Case Background
As part of the continuing fuel and purchased power
adjustment and generating performance incentive factor clause proceedings, an administrative
hearing was held on November 2, 2021. At the hearing, certain stipulated issues
for Duke Energy Florida, LLC (DEF or Company), Florida Power & Light
Company (FPL), Florida Public Utilities Company (FPUC), Gulf Power Company
(Gulf), and Tampa Electric Company (TECO), were approved by bench decision. The
Commission approved stipulations on all but one of the issues before it
concerning each of the investor-owned utilities (IOUs) actual and projected
fuel and capacity costs. The only issue left outstanding is Issue 1C, a company-specific
issue with respect to DEF. More specifically, the subject matter of Issue 1C
concerns the recoverability of replacement power costs associated with the
January 2021 through April 2021 forced outage of Crystal River Unit No. 4
(CR4). CR4 is an approximate 715 megawatt (MW) coal-fired steam unit located in
Citrus County, Florida. Through Issue 1C, the Commission is being asked to
determine if DEF’s actions were reasonable and prudent with respect to the
factors leading to the forced outage of CR4, and to determine if the associated
replacement power costs are recoverable by the Company.
The Florida Industrial Power Users Group (FIPUG), the
Florida Retail Federation (FRF), the Office of Public Counsel (OPC), and White
Springs Agricultural Chemicals, Inc. d/b/a PCS Phosphate – White Springs (PCS
Phosphate) filed a joint brief concerning Issue 1C, as well as DEF, on November
15, 2021.
Staff presents its analysis and recommendation on the
prudency of DEF’s actions and the recovery of replacement power costs
associated with CR4’s forced outage (Issue 1C) herein.
The Commission is vested with jurisdiction over the
subject matter of this proceeding by the provisions of Chapter 366, Florida
Statutes (F.S.), including Sections 366.04, 366.05, and 366.06, F.S.
Discussion
of Issues
Issue 1C:
Has DEF made appropriate adjustments, if any are
needed, to account for replacement power costs associated with the January 2021
to April 2021 Crystal River Unit No. 4 outage? If appropriate adjustments are
needed and have not been made, what adjustments should be performed?
Recommendation:
No. Failure of the plant operator to follow written
procedures, without supervisory approval, directly led to the outage at Crystal
River Unit 4. As such, replacement power costs should not be borne by retail
ratepayers. DEF should credit its customers $14.4 million associated with retail
replacement power costs for the Crystal River Unit No. 4 outage through its
2021 Final True-Up filing. (Wooten)
Position of the
Parties
DEF:
No adjustments are necessary because DEF’s actions
related to the outage were reasonable and prudent. The testimony and exhibits
clearly demonstrate that DEF could not have known that the highly reliable
Beckwith manual sync check relay failed. While the operating procedures were
changed as a result of this incident, it was not reasonably foreseeable for DEF
to have planned for this unexpected failure in advance of the incident at
issue.
FPL:
No position.
FRF, FIPUG, OPC, PCS Phosphate: No. The utility
bears the burden of proof for recovery of costs claimed. DEF did not
demonstrate that its actions causing damage to the plant and the related
outages were reasonable and prudent, or that replacement power costs should be
borne by customers.
Gulf:
See FPL position stated above.
TECO:
No position.
NUCOR:
No position.
Staff Analysis:
Parties’
Arguments
DEF argues that no adjustments are necessary with respect
to replacement power costs associated with the January 2021 to April 2021
forced outage of CR4, and that these costs should be deemed fully recoverable.
DEF asserts that the testimony and exhibits presented with respect to this
matter clearly demonstrate that it could not have known that a highly-reliable
plant component (a Beckwith manual sync check relay) failed, which was
identified as a “root cause” of the outage. (DEF BR 5) Further, even though operations
procedures were changed as a result of the incident, it is not reasonably
foreseeable for DEF to have planned for this unexpected failure of the manual
sync check relay in advance of the incident. (DEF BR 3)
FRF, FIPUG, OPC, and PCS Phosphate (Joint Intervenors)
argue that DEF did not demonstrate that the actions which led to the forced
outage of CR4 were reasonable and prudent, or that replacement power costs
should be borne by DEF’s customers. Further, the DEF operating team at CR4
failed to follow established start up procedures and thereby damaged the plant
when attempting to synchronize the generator to the electric grid. (Joint
Intervenors BR 2) The Joint Intervenors argue that the Commission should find
that DEF failed to demonstrate that it acted prudently in operating CR4 with
respect to the actions leading to the forced outage. (Joint Intervenors BR 15)
Analysis
In its brief, DEF states that the Company’s actions
leading up to the CR4 outage were prudent and reasonable. DEF is requesting
cost recovery of the replacement power costs associated with the CR4 outage. To
calculate replacement power costs, DEF ran a simulation model that produced the
total system costs assuming CR4 was fully available compared to actual system
costs for the outage time period. The difference between the two costs
represents the estimated system replacement power cost for the outage time
period, which totals $14.5 million ($14.4 million retail). (EXH 59, 67) No
party disputed the estimated system replacement power costs at the hearing.
The events leading up to the forced outage at CR4 occurred
when the operator was attempting to synchronize the unit to the grid, on
December 17, 2020. Synchronization is a process by which the generating unit is
connected to DEF’s power system by matching the generator’s electric
parameters; such as voltage, frequency, phase angle, and the power system’s
electric parameters. (TR 335) It is important that the electric parameters of
each are matched as closely as possible to avoid excessive torque placed upon
the generator rotor, which could lead to machine damage. (TR 436) Standard
Operating Procedure (SOP) at CR4 is to synchronize the unit to the grid in
automatic mode; but manual synchronization of the unit is permitted and has
been done at CR4 before and after the outage event. (TR 335)
DEF’s operator unsuccessfully attempted to synchronize CR4
to the grid three times, using the automatic synchronization process. The
operator’s subsequent actions resulted in an out-of-phase synchronization
attempt of CR4 to the grid causing damage to the generator rotor and directly
leading to the forced outage event. The unit remained in a forced outage status
until all repairs and inspections to the generator had occurred. (TR 335 - 336,
445; EXH 8; EXH 54) This event also caused a relay malfunction that tripped the
Citrus Combined Cycle Power Block 1 (Citrus) station offline. (TR 417 – 418) Replacement
power costs for Citrus are not at issue here. (EXH 8, EXH 54)
Both DEF and the Joint Intervenors agree that the standard
for review of prudence is “what a reasonable utility manager would have done,
in light of the conditions and circumstances that were known, or should have
been known, at the time the decision was made.” (Joint Intervenors BR 2; DEF BR
3) It is also clear that DEF has the burden of proof to meet this standard by
providing credible evidence in the record.
The Joint Intervenors argue that DEF has not met this burden in this case, and
staff agrees as discussed below.
In keeping with common industry practice, DEF performed a
Root Cause Analysis (RCA) that explored the contributing factors of the event,
the condition of the impacted unit, and corrective actions to prevent repeat
occurrences. (TR 336 – 337; EXH 8) The RCA was performed by a team of DEF
employees, including DEF witness Simpson. As determined by the RCA, the two
root causes of the CR4 outage were (1) the failure of the Beckwith Manual Sync
Check Relay (relay) and (2) the operator’s failure to follow proper operational
procedures. The RCA also identified seven contributing causes related to
training and communication issues that contributed to the outage. (TR 337; EXH
8)
The first root cause identified in the RCA was the failure
of the protective relay. DEF witness Simpson described the relay as a highly
reliable protective device, with an exceedingly low failure rate, designed to
prevent the unit from attempting to synchronize to the grid in an out-of-phase condition.
(TR 338, 451) The relay was originally procured on February 28, 2002. The relay
was then relocated to the CR4 unit and was last functionally tested in April
2020. (EXH 8) DEF states the relay has no manufacturer published life
expectancy or testing requirements; however, DEF maintains a six-year
maintenance interval for protective devices, including the relay. DEF asserts
that the relay was properly maintained and received regular calibrations before
its failure in 2020. (TR 351 – 352, 354 451; EXH 54) The evidence in the record
reflects that the equipment was reasonably maintained and the failure of the
relay was reasonably unforeseen by the Company. DEF contends that had this
device performed as designed, the outage would not have occurred. (TR 338)
Under such a scenario, the operator’s actions would also have gone unnoticed.
As stated by DEF witness Simpson:
If he closed it at the correct time and the device was
failed, we never would have known. Had he closed prematurely and the device had
been good, this event wouldn’t have happened. So when he closed early, the
protective device failed to do its job, and that’s what led to the event. (TR
396-397)
This statement highlights the importance of following
written procedures for critical operations. Staff recommends that the failure
of the operator to follow written procedures, as discussed below, directly and
independently led to the outage event at CR4.
The second root cause of the outage is the operator’s
failure to follow written operational procedures which led to the out-of-phase
synchronization. In interviews conducted as part of the RCA, the operator was
not attempting to synchronize in manual mode; but rather, was attempting to
reset the synchronization circuit to permit automatic synchronization. (EXH 8,
Page 2) According to the RCA, the operator did not follow proper procedures by
attempting to reset the synchronization circuit to permit automatic
synchronization. The proper written procedure would be to place the unit in a
safe condition prior to repositioning the synchronization switch handle. (EXH
8, Page 4) The startup procedures states that, “If [a]uto synchronization is
inoperable on [U]nit 4, then use manual sync listed in Enclosure 5.” (EXH 8,
Page 4) The procedure that the operator was attempting to perform was neither a
manual synchronization nor automatic synchronization and was not SOP for
synchronization at CR4. (TR 335, 445; EXH 8, Page 4) The RCA states: “The
operator understood the synchronizing relay would not allow an out-of-phase
synchronization.” (EXH 8, Page 7) The operator’s understanding of the relay was
based on past experience and training. (TR 338) Therefore, the evidence in the
record does not suggest the operator acted with malice or intentional disregard
for safety. However, the incident does highlight the importance of both
following written procedures and not overly relying on protective equipment.
Under certain circumstances deviation from established
written procedures may be warranted, albeit with supervisory concurrence. The
RCA states: “…the operations crew attempted unsuccessfully to synchronize to
the grid four times without a questioning attitude and without consulting the
Operations Superintendent and/or Station Manager.” (EXH 8, Page 4) According to
DEF witness Simpson, the supervisor was present during the troubleshooting
process but was unsure if the operator received supervisory approval to deviate
from written procedures. (TR 439 – 440, 445) However, the RCA does not state that
the operator received supervisory approval to disregard written procedures. (TR
430, 439 – 440) DEF witness Simpson states there is no written procedure
addressing the procedure the operator was attempting. However, this procedure
had been utilized at CR4 by the operator prior to the outage event. It is
further established that this procedure was not approved or preapproved at any
point before the outage event. (TR 446 – 447) DEF witness Simpson testified
that the operator was properly trained and had the supporting materials necessary
to correctly and safely operate the unit. (TR 339) However, according to the
RCA, this is in contrast to the supervisor, who had not received adequate on-the-job
training prior to the incident. (TR 385-386; EXH 8, Page 4)
Prior to the outage incident, the operator attempted to
synchronize the CR4 unit to the grid three times in automatic mode over an
approximate eight-second time period. For two of the three attempts, issues
that may have been preventing automatic synchronization were identified, but
the third attempt failed for an unknown reason. (EXH 8, Page 3) The RCA did not
identify a root cause for the failed third attempt. DEF witness Simpson testified
that proper procedure after a failed synchronization attempt is for operators
to perform a walkdown for the purpose of discovering any issues, correcting the
issues and attempting synchronization again. (TR 401; EXH 54) According to the
final version of the RCA, this walkdown process was performed for each of the
three automatic synchronization attempts. However, this statement is
contradicted by a comment in a draft version of the RCA that states: “The
operators did not complete a thorough walkdown after each trip, therefore each
time they attempted to sync there was another item holding them out.” (TR 408;
EXH 8, 64) DEF witness Simpson did not provide any explanation as to the
discrepancy between the statement present in the draft RCA and the final RCA. The
brief eight-second timeframe in which the synchronization attempts occurred,
and this contradictory statement, leads staff to question whether a thorough
walkdown occurred prior to each synchronization attempt. Since the CR4 outage
event, the startup procedures have been revised to include guidance to contact
either the Operations Superintendent or Plant Manager in the case of multiple
failed automatic synchronization attempts. (EXH 54)
If the operator had followed written procedures, staff
believes the outage would not have occurred and the failed relay would have gone
undetected until DEF performed an inspection. If the relay had not failed, then
the operator’s disregard of written procedures would have been inconsequential.
The record does not satisfactorily establish that either a thorough walkdown
occurred after each synchronization attempt or that the operator received
supervisory approval to deviate from the written procedure. Based on the
evidence in the record, staff recommends that DEF has not adequately proven
that its actions were reasonable and prudent.
Conclusion
Failure of the plant operator to follow written
procedures, without supervisory approval, directly led to the outage at Crystal
River Unit 4. As such, replacement power costs should not be borne by retail
ratepayers. DEF should credit its customers $14.4 million associated with retail
replacement power costs for the Crystal River Unit No. 4 outage through its
2021 Final True-Up filing.
Issue 2:
Should this docket be closed?
Recommendation:
No. The 20210001-EI docket is an on-going proceeding
and should remain open. (Brownless)
Staff Analysis:
The fuel docket is on-going and should remain open.
