and they determine that it is not
responsive enough, then what your point is, is that it has to be made more
Tesponsive ...
TOM STAHR: I don't say that they are responsive enough, as far as the
spin reserve requirements, the flow .... the Alaska interties, the committee,
and so on, and determines, and they think that minute and a half is great
for spin and .... I don't have a bit of problem with it. But if they are going
to say no, that's really not it, you've got to do this, or you've got to do that.
Then, that's another matter now. If we've got to do what Hank talks about,
and start to get, you're talking about .... expensive, that I don't know, we
may be looking with our hand out too. I just, all I want is what I think we
bought and I think what those words say we bought. It's not going to be
my weird thinking on what constitutes spin or not. That'll be a proper
committee, out of the Intertie Committee, that is working on that. But I
want to say, I want to get that! I'm paying for it!
MALE VOICE: If I could predict .... the lawsuit. The lawsuit was going to
be one of engineers. It is going to be one group of engineers saying what is
reasonable to expect from this kind of project and another group of
engineers differing with that. That's probably what's going to happen.
MALE VOICE: Let me cut one more path here real quick, Dave. Just to
distinguish again, a little further. You did not expect not to pay if you
didn't get your SVS and intertie coincident with Bradley. That was not
your expectation. You knew you weren't going to get them, so did I. That
was OK with you, not OK, but that's not what we're talking about.
TOM STARR: That's not what I'm arguing about. I'm arguing about can
Bradley Lake itself, at Bradley Junction, do what I believe we bought, or
not?
MALE VOICE: OK. That's helpful, because what it will produce, Dave's
saying, is Bradley Junction, all things being equal, somebody could take,
and he's going to show, that it will demonstrate 90 megawatts.
MALE VOICE: Oh, I don't doubt that.
MALE VOICE: And you didn't expect that you were guaranteed a
transmission line and SVS, and neither did any of us.
TOM STAHR: No.
MALE VOICE: So the question really becomes, then, is the ability to
schedule, your percentage as full spinning reserves, as you would out of
any of your other generators?
TOM STAHR: Right. That is the issue that I am concerned about. Some
of the other utilities ought to be concerned with more issues, but that's all
that bothers me.
MALE VOICE: Two things. Where in the world does the turbine
response of this thing, of this beast, fit with other hydros that are out
there. I don't know.
DAVEEBERLE: All hydros are different. You get back to the basic
definition of what the project is in the power sales agreement and the
design that was before everybody, before that power sales agreement was
there. It had a 90 second response time. It's not going to respond like a
gas turbine. With Tim Stahr sitting over there saying that I'm going to use
1 megawatt of power and I want the other 24 megawatts available as
spinning reserve is absurd. It's impossible with that 90 second time. That
90 second time was on the table before the power sales agreement was
signed. I've got a real problem here saying he's not getting what he
wanted or what he thought he bought. If he didn't do his homework to
find out what he was buying, that's not our problem. I don't see where we
mislead anybody. If somebody can show me that, that's fine. Then maybe
we're on the hook, but I don't see that as being real. To expect it to act like
a gas turbine is absurd. It's not a gas turbine. It's had a 90 second
response time for 5 or 6 years.
TOM STAHR: I'm not worried about a gas turbine, I'd like to see
Eklutna - that we could use that for spinning reserves.
DAVEEBERLE: What's its response? I just curious.
TOM STAHR: I don't really know. I could find out. Stan, do you know?
STAN SIECZKOWSKI: Gates were set up to operate from 0 to 100% in 8
seconds. Response to that, I doubt would exceed that, or at all. .... it's a
different type of ....
TOM STAHR: But, I mean, ... reserves... in fact I mean, hell, survived
any of these major earthquakes. The Southcentral and Railbelt both
crashes, so obviously it works, real good.
DAVEEBERLE: Well, let me ask you a question. Does anybody here
know this wasn't a Pelton tubine at the time they signed this power sales
agreement? Does anybody know it had a three and one-half mile tunnel?
Did anybody know there was not a surge tank? I mean, all this stuff was
known. To sit here and say that ....
TOM STAHR: You picked that type of turbine in order to .... reserves, or
something to that effect.
DAVEEBERLE: So you didn't evaluate what you were getting, is what
you are saying.
TOM STARR: Well I don't think, I think there is a chance we may not
be getting what we bought. I know what you're saying. But I don't think
anybody evaluated it, I don't think any utility that evaluated that,
evaluated it as an energy source. I think each and every utility around
this table evaluated it as just another run of the mill generating unit. ....
built to serve load. Should be able to serve load.
MALE VOICE: Let's take about a three minute break here and get our
chow and then come back to the table because some people have a 1:00PM
BREAK
MALE VOICE: To kind of recap where I think we have progressed is
that I'm not hearing anybody in the room say that they have a doubt,
unless something comes up, that 90 megawatts will be attained by this
thing, can be demonstrated, without the absolute requirement of having
the SVS and the transmission installed. Is there anybody that has a
problem with that? As Tom said, it still has to do its trick - it has to do its
job. The second thing, I think, as far as scheduling the output, that the
problem there goes away when the SVS - I mean, we can get our energy
out of this thing in the interim period and we knew were going to have
some constraints in the interim period and that does not effect the
declaration of the date of commercial operation. I think we've agreed on
that. Which brings us down to the final issue of being able to count on
kilowatt for kilowatt spinning reserves. Dave, is there some work that
your committee needs to do? How close are you to finishing up and being
able to tell us what percentage or what number of megawatts out of there
we can count on as spinning reserves?
DAVEEBERLE: I think we've probably got two or three weeks. .... 20 to
30 megawatts.
MALE VOICE: I would expect that somewhere in the 20 to 30 megawatt
range, based on the baseload.
MALE VOICE: Tom, you're saying that your expectation is 90?
TOM STAHR: Yes. I don't see what is any different than any other,
what I call 'normal power plant’. I don't care if it's a normal hydro plant.
Take any number in the Pacific Northwest, something like that. Eklutna's a
perfectly good example. I think that's what we should - I believe that's
how we all evaluated it and I think that's what .... Maybe if we studied
enough and looked enough. I'll be honest, Mr. Eberle, I never conceived in
my wildest imagination that we would go to project and couldn't do that.
A lot of places they don't. And I think this is an important issue, because
one, it has to do with some money. I mean, it's not inconceivable to my
way of thinking that some further changes might have to be made to the
project. Maybe if we have the SVS and do this peak load thing and all of
that, we can form enough of a crutch for Bradley Lake to lean on. At this
point, I don't think we should rule out the possibility. The hypothetical
possibility. Might have to go back there and do something different
MALE VOICE: Charlie, as far as holding on to that money, they didn't
give us money for the trees and we .... continue to do so.
BRENT PETRIE: We do intend to hold on to the money until late next year
when the project is complete. The other thing is, there's a lock on that
money .... and the resolution, it's not even setting at a place where the
legislature can get at it.
MALE VOICE: I'm glad to hear that. .... like intertie money .... very well
spent money.
MALE VOICE: Mr. Chairman, I have a question for Brent. Would that be
after SVS is on .... to hold on to the money until that time?
BRENT PETRIE: Yes. The earliest that we could release any money with
bond indenture is December, 1992.
MALE VOICE: I think that we need, each utility is going to need to
respond relative to this peak ... thing, turbines, which is obviously an
attempt to get some megawatts into the system while help is on the way.
But I think we're right back to really a surge tank issue. I'm going to just
go around the room and ask - from your utilities standpoint, knowing what
we've narrowed this down to, what do you expect?
MALE VOICE: Well, I think we'll be on the receiving end of whatever
happens, .... either one of two ways - we'll be going because there is a
failure in the system someplace or we'll fail and rates will reflect the
wholesale power from Chugach, the additional cost of ...., so we looked at it
basically an additional source of power out in the .... piece of it so we would
be able to utilize it in some way or other. ... that's exactly where we stand
on it.
MALE VOICE: Well, I'd said before that we have some, .... I understand
what Tom is saying, but I also .... think that what he said, is that we need ...
is not a gas turbine. I don't think, .... to me we're in an unknown area, but
Tom is also right in the sense that whenever the feasibility thing was done,
that presumption, whether right or wrong, that there was spin there.
What my inclination, personally, is to say that I don't see it as litigable
issue. But, like everybody else in a sense in that I have a board to report
to and that's going to be their decision as to what they think. I brought
these up at the last meeting and I had one board member about blow a
fuse. They thought that they were going to be paying for this spin, so I
don't know. I have my own personal views, but that's going to have to be
made by my board.
MALE VOICE: I think the one thing Seward looked at was another
reliable source of power on the Kenai so they'd have a little more comfort
there and we recognized that there would be some cost differential. But
this additional cost of spinning is going to have an impact.
TOM STAHR: I guess we'd didn't really consider that we were buying a
another gas turbine, with all the characteristics of a gas turbine, down
there, but we do expect that the 90 megawatts - there to be able to
operate in a stable manner, and I don't think that is going to happen until
the SVS's are installed and/or another intertie system. It's not Chugach's
position that the addition of another generating resource could put our
system, our wholesale customer system unstable. That's a big concern of
ours.
MALE VOICE: I'd rather defer to members of the PMC here.
MALE VOICE: Well Mike, you know what our concerns are. I wrote you
a letter on it the other day. It would appear to me that going into this,
everyone knew it was a hydro facility, not a gas turbine, but it also
appears, from what I can gather, getting involved late, that there also
continued to be more concern surface as it went on. I guess to go back to
what Ken said, we're in somewhat of unknown territory. Homer Electric's
concern is well, number one, we feel we're going to out of what was
probably anticipated, but our big concern is that this is accomplished
without adverse effect to our system. We're enjoying a level of service at
this time, and we're going to insist that we continue to enjoy that same
level of service after Bradley is on, and not feel that it incumbant upon us
or our wholesale supplier to suffer the expenses of maintaining level of
service because Bradley's project happens to be located on the far end of
the system, square in the middle of our service area. Whether that is a
total PMC problem or a combination of AEA and PMC working that out, we
feel like that's what needs to take place and we'll be supporting a push for
that to happen. During the interim period of operations and then at some
point it's going to have to be viewed again with the ... SVS's.
MALE VOICE: I think I kind of already stated what my thoughts were
on it. I guess the question then becomes one of - if the unit cranks out 90
megs, in other words, if the Power Authority goes ahead, with a reasonable
determination of 90 megawatts being available, they're not going to get a
challenge that - well it couldn't commercial until the SVS and the power
line was built, or the responsiveness of the unit is in question. I guess the
thing that I feel relative to our individual bond ratings, the ability to
finance, that we should not lightly, either anyone of us or all of us, enter
into any legal challenge of this thing without a lot of consideration. I for
one, don't want the utilities to end up in a situation relative to the bond
community, where we appear to be people that you ought not deal with.
We brought the surge tank to the table a year ago. This is one way, ..... get
better response. The surge tank issue came up and was dealt with and
was put down.
MALE VOICE: Do you recall what was the improvement on that, I was
trying to recall. It didn't do much as I recall.
MALE VOICE: Does anybody know?
MALE VOICE: The surge tank gave us all but .... tunnel, the surge tank
was expended and then you actually had a turbine respond very fast and a
very fast increase but then you actually had a power reduction because of
the time it took to refill the tunnel, so that the net effect was that it was
deemed not a net benefit, I guess, by the TCS.
DAVEEBERLE: Dammit. We brought the surge tank to the table. We put
it to bed. LeResche was sitting. The other, the issue, as I see it, if we're
going to fight on this thing, we would identify that the response is not
acceptable and we'd fight and we'd end up in a lawsuit with the utility.
TOM STAHR: If I fight on it, I'm not going to fight it on response. I'm
going to fight on the issue that you cannot commercially schedule the
output of the unit because capacity is a part of the output of the unit. And
that goes back to what this committee says - if the spin, if you get the
spinning reserves, however we do it, the the capacity of the unit can be
commercially scheduled. If we can't get that spin, then the capacity of the
unit cannot be commercially scheduled. That is the issue. I don't
particularly care ... the surge tank. They had a lot of design decisions they
made during part of this project; they said they made their design
decisions to enhance spin - I question that, but that's what they said, and I
think that in the official license application and I think we had every
reason to rely upon it. So I wouldn't do it lightly, but I don't want you to,
you can decide and the committee can vote as it likes, but I'm telling you
that I intend to get what I believe we bought out of this project. I think
it's a reasonable expectation.
MALE VOICE: Just a comment. According to Dave, that 90 second
response time was up there in front of everybody and it must have been
or you wouldn't have discussed the surge tank to begin with, to try to
hasten that response time. So it's been in front of us, just, I haven't been
involved in this process, but appears to me that this is coming pretty damn
late in the game and resolution should have been done a long time ago.
This thing has to move ahead and it would be a crying shame, in my
estimation, if we stub our toes on this son of a bitch, and get into a big
donnybrooke when we're ready to go commercial within a relatively short
period of time. But again, I haven't been involved in the process and this
is just what I hear.
MALE VOICE: Maybe, in terms of expectation, we need to go one step
further, and really, and this was addressed earlier and then backed off,
this goes way back to the original intertie when we established ... spinning
reserve... There was a great misunderstanding at the time. I think we
resolved it, at least on an operational basis. Does spinning reserve mean
you do not have load shed, first stage load shed on the loss of the machine?
And in practice, I don't care whether it is 90 second response or not, you
will probably, in loss of a major machine, end up with load shed. We have
never, because of load shedding, ever denied any other machine reserve
status. The governors in our system respond at many different levels and
we have never considered that as a factor. ... considering spinning
reserves. Why should we do it for this machine? If you accept load
shedding as the ability to restore rapidly, a lot of the problem goes away.
MALE VOICE: That is almost like having ..... spinning reserve. If that's
all it takes, then we probably have a very small problem here.
MALE VOICE: I don't think so.
MALE VOICE: Who set the spinning reserves.
MALE VOICE: The utilities set the spinning reserve. And as far as ...
there is another, it's part of the IOC. The IOC is apparently going through
a load shedding study right now and in the load shedding study, the
preliminaries all indicate that the load shedding schedules will most likely
be adjusted to prevent load shedding for the loss of any major unit if that
unit does not go off on a large amount or an excessive amount of reverse
power. The spinning reserve levels for Bradley were set, the ... level for
Bradley, which was set by the committee of the utilities, said that Bradley
Lake spin reserves cannot deter or detract from the spinning reserve that
would be available from the system as a whole without Bradley.
MALE VOICE: Were those set back in 1985?
MALE VOICE: Those are set right now. So when Bradley design ....
signed the agreements in 1987 or whenever we did it, those were not the
rules?
MALE VOICE: Well I think everybody need to remember, when
everybody signed the agreements, as far as I know, there were not any
studies done on the Railbelt system. The Railbelt system was modeled
from .... South.
MALE VOICE: Exactly what I'm getting at. I think after listening to all
the discussion, we're going to get Bradley, the way Bradley is. That's the
way it's coming at us. I don't care what we do. We're going to get it the
way it is or we're going to fight. If we fight, the potential for losing is
extremely high. Recognizing that, I think as the reality, then in recognizing
that Bradley was a resource committed to before the system studies were
done, all I'm saying is, perhaps following on what Hank's point was,
perhaps what we do is we recognize that we bought Bradley the way it is
and enter it into the system and make a declaration relative to it and if it
isn't 100%, then declare it at some lesser number but be well aware of
what we're doing. I think that you may be right - that's more of a political
decision, Dave, than it is a technical exercise.
MALE VOICE: So far as the load shed?
MALE VOICE: Yes.
MALE VOICE: It's a political decision. ... to make the addition of Bradley
not track on the system response. That is how Bradley Lake spinning
teserve levels will be set.
TOM STAHR: There are funds that are going to be encumbered for a
year?
MALE VOICE: Until the SVS.
MALE VOICE: December 1992.
TOM STAHR: But the problem you have - once you declare commercial
on channeling ... the changes to that project after that point are 100% on
the purchasers.
MALE VOICE: Is there any possibility of some kind of agreement that
even if it is declared commercial, if there are problems that arise during
the operation for a specified period of time, that the Authority would
consider that as a project cost ...? Because we're limited in so many way
about what we can tell, about what we know.
CHARLIE BUSSELL: I think that's a good statement, and I think the
Authority's position would be that it could be technically operational
without being complete and if something like that occurred, that's what
we'd recognize and we'd want to go back and look at it and fix it. The State
is not, although we're not standing up here for everyone of you to take a
shot at as .... concrete and saying you can't shoot at us anymore. But we
want that thing to operate more than you. We want those power lines to
be built as much or more than you do. We want to a good Southeastern
Alaska intertie as much or more than you do. Quite frankly, the Governor
that's elected right now is different than any other we've had in the last 12
years and I think in the next, at least several years, that he's going to be
easier to work with, that these kinds of matters, and he's not going to let
us ...
MALE VOICE: Any individual, as Tom has gone through your concerns,
naturally free the utility in a participant to do anything that they want to
do relative to the commercial operation declaration. As Tom says, if you
decide to do something .... but at this point, with what I know, I am
prepared as a utility to understand that 90 megawatts may be
demonstrated without actually putting 90 megawatts into the system. I've
accepted that. That the SVS won't be on-line before the damn thing is
declared commercial, and I've known that for a long time. That there will
be no transmission lines on-line before this thing is declared commercial,
and I've known that for a long time. And that this governor has a minute
and a half response, and I've known that for a long time. And there is
nothing we can do, at this point, reasonably, about any of those things,
unless we decide to oppose the commercial operation. At this point in
time, I think we've heard Tom's concerns, we've narrowed the issues down
where we don't have a problem as a group. But the 90 megawatts, that's
probably going to happen, or with the transmission line or SVS, they're
going to be late. But the response thing is what is cropping up here and
the AEA is not offering to put in whatever it would take to correct that, at
this point in time, and that's where we're at.
TOM STAHR: Well wait a minute. Part of this I got lost on. My
suggestion there, and Charlie's response to that, did that just drift away?
MALE VOICE: It sounded like a good faith statement to me. It didn't
sound like he agreed to ....
TOM STAHR: I didn't say he agreed. I said my statement and Charlie's
statement, and then what you came on saying is that you accepted
everything and therefore we are where we are. I think what we were
talking about is worth exploring, and I thought that's what Charlie thinks.
MALE VOICE: To do what? So we're specific - to do what? I'm talking
about that if it is declared commercially available, that for an agreed
period of time, that the Bradley system will not operate or will not be
stable or will cause problems. That if it is something that can be fixed, that
. encumber funds, whatever, that the Authority would agree to go back in
and to do that. And I think what Charlie said was, is that it could be
commercially operable, but not
CHARLIE BUSSELL: We might be willing to talk about a project that was
commercially operable but maybe not finished but if you thought ... an
issue, that the dam literally couldn't meet that, if it was something
indefensible on our part, if it was a design flaw and clearly out there -
then we'd have to look at it.
MALE VOICE: But you're talking about after your declaration of
commercial operation.
CHARLIE BUSSELL: After our declaration.
TOM STAHR: What I would like to suggest is that some sort of limited,
restricted commercial operation - I think we've agreed we're not going to
withhold the bond payment on this .... I certainly have no problem going
ahead and making the bond payments. What I don't to do, I want some
legal relief from this thing that it's all on our nickel, I understand your
good faith, but I'm talking about some legal situation where we do have a
period of time, maybe until we get the SVS's in, before you have to release
the money, so we know the other things are right, and we still can go back
on a 50-50 thing. Something like that, then there's certainly no reason to
talk litigation. But I'm afraid that if we can't get some middle of the road
position like that, we may have to institute litigation just to defend
ourselves.
MALE VOICE: Dave, he's responding to your point, after he declares it
commercial. Tom's asking for the thing we've all talked about, which is
some middle ground, which is what you were asking for, that I didn't hear
you say yes to. Could we clarify that?
CHARLIE BUSSELL: I think the bond declaration speaks to the specific
issues that I don't think we can avoid. We can't declare a partial operation
of the facility. Can we do that?
MALE VOICE: No.
CHARLIE BUSSELL: If we curtailed that in any way, with any kind of a
separate agreement, we'd have to go back to the bond holder. It's that
simple.
TOM STAHR: I would like to have that point of issue researched a little
bit.
CHARLIE BUSSELL: We did that. You've got the papers. It's not a new
issue.
MALE VOICE: Just for a clarification of what I heard Mr. Bussell say,
was that if there was a flaw or there was a problem with the design of the
project, and that I think probably everybody feels is probably not going to
happen. But, that's one step. The next step is, concerns me, is the fact that
the AEA did go out farther, early out and indicate that they wanted to put
some funds toward an SVS, try to fix the problem that was perceived at
that time to be a stability problem. If the project was considered
commercial, which is what Dave indicated, go ahead and allow it to go, not
Tesist that, in fact to support that - allow it to go commercial. There is
encumbered funds that have to remain there. Can we get support,
agreement from AEA, that those funds would be utilized if necessary to
solve the problems that at this point may not be known? We assume
we've got warranty problems. We've got warranty coverage. We've got
omissions and errors coverage as far as design. But I'm talking about
solving the problem of stability down the road. Between now and SVS and
maybe after SVS.
MALE VOICE: Is that essentially what you were saying? In other words
- declare commercial operation - not object to that.
TOM STAHR: Well I'm assuming from what we've heard here, and I'm
agreeing with you on this, that declaring commercial operation is
practically a given, regardless of what ... but, I'll say, if there are design
flaws, if there's any of this system that is not too - give us time, give us
some operating time, give the dam operating time, and we have some
funds there that we've agreed to pay back anyhow, we could use some of
that to do this.
DAVEEBERLE: There are two different concepts here and we all need to
keep them the same in our minds - that they are separate. Commercial
operation is important because it is the date when your payment
obligation starts. That's why it's an important event. It triggers this
becoming a contract - it triggers the take and pay obligation to a payment
obligation. There is nothing about that date that .... has to be done, or that
50-50 matching stops on that date. The 50-50 matching is tied to
something called the cost of acquisition and construction for which the
bond resolution has a long, several page definition, but which basically
says the cost of getting the project done. I can give you a long and
technical answer if you want. But there is nothing in that definition that
says this is the same date as commercial operation. If the project takes
two years after commercial operation to actually work out the kinks and
get it done, the cost during that two years should still be project costs
which are matched on a 50-50 basis until you hit 350,000,000. It
shouldn't take a special new agreement or anything of that sort. It is
anticipated that at the point where the project was good enough to run and
produce electricity, the State could declare it as such and start getting you
to pay the bills. But that is not what we've done with the obligation to pay
their half of the costs to finish up whatever is left to be finished up.
Kelle _MALE VOICE: = Charlie first and then Norm.
END OF TAPE
BRADLEY LAKE PMC MEETING June 6, 1991 Side 6
MALE VOICE: 2? megawatts gas turbine ..... right now. Somewhere
around 65 we're out of gas turbine right now. Somewhere around there.
In 80 with, and on the quarterly, the minimum numbers have to do with
the historical level of load change Kenai has been subject to considering the
loss of the 115 line south. The feeling of the TCS is that Homer should not
be subject to any more chance or risk of load change considering the loss of
the TCS and that what they had .... been subject to in the past. So what
that means is since in the past although there may have been a lot of
heavy import or export to the Kenai, that we always had at least one gas
turbine, most of the time, actually, in the last several years we've had two,
which would make the Kenai be subject to a certain amount of load shift.
So what the TCS has done, is that they've gone through the dispatch
records for the past year to get an idea of what risk Homer was subject to
during the past year. They said OK, the risk that Homer was subject to
load change, assuming the loss of line, would not be any less than or any
more than what they've been subject to during the last year. So what that
is effectively going to do is restrict the amount of power that is imported
to the Kenai without a gas turbine. That level is going to be significantly
higher that the import level which was experienced with the gas turbine. I
guess that's it in a nutshell.
MALE VOICE: So that's where we get the 10 and 40? You had the
window of 40 to 60 and then an expanded window of 10 and 40.
MALE VOICE: Yes. Right. Those numbers aren't set yet. The TCS has
not set the minimum level yet. But that's tentative.
MALE VOICE: The 10 and 40 are estimates at this point.
MALE VOICE: The 10 has actually been set by the scheduling allocation
committee as a minimum, scheduled amount for Bradley Lake, so that's set.
MALE VOICE: You could turn it off at O (zero).
MALE VOICE: You could turn it off and use it the same .........
MALE VOICE: I received this ..... 3 SO. asesers
MALE VOICE: We've already done that once.
MALE VOICE: There are a lot of things in that interim period that we
probably need to look at on this one. We'll stick it back on the agenda.
MALE VOICE: The whole interim period is probably what we should
look at.
MALE VOICE: The only thing we should be aware of if we decide to
delay this is that effectively July 26 when this plant, when Bradley Lake is
declared commercial, whatever constraints or operations or whatever we
have got to be in place before then, because that's essentially when this
would start, would be July 27, 1991.
MALE VOICE: That or September 1, 1991. I mean if you're going to be
racking it up and down, and testing ......
MALE VOICE: Well, I would assume that at some point in time, we
would be careful enough to turn off any turbines which were required for
testing so that we would be wanting to schedule Bradley Lake as if it were
commercially operable. That's the whole point and intent of this, and I
would assume that for some period of time we operate some minimal
turbine for reliability purposes until we get a good feeling for the plant.
But then there's going to be during that time period before September 1
where the plant is essentially operating as if it were commercial.
MALE VOICE: OK. We've got a couple of other items here. Under
Approval of PMC Expenses and then we've got a couple of attached
additional agenda items. Ron, on the PMC expenses, there are close to
enough of these to send around. While they are being passed around, I'd
entertain a motion to approve.
MALE VOICE: Approve.
MALE VOICE: Is there a second?
MALE VOICE: Second.
MALE VOICE: Take a minute to look at them and see if there is any
discussion. When you're ready, somebody call for the question.
MALE VOICE: Excuse me, Mike. Just to back up for a moment on this
other item. See if I'm correct. At this point in time the PMC is really not
interested in or convinced that it is in their best interests to commit a
turbine to allow a broader window of capability out of Bradley. You'd
rather wait until the initial test period and then July 26, as I understand
AEA now, the utilities will have an opportunity to dispatch and run it up
and down and prove it out until September 1, during that particular period
of time and I suppose that is going to tell us a lot as to whether or not, in
fact, a unit is going to have to be committed for satisfactory operation, to
everybody's satisfaction.
MALE VOICE: Dave's Chugach then, or ML & P, whoever has to run the
unit, or AEG & T, would be compensated during the test period, which we
assume will run till September 1 , approximately, for any starts. The
excess operation. You are exactly right. I think we will learn some things
about whether we want to buy that ability to expand. I think each person
here wants to go back to your shops and talk about that question. That's
right on my list here. To talk to our people about whether they want that
expanded operation or a flatter operation as built. To me it's just
economics.
MALE VOICE: Right. I appreciate that. But it's held in abeyance, it may
or may not happen.
MALE VOICE: I think what we ought to do is bring that back up, maybe
in our August meeting, well we've got it next time on the agenda so we'll
be kicking it around.
MALE VOICE: OK. Chugach in the meantime has committed to run a
turbine that quote "test period". That's AEA's test period, is that correct?
Or through September 1. What test period are you talking about? The
utilities test period or AEA's test period?
MALE VOICE: The date of commercial operation.
MALE VOICE: Well they may declare that July 26. Is that ....
MALE VOICE: No. No. He's not going to do that on us. Eberle's agreed
1Osiee ; Well I just want to understand.
MALE VOICE: So I think Dave's point is that operation of the turbine
during the test period is not the same as operation of the turbine today. I
think the utilities want to see this too. Regardless of what goes on running
24 hours per day even if you pay for it or not.
MALE VOICE: And it has to be a good faith deal where we kind of leave
it with Chugach, it has to run a machine that they wouldn't run because of
your own requirements, then we've agreed that this would be a cost of
testing, that you'd be reimbursed, but Bob, during that particular period,
after September 1, is where we're talking about buying from Dave the
services of .....
MALE VOICE: OK. After that.
MALE VOICE: I agree after July 26 it's appropriate to cost. I guess
between July 26 and September 1 we ought to know what the plan is and
what the cost of that plan is and then we need to debate in our own minds
whether that is appropriate to our own costs.
NORMAN STORY: Just to follow up on that, it seems like what we need to
do is Homer and Chugach will have to talk some on this but also there's
been some questions raised as to the cost and the limit, that we need to
come back to the next meeting, maybe prepared to do a little more than
just kick it around and come to a conclusion prior to July 26 ... operate
during the test period and beyond the test period.
MALE VOICE: That way you start the conversation by saying “Dammit,
Highers, I thought you were going to run that until September.
STAN: I can answer the question. Yes. At the last operations dispatch
meeting Chugach gave the committee a proposal here and we are
considering that and we will be discussing it at the next meeting on the
18th of June.
MALE VOICE: How do the costs seem?
MALE VOICE: Very reasonable.
MALE VOICE: All of the utilities are going to incur costs during the
testing period. Golden Valley, I'd think you be ..... because we can't ... all ...
we don't have it.
MALE VOICE: .... Chugach system which we could get ... up... They have
to be the incremental portions.
MALE VOICE: It seems to me though that if that group agrees you've
got enough reps on his group, that if you agree to how the costs will be
reimbursed, that whether they are mine or Chugach's or Tom's or whoever
or AEG&T's would have to then work. OK. We're going to rip right ahead
here. Is everyone getting sick of this?
MALE VOICE: Mr. Chairman. We're divorcing, I guess I have a problem.
We're divorcing two issues that are caused by technically the same
problem and that is response. And they're the same issue.
MALE VOICE: In the interim sense, I'd agree with that. In the long
term sense, I think we'll still be here by Thanksgiving.
MALE VOICE: Anybody else want to say something? OK. First of all, if
there's no objection, the next meeting is July 2. Oh, excuse me, did
somebody call for a question on that or do you have questions? Discussion.
MALE VOICE: These are the categories we talked about before. Most of
the expenses are for three or four months, depending upon how people
reported their aggregate. Some of you didn't .... didn't have them or you
didn't turn them in, maybe next time. The most important thing is
Marcey's memo which follows up on what was said at the last meeting - it
won't be reimbursed unless there is backup. I'm not sure what is
adequate backup, but if you feel that .... we have been audited since we did
this last .... backup for these expenses. Any further discussion. Terri, call
the roll please.
City of Seward yes
Matanuska Electric yes
Chugach Electric yes
Homer Electric yes
Golden Valley Electric yes
Municipal Light and Power yes
AEA yes
MALE VOICE: Thank you, Terri. A couple of items were added to the
agenda at the request of Dave Highers, with two motions forwarded from
the TCS. I guess I'm not sure what's happening. Do you have those
motions in front of you? OK. You have in front of you the two motions
from the TCS. Dave do you want to hold forth on that.
DAVE HIGHERS: Well, the first one is pretty straight forward and that is in
the interim period, and this will be quickly retired after the SVS
installation and that's just the transfer to our .... at Soldotna from Fish
Creek and that will allow, I think it's either 10 or 15 megawatts, I think it's
10 megawatt increase in the Bradley Lake output during the interim
period, and that cost was estimated at $30,000. The second motion was
the motion which did not pass .... Mr. Eberle and ML&P, was to install
transfer turbines between East Lake and Soldotna and Soldotna and Quartz
Creek. One difference at the meeting. The cost was estimated to be
$30,000 for Chugach, $45,000 for Homer, with the total not to $75,000
subject to Homer preparing their own cost estimate. Homer prepared a
cost estimate of $110,000 which is different from the TCS preferred
motion.
MALE VOICE:
MALE VOICE:
MALE VOICE:
MALE VOICE:
OK. Let's get it on the floor. Motion approved?
Move approval of Motion 1.
Motion seconded.
Discussion. Terri, call the roll.
Matanuska Electric yes
Chugach Electric yes
Homer Electric yes
Golden Valley Electric yes
Municipal Light and Power yes
City of Seward
AEA yes
MALE VOICE:
MALE VOICE:
MALE VOICE:
MALE VOICE:
MALE VOICE:
MALE VOICE:
MALE VOICE:
yes
Motion #2. Is there a motion?
So move.
Is there a second?
Second.
Discussion.
What are we buying with #2.
Well, I've been hearing little rumors here that this is kind
of a number givaway.
MALE VOICE: To be honest with you, I'm not prepared to deal with it. I
was hoping that maybe Dave would. I don't have that answer, other than
that I do know that there might be some differences based on the cost of
the design and possibly installation.
MALE VOICE: .... do you want to take a look at and bring your excuses
with you next time.
MALE VOICE: I think Dave can.
MALE VOICE: The basic differences are that we design ours in-house
and they design theirs out. We construct a lot of these and they don't.
MALE VOICE: Possibly we could get Chugach to design ......
MALE VOICE: Further discussion?
MALE VOICE: If not, a motion to table ..... Terri, call the roll.
MALE VOICE: Whoa. I think the motion's tabled. I'd really like for ...
MALE VOICE: Ken just seconded. If there are objections to the motion
tabled. Hearing only Norm. OK. The stuff on backup from Marcey. And
anything you can get ahead of time, Norm. If you can give it to me or ....
MALE VOICE: Actually, whatever money he gets out of selling those
trucks that we bought to build that line could probably be placed in
another deal.
MALE VOICE: Anybody have a problem with a July 2 meeting. Hearing
none. We are ready to adjourn.
MALE VOICE: We got a date.
MALE VOICE: Mr. Chairman, not exactly. I'd like to add one other item
to the agenda. Informational at this point. Basically, we're supposed to
have is another possibility to increase energy at our project by creating
another diversion. Actually, two possible diversions, one of which is very
minor and one of which is pretty major. The minor one we've done some
research and worked with the various resource agencies and basically
have their blessing to go ahead with the minor one and we're pursuing
that with FERC. It's got a pretty rapid payback. I don't think we're going
to have any problem getting it through FERC and .... this summer. The
major one is going to involve a lot of studies. We're going to have to do an
environmental assessment on it, and it's going to take several years to
even think about that. Basically, what it amounts to is diverting some of
the drainage area from the upper Battle Creek which to date, we have not
touched. The minor diversion consists of basically digging a shallow ditch,
a couple of thousand feet long and diverting water that comes from a
water fall and presently drains into Battle Creek, diverting it to Bradley
Lake. The estimated annual benefits of that range from $184,000 per year
to $316,000 per year depending on what value you put on energy. The
cost, when Stone and Webster first estimated this, they figured about
$792,000. After looking at it this spring, I think it's going to be $400,000
or less. So potentially, you could pay this thing back in two years. We're
going to FERC asking for the approval. We don't have to make a
commitment right now. What I propose, to come back to you with some
firm numbers on the cost and then assuming that we get the go-ahead
from FERC, build it this summer.
MALE VOICE: The minor one?
MALE VOICE: Right. The major one, there's no hope of doing it this
year, and I would say that you're talking two or three years away if we
could even do it. We're not pursuing that at this time. If you want to
pursue it that's another matter for the PMC.
MALE VOICE: On motion to proceed. Do so.
MALE VOICE: I don't need an action right now.
MALE VOICE: It looks like a great opportunity that we ought to pursue.
MALE VOICE: What I would do, is can come back to the next meeting
with the numbers of what it would cost.
(a! MaEDYOICE: Without objections, we'll do that. An on the major one,
you're going to come back with more .... Anything else? Without objection,
we're adjourned.