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IN THE MATTER OF AN ARBITRATION CONCERNING the K POWER PURCHASE

ARRANGEMENT

BETWEEN:

- GENERATION PARTNERSHIP

Claimant

and

- ENERGY CORPORATION and THE -

Respondents

Award

November 14 , 2016

I BACKGROUND

1. The Claimant, - Generation Partnership ("-" or “Owner”) was, at all material

times, the owner and operator of a coal-fired thermal electrical generating facility

referred to as the K power plant.

2. The Respondent, - Energy Corporation (“-” or “Buyer”) is an Alberta corporation

with its head office in Calgary.

3. The Respondent, - is a corporation established by the Electric Utilities Act

(“EUA”)1 and further governed by the - Regulation.2

4. The K power plant is located approximately 70 kilometres west of Edmonton,

Alberta. One of the generating units, unit 1 (“K 1” or the “Unit”), is at issue in 1 RSA 2000, c. E-5.1. 2 Alta. Reg. 158/2003. 3 Alta. Reg. 167/2003. 2 Alta. Reg. 158/2003.

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this arbitration. It was manufactured by H in 1981 and commissioned in 1983. It

was originally designed with a rating of 400 MW but in 2012 it was uprated to

428 MW (“Uprate” or the “2012 Uprate”).

5. Since January 1, 2001, K 1 has been subject to the K Power Purchase

Arrangement (the “PPA”), as described in greater detail below. The Committed

Capacity for the Unit under the PPA is 383 MW. The PPA term for the Unit ends

on December 31, 2020.

6. - is the Buyer under the PPA, which means that - receives the generation capacity,

electricity output and ancillary services capacity from K 1. - pays - a regulated

wholesale price for the electricity that is set by the PPA's terms. - then sells the

electricity and receives any margin between the regulated wholesale price it pays

for the electricity and its retail sale price.

7. The - has certain rights and responsibilities under the PPA, the - Regulation, and

the Power Purchase Arrangement Regulation3 and the EUA. Under the PPA,

the - is also entitled to participate in any arbitration brought between an Owner

and a Buyer.

8. Although drafted to look like and designed to function in a manner similar to a

commercial contract between the Buyer and Owner, the PPA has been described

as a form of regulation, promulgated under the Power Purchase Arrangements

Determination Regulation4 and continued by s. 96(1) of the EUA.

9. The PPA recognizes that in certain circumstances, for reasons beyond its control,

either the Owner or Buyer may be unable to perform its obligations under the

PPA and can claim Force Majeure under Article 14 of the PPA.

3 Alta. Reg. 167/2003. 4 Alta. Reg.175/2000.

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10. During periods of Force Majeure, pursuant to Schedule D, section D 3.7 of the

PPA, the operation of the Availability Incentive Payment (“AIP”) mechanism is

suspended, such that - is relieved of its obligation to make penalty payments to -,

even though Actual Availability is less than Target Availability. Additionally,

pursuant to Article 14.4 of the PPA, - is relieved of its obligations to make

Capacity Payments to -. The obligation to make Capacity Payments during

periods of Force Majeure shifts to the -:

14.4 Effect of Force Majeure

During any period in which the Owner’s obligations to perform or comply with an obligation under this Arrangement are suspended pursuant to Section 14.1, the Monthly Capacity Payment shall be reduced as provided for in Schedule C to reflect the availability of Committed Capacity of each Unit during such Month. The Owner shall be entitled to payment from the - of the difference, if any, between the Provisional Capacity Payment and the Monthly Capacity Payment for such Month.

11. At approximately 3:29 p.m. on March 5, 2013, the K 1 stator ground fault

protection system tripped the Unit offline (the “Trip”) and the Unit remained

offline until October 6, 2013.

12. As a result of the Trip, - issued a Notice of Force Majeure on March 25, 2013.

Force Majeure is claimed from 4:00 p.m. on March 5, 2013 until 10 p.m. on

October 6, 2013. This period has been referred to by the parties as the “Event”.

13. On March 27, 2013, - requested that the - confirm that a high impact low

probability event (a “HILP”) had occurred, which is one of the components of the

definition of Force Majeure in the PPA. The - did not issue a confirmation.

14. The Respondents deny the Event falls within the definition of a Force Majeure

under the PPA and also deny the Event was a HILP.

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15. A Demand for Arbitration was issued by - on September 25, 2013 under section

19.4 of the PPA, which provides in part:

Subject to Section 19.3, all disputes with respect to this Arrangement shall, after the provisions of Section 19.2 have been followed, be forwarded to and resolved by binding arbitration in accordance with the Arbitration Act S.A. 1991, c.A-43.1 (the “Arbitration Act”), by a board of arbitrators in accordance with the following provisions…

16. Following some preliminary disputes and court applications that are not germane

to these proceedings, the parties agreed to a procedural order in this arbitration

(“Procedural Order No. 1”) that confirmed, inter alia:

a. This arbitration is subject to and will be conducted in accordance with

Article 19.4 of the PPA and the Arbitration Act (Alberta), (the “Act”) and

shall be conducted in Calgary, Alberta.

b. The place of arbitration is Calgary, Alberta.

c. To the extent Procedural Order No. 1 conflicts with the Act, the

Procedural Order shall apply except to the extent that the Act does not

allow contracting out of its provisions.

d. The timeline for arbitration proceedings contained in Article 19 of the

PPA is adjusted for the purpose of this arbitration and the dates and time

periods ultimately set forth in Schedule "A" to Procedural Order No. 1

will govern the arbitration, subject to the Panel's discretion to shorten or

lengthen timeframes for actions to be taken by any of the Parties and the

Parties' right to further modify those timeframes by agreement.

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e. The Arbitration Panel shall consist of J. Brian Casey, S, and B (the Panel).

Each of the Parties acknowledged that the Panel members had been

properly appointed. J. Brian Casey is the Chair of the Panel.

f. The Panel has jurisdiction to decide all of the matters submitted in this

arbitration, including, without limitation, the jurisdiction to determine any

question of law or equity arising in the Arbitration and determine any

question of fact.

g. The Panel has jurisdiction to confirm a HILP Event in the absence of

a - confirmation and the Panel's confirmation of a HILP Event has the

same effect and force as confirmation by the -.

II THE ISSUES and RELIEF CLAIMED

(a) Issues

17. Also, pursuant to Procedural Order No. 1, the Parties agreed that the following

issues (the “Issues”) were to be resolved by this arbitration:

a. Was the Event a HILP Event under the PPA?

b. Was the Event a Force Majeure event under the PPA?

c. If the Event was an event of Force Majeure, for what Settlement Periods

is - entitled to Force Majeure relief?

d. If there is determined to have been an event of Force Majeure and if, after

the Panel renders its award on Issues (a), (b) and (c), the Parties are unable

to reach agreement on the monetary consequences of the Panel's award,

the Panel shall determine upon request by one or more parties the

monetary consequences of its award.

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(b) Relief Claimed

18. - requests the following specific relief:

a. A determination that SAIPus5 = 0 from 4 p.m. on March 5 to 10 p.m. on

October 6, 2013 (the Settlement Period) for the purposes of calculating

Availability Incentives under Schedule D to the K PPA;

b. A declaration that the - is required to pay - the Capacity Payments during

the Settlement Period;

c. Costs.

III PROCEDURAL HISTORY

19. By email dated October 19, 2014, the parties were requested to work together to

finalize the arbitration procedure to be followed herein. All parties agreed that the

timeframe for arbitration set out in the dispute resolution provisions of the PPA

was unrealistically short and the timetable set out in Schedule A to Procedural

Order No. 1 would be followed.

20. In accordance with Schedule A to Procedural Order No. 1, - provided a Statement

of Claim, which included: (a) a statement of the facts supporting the claim; (b) the

points at issue; (c) the relief or remedy sought; (d) the legal grounds or arguments

supporting the claim.

21. - and the - then delivered Statements of Defence and - delivered a Reply thereto.

22. The following procedural orders were made during the course of these

proceedings:

5 Settlement Period Availability Incentive Payment

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a. Procedural Order No. 1, dated May 1, 2015, dealing with the terms of

reference to arbitration and the procedural schedule;

b. Procedural Order No. 2, dated August 31, 2015, dealing with a request for

production of additional records;

c. Procedural Order No. 3, dated December 14, 2015, dealing with a request

for production of additional records;

d. Procedural Order No. 4, dated March 3, 2016, dealing with a request for

the production of additional records and the removal of redactions;

23. In addition, email directions respecting the conduct of these proceedings were

issued December 19, 2014, February 22, 2015 and May 3, 2016.

24. The oral hearing took place in Calgary May 9-13; May 16-20 and May 24-27.

25. Witness statements (in the case of -6) and expert reports7 (in the case of all

parties) were filed by the parties from the following individuals and tendered as

their evidence. Each was also examined and cross-examined at the hearing.

-:

(i) Witness Statements

a. LOUIS A. FLORENCE JR. – Vice President, Alberta Coal Operations b. YONDONG LU – Lead Electrical Engineer c. JOHN RICHARD SHARP – Senior Generator Specialist d. MICHAEL STRUHAN – Manager Of Engineering, K Plant e. ROBERT EMMOTT – Vice President and Chief Engineer f. KELVIN KOAY – Director, Commercial Management, Alberta PPAs

6 The positions of the fact witnesses were those held at the time of the Event, unless otherwise noted. 7 While experts were not specifically qualified at the hearing, an indication of their qualifications and area(s) of expertise (where set out in their reports or in oral testimony) is provided as a matter of information.

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g. ANDREW JOHN BROWN – Principal Scientist and Generator Specialist, K Inc.

(ii) Expert Reports

h. HOWARD CHRISTOPHER MORRISON – Principal Consultant, HC Morrison & Associates (generator operations, maintenance and asset management)

i. DAVID WAYNE THOMPSON – Generator Lead, HDR Engineering (generator inspections, investigations and rewinds)

j. JOHN BRONKO MIHELCIC – Senior Electrical Engineer, Charles G. Turner & Associates Ltd. (generator outages)

k. HERBERT CONKLIN BISSELL – Herb Bissell, LLC (generator maintenance)

l. CHARLES CICCHETTI - President, Chicetti Associates, Inc./Pacific Economics Group, Inc. (economist specializing in electricity, natural gas and telecommunications regulation)

m. JOHN DUNCAN GLOVER – President and Principal Engineer, Failure Electrical (investigation of generator failures)

n. GUY FRANCIS GORNEY – Private Consultant (operations and management decision-making in the utility industry)

o. SHANE HOLST – Investigative Engineering Corporation (decision-making in the context of power plant operations and asset management)

p. RUSSELL WILLIAM PATTERSON – Patterson Power Engineers, LLC (protection systems)

q. CHARLES JOHN MOZINA - Private Consultant (relay protection)

-: Expert Reports

a. JONATHAN DAVID GARDELL – Principal Generation Consultant, TRC Engineers, LLC. (plant equipment and protection application of electric rotating machinery)

b. ROBERT FENTON – President, Generation Technology Consultants, Inc. (generator consultant)

c. BRADFORD JOHN SNYDER – Senior Consultant, TG Advisers, Inc. (condition assessment of generators)

d. UMBERTO MILANO – Bert Milano Electric Generating Corporation (generator diagnostic and high-potential testing, insulation test analysis and assessment)

e. LARRY CHARACH – Private Consultant (Alberta electricity policy and regulatory affairs)

-: Expert Reports

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a. RONALD ANDREW HALPERN – President, Generator Consulting Services, Inc. (inspection, evaluation, root cause analysis and recommendations for repair and rewind of generators)

b. JOHN KEITH NELSON – Professor Emeritus, RPI (electrical insulation systems and diagnostic technologies)

c. STEPHEN BRADLEY EISENHART – President, VATIC Associates (investigation of trip events, including ground fault relays and forced outages, FMEA techniques)

26. Sworn witness Statements (in the case of - and -) were also received from the

following individuals8 and tendered as their evidence without appearance or

cross-examination at the hearing:

-:

(a) STEVEN SANG-UK KIM – Commercial Manager, Alberta PPAs (b) RICHARD WAY – Vice President, Regulatory Affairs (1998-2004)

-:

(a) CHRIS JOY – Director of Commercial and Portfolio, Wholesale Energy (b) MARK PHILLIPS – Manager, Instrumentation and Controls (c) PAVEL GORELOV – Electrical Maintenance Engineer

27. Closing written submissions were received from each of the parties June 17, 2016.

Following written follow-up questions from the Panel, the Parties each filed a

written Reply Friday July 22, 2016.

IV Law (a) Interpretation

28. The parties are in agreement that the K PPA is a regulation, not a contract, and

that all of the normal rules of statutory interpretation apply.

8 See footnote 6, supra

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29. The - submits that there is no basis to depart from normal principles of statutory

interpretation in interpreting the language of the PPA. These principles were set

out by the Supreme Court of Canada in Canada Trustco:

It has been long established as a matter of statutory interpretation that "the words of an Act are to be read in their entire context and in their grammatical and ordinary sense harmoniously with the scheme of the Act, the object of the Act, and the intention of Parliament."9

30. We agree, however we must add to these principles of interpretation the

requirement to interpret words of the PPA taking into consideration any usages of

the power generation industry. Under the Act, Section 33 provides:

The arbitral Panel shall decide the matters in dispute in accordance with the arbitration agreement and the contract, if any, under which the matters arose and shall also take into consideration any applicable usages of trade.

31. We find that none of the provisions at issue in this arbitration are ambiguous or in

conflict with each other. We are able to interpret the words in their grammatical

and ordinary sense, within the context of the power generation industry.

(b) Prudence and Regulated Utility

32. At the outset of its argument, - alluded to the prudence standard applicable to

regulated utilities. This submission, as well as the evidence of Dr. Chicetti and

Mr. Charach, prompted the Panel to ask the parties for their views on whether - is

entitled to any presumption of prudence in respect of its actions during the Event.

Not surprisingly, - stands alone in its answer that if necessary in this case, a

traditional prudence analysis, including a presumption in its favour, should apply.

33. - says that the PPA does not establish a prudence standard, that - is not a

traditional regulated utility, and that the standard is in fact irrelevant to the issues

9 Canada Trustco Mortgage Co. v. Canada [2005] S.C.J. No. 56 at para. 10 (Authorities, - Argument, cited at Tab A paragraph 3)

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to be decided in this case. The -’s position is to the same effect as that of -; it

notes that since the recent decisions of the Supreme Court of Canada in OPG and

ATCO Gas10, any presumption of prudence in a regulated utility regime requires

specific statutory language to that effect, which is not found in the PPA.

34. In the context of this case, we agree with - and the - on this issue. The

determination to be made by this Panel focuses on whether a HILP event and

Force Majeure event have occurred. The normal burdens for asserting and

defending such claims are to be applied here. Applying an extraneous

presumption of prudence would trigger an additional onus of proof on the party

impugning managerial decisions, which would be inappropriate to the issues

involved and the decisions to be made.

35. Taking into account the history of the PPA and the objective of the Province to

put in place a transitional program leading towards full deregulation, we are

satisfied that the PPA, although a statutory instrument, should be regarded as

having many of the attributes of a commercial contract. To the same effect, we are

satisfied that in this case, - should not be regarded as a regulated utility to which

the prudence standard might otherwise apply in the appropriate circumstance,

when the context and issue for determination is a claim of Force Majeure under

that PPA.

36. The following provisions of the PPA are relevant to the Issues.

(c) Was the Event a HILP Event under the PPA? 37. The PPA defines a HILP Event as follows:

“High Impact, Low Probability Event” or “HILP Event” means a major failure of some or all of the components of the Plant (or a reasonable prediction by the Owner that a major failure of some or all of the components of the Plant will occur before the next scheduled Planned Outage) and which results (or could be reasonably expected to result) in

10 Ontario v. Ontario Power Generation [2015] 3 S.C.R. 147; ATCO Gas and Pipelines v. Alberta [2015] 3 S.C.R. 219

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the Plant being unable to operate or being forced to operate at a lower level (or is reasonably predicted by the Owner to be unable to operate or forced to operate at a lower level) and (a) it is reasonably predicted by the Owner that the Plant will be unable to operate or forced to operate at a lower level for a period in excess of six (6) weeks; and (b) the - has confirmed that the above conditions have been met;

38. In this case, there is a series of occurrences or events that collectively form the

Event as defined by the parties. The key issue in the definition of a HILP is

whether at each or any decision point during the outage, there was “a major

failure of some or all of the components of the Plant”, or “… a reasonable

prediction by the Owner that a major failure of some …of the components of the

Plant will occur before the next scheduled Planned Outage and which … could be

reasonably expected to result in the Plant being unable to operate or be forced to

operate at a lower level … and it is reasonably predicted by the Owner that the

Plant will be unable to operate or be forced to operate at a lower level for a period

in excess of six (6) weeks.”11

39. - puts the second part of the definition this way in its post-hearing Reply

submission: “based on the information that - knew, or reasonably ought to have

known, at the time, was it reasonable for - to predict that a major failure would

occur prior to the next Planned Outage (May 2014).”

(d) Was the Event a Force Majeure event under the PPA?

40. The PPA defines Force Majeure as:

“Force Majeure” means any event or cause which is beyond the reasonable control of the affected Party, or its Affiliates, including a HILP Event, a mechanical breakdown but only insofar as such breakdown results from a HILP Event, an act of God, flood, earthquake, storm, lightning, fire, epidemic, war, blockade, explosion, riot, act of the Queen’s enemies, act of civil or military authority, civil disturbance or disobedience, strike, lockout or other labour dispute or industrial disturbance, accident, sabotage, lack or inadequacy of fuel supply from a

11 “Plant” is defined in the PPA as comprising K units 1 & 2. If K 1 was off line, the Plant would technically be operating at a lower level, presuming K 2 was still operational.

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fuel supplier, any suspension of delivery of Electricity pursuant to Section 5.4, restraint by court order or any Laws, or the action or inaction of any Governmental Authority, or inability to obtain or renew any Governmental Approval, provided that lack of funds or economic hardship shall not constitute a cause beyond the reasonable control of the affected Party;

41. Thus, any event beyond the reasonable control of an affected party can be a

matter of Force Majeure, including a HILP, but if the Force Majeure is from a

mechanical breakdown, it must be a HILP. Thus, one of the questions is whether

there was a mechanical breakdown.

42. And if a HILP event is to qualify as Force Majeure, the HILP event must also be

beyond the reasonable control of -. This must also be analyzed at each decision

point at each stage of the outage.

(e) Good Operating Practice

43. In determining what is “reasonable” it is necessary to first focus on what is

referred to in the PPA as Good Operating Practice (“GOP”).

44. The parties spent considerable time on whether or not the activities carried out

by - were or were not within the definition of GOP. The PPA tells us that “Good

Operating Practice” means:

Any of the range of practices, methods and acts engaged in or approved by a significant proportion of the industry in North America involved in the supply of electricity from and the operation of generating units similar to the Units, from time to time, or any other practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known or reasonably ascertainable, could have been expected to accomplish the desired result at a reasonable cost consistent with applicable Laws, reliability, safety and expedition.

45. While a number of activities of - can be weighed against the first part of the GOP

definition, the evidence is that one of the tests relied on by -, the TVA test, while

recognized by the Institute of Electrical and Electronics Engineers (“IEEE”), is

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not commonly used in North America and so there is little or no evidence

regarding its use amongst others in the industry in North America. While some of

the experts who testified felt that the absence of common use meant the TVA test

fell outside of GOP, the second part of the definition of GOP states that GOP can

encompass: “… any other practices, methods and acts which, in the exercise of

reasonable judgment in light of the facts known or reasonably ascertainable, could

have been expected to accomplish the desired result (in this case, the return of the

Unit to service) at a reasonable cost consistent with applicable Laws, reliability,

safety and expedition.” This allows for a wider range of practices to fall within

the definition of GOP. It also requires that actions be analyzed in context and in

light of the facts known at the time.

(f) If the Event was an event of Force Majeure, for what Settlement Periods is

TAGP entitled to Force Majeure relief?

46. Article 14.1 of the PPA provides:

If either Party is unable, wholly or in part, to perform or comply with any obligation hereunder, and if such inability shall have been occasioned by or as a consequence of any event of Force Majeure, the obligations of such Party, insofar only as its obligations are affected by the event of Force Majeure, shall be suspended for so long as the event of Force Majeure continues to prevent the performance of or compliance with such obligation and for such time thereafter as such Party may reasonably require to fulfill such obligation.

47. A Party that claims Force Majeure is obligated to make all reasonable efforts to

mitigate its effects. Article 14.2 provides in part:

If either Party relies on the occurrence of an event of Force Majeure as a basis for claiming suspension of an obligation under this Arrangement, such Party shall: …(b) exercise all reasonable efforts to continue to perform or comply with its obligations hereunder; (c) exercise all reasonable efforts to mitigate or limit the effect of the event of Force Majeure…

48. If there was an event of Force Majeure, were all reasonable efforts made to

mitigate or limit its effect?

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(g) Adverse Inferences

49. Respondents state that there are two key witnesses that - failed to call, namely a H

witness, (such as Mr. Lunney), and Mr. Klempner. - also did not produce any

witness from M. Further, - states the Panel did not hear from several - employees

who were intimately involved in the Outage and who - says were responsible for

many of the key decisions that were made, including Jerome Campbell, the Plant

Manager at K during the Outage, and Hugo Shaw, who made the decision to issue

the notice of Force Majeure. Respondents submit the Panel should make

appropriate adverse inferences in these circumstances.

50. Respondents cite a portion of paragraph 9 in the case of Spartan Developments

Ltd. v. Capital City Savings and Credit Union Limited12, as the test for finding an

adverse inference. The entirety of paragraph 9 states:

An adverse inference may be drawn if a party without explanation fails to call a witness who would have had knowledge of the facts, particularly important information uniquely available to him or her, and that witness would be assumed to be willing to assist that party. Such a negative inference can be drawn when that witness is not called. However, a Court is not required to draw an adverse inference. Here, the trial judge did not draw an adverse inference on the basis that there was no property in a witness and either party could have called the two former employees. We find no reviewable error in his failure to draw the requested inference in the circumstances.

51. With respect to the outside advisors, including H, the question is what did they do

and what did they recommend? The panel was provided with their reports, which

speak for themselves and upon which - acted. It is unclear what additional

important information they could have provided. Further, they are independent

of - and any or all could have been called by the Respondents if there was some

particular reason they believed their testimony was necessary.

12 2004 ABCA 12

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52. With respect to the current employees of - who were not called, the Panel does not

agree that the record discloses they were solely responsible for making any

decision. The basis for the adverse inference test is that there is an outstanding

issue upon which the absent witness could have provided important, or the best

evidence. A number of - personnel were involved in the decision making process,

many of whom testified. There appears to be little another employee could add to

the testimony already provided.

53. The Alberta Court of Appeal, in Panarctic Oils Ltd. V. Menasco Manufacturing

Company13, made it clear that not all witnesses to the same event need to be called

to avoid an adverse inference, and we decline to do so in this case.

V AWARD STRUCTURE 54. In this Award we have highlighted, generally in chronological order, each of the

sub-issues and related facts that go to determining whether or not Force Majeure

existed. When necessary, findings of fact are set out and a determination made

regarding whether a step was reasonable and within GOP. At the end of this

chronology we then summarize the findings and discuss them in relation to the

definitions of Force Majeure and HILP.

55. The Panel has reviewed all Witness Statements and Expert Reports together with

reference to the transcript when necessary to clarify or confirm what was said

during the hearing. In the following sections, reference is made to certain

testimony that the Panel considered of significance. It should not be taken that

omission of other testimony means it was not considered.

VI DISCUSSION OF MATTERS IN ISSUE (a) The Trip and the Initial Investigation

13 [1983] A.J. No. 889 (CA)

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56. The Trip occurred March 5, 2013. On March 6, M IV Engineering, an outside

consultant, (“M”) was on site to test the ground fault relay and related equipment.

The test results showed normal operation.

57. On March 10 M was again retained to test the relay and related equipment. In its

report of March 17, 2016 M summarized the scope of its work as :

• Proof testing of B64/G1 neutral overvoltage relay • Characteristic testing of the A64/G1 relay • Continuity testing of wiring between the A64/G1 relay and the Neutral

Grounding Transformer (NGT) and generator terminal side wiring • Proof testing of the A64T/G1 timer relay • Continuity testing of wiring between the A64T/G1 relay and the A64/G1

stator ground fault relay • Excitation testing of twenty four (24) generator current transformers (CT's) • Transformer ratio, winding resistance, and insulation resistance of all six (6)

generator terminal potential transformers (PT's) • Transformer ratio, winding resistance, and insulation resistance of the NGT. • Resistance measurement of the NGT resistor • Enabling and testing 27TN third harmonic neutral undervoltage on the unit's

Main Generator Protection relay MGP-114

58. M and Mr. L from - reported that, the relay that initiated the Trip (the “DGSH

relay”) and related safety equipment appeared to be functioning properly.

59. Mr. Eisenhart testified that from his review of the documents he did not

believe - had taken appropriate steps to quarantine the site and immediately

interview all personnel on shift at the relevant time in order to capture and

preserve the evidence surrounding the Trip. While all of the protocols advocated

by Mr. Eisenhart may not have been followed, the reality is there is no evidence

to support speculation that a so-called “screwdriver” fault, or other external act

caused the Trip. There was no evidence of any scheduled or unscheduled

maintenance taking place in the relay room or evidence of any activity that might

have exposed relevant equipment or wiring to shorting, grounding or other

14 Doc 000006.446102.0002/5

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interference. No other type of activity was presented as being a plausible or

probable cause of the Trip.

60. Based on the available evidence, we find it is speculation to suggest that

following such additional protocols suggested by Mr. Eisenhart would have

resulted in any different findings as to the cause for the Trip.

61. In his email of April 24, 2013 to Geoff Klempner, the third party expert hired

by - on or about April 20, 2013, Mr. Sharp described the testing by M as

including relay functional testing, testing of the ISO Phase Bus, potential and

current transformers, neutral grounding equipment and all associated cabling. Mr.

Kempner’s response was that the stator had neutral ground protection and the

protection on the stator was working.

62. Mr. Gardell states in his expert report that testing of the DGSH relay during the

previous 2009 and 2012 maintenance outages did not meet the level of GOP. Mr.

Fenton also opined on this with the same suggestion. In Mr. Gardell’s

opinion, - ought to have performed characteristic testing of the DGSH relay as

part of the 2012 Uprate. He opined that:

The testing completed in both 2009 and the 2012 was limited to a proof of operation tests using a 60 Hertz voltage instead of the third harmonic voltage (180 Hertz) that the ABB A64/G1 Relay is designed to operate on….My opinion is that the ABB A64/G1 Relay should have been subjected to more comprehensive operating characteristic testing, setting and calibration checks during the outage and the return to service when the unit was uprated in 2012. 15

63. Mr. Patterson says in his report that while the third harmonic voltage would have

been a more appropriate choice to use for trip testing, using 60Hz is acceptable

for this purpose since the DGSH relay will operate on 60Hz. He points out that

the instruction manual for the device clearly states that the relay will operate on

15 Expert Report of Jonathan Gardell

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60Hz. As such, he says using either 60Hz voltage or 180Hz for trip checking

would be acceptable.

64. According to Mr. Patterson, AMEC Engineering evaluated the impact of the 2012

Uprate on the generator protection and produced a report that specifically

excluded the DGSH relay from concern. In Table 6-3 of the AMEC report it

states: “Generator Protection, No Change Due to Increased Capacity”. Mr.

Patterson concludes that it was reasonable for - to rely on this report from a 3rd

party expert who raised no flags regarding the adequacy of the existing DGSH

relay settings.

65. In Mr. Mozina’s opinion, based on his experience with commissioning 3rd

harmonic schemes, the installation of a new rotor and small increase in MW

output (7%) would not significantly affect the generator 3rd harmonic neutral and

terminal balance. He acknowledged that the proof tests done by M in 2009 and

2012 were at 60 Hertz instead of 180 Hertz. However, he stated that the testing

done by M immediately after the March 5, 2013 Trip was done correctly at 180

Hertz. He stated that the settings on the relay prior to the Trip were the same

settings that were retained after the rewind and extensive field commission

testing. Immediately after the Trip, the DGSH relay was investigated and, when

Bill Lu analyzed the results, they showed that the DGSH relay was in proper

calibration prior to the Trip. In Mr. Mozina’s opinion, the settings for the DGSH

relay were proper prior to the Trip.

Factual Findings

66. The Panel finds:

a. There is no evidence that the DGSH relay was not calibrated properly at

the time of the Uprate;

20

b. Testing at 60Hz rather than 180 Hz appears to be immaterial;

c. The testing by M was sufficiently thorough to eliminate any external cause

for the Trip.

67. On the evidence presented, the Panel finds that the DGSH relay and related wiring

was functioning properly at the time of the Trip.

(b) The Theory for the Trip

68. The DGSH relay protects 100% of the generator by comparing the third harmonic

voltages at the line and neutral ends. Mr. Lu’s theory concerning the possible

cause of the Trip was reported in his email to Mr. Sharp on April 17, 2013. He

makes two observations, including that according to his calculations, if a

capacitance change happens at either end of the generator it would affect the third

harmonic voltage ratio significantly. He asked the question whether there is a

relationship between the TVA test results and the capacitance change since,

according to the test results, it would appear that a higher TVA correlates to a

higher capacitance.

69. There is no question that in theory a higher capacitance results in a lower voltage.

This was explained in the testimony of Mr. Patterson.

70. The paper published by CIGRE16 in September 2007 makes the point that 100%

stator winding protection systems using third harmonic voltages are capable of

detecting not only any (low) resistance earth-faults anywhere along the stator

winding of the protected generator, but are also sufficiently sensitive to indicate

the deterioration of insulation in the winding sections situated close to the neutral

point of the stator winding. The authors of the paper state that while not

16 International Council on Large Electric Systems (in French: Conseil International des Grands Réseaux Électriques, abbreviated CIGRÉ). - Cross-examination documents Tab 5

21

immediately critical, these must be detected in order to prevent double earth-

faults.

71. Mr. Milano in his report stated such relays could not detect these changes in

capacitance, but when confronted with the CIGRE paper, he responded that the

researchers were probably using an electronic relay, not a mechanical one. He did

not dispute the underlying stator earth fault protection principles, or the operating

mathematical equations used to describe the third harmonic protection. He did not

explain why the math should not work regardless of the equipment used. His

calculations regarding whether there could be enough change in the capacitance

of Bar T5 to trigger the DGSH relay were, in his own words, “back of the

envelope” and only took into consideration the small area found in Bar T5 in the

first TVA test. He acknowledged no calculations were done, or could be done on

the distributed capacitance.

72. In his report, Mr. Milano also said that delamination does not cause a change in

capacitance, but on cross-examination he changed his view and said that it does.17

73. It is also noted that Mr. Milano was put forward as an insulation expert, not a

relay expert.

74. Mr. Gardell testified that rigorous calculation of potential capacitance changes is

a difficult task, and there is no way of knowing what actually occurred when the

Unit was operating and Bar T5 was subject to mechanical and thermal forces. In

his opinion, a change in capacitance did not cause the Trip, as the capacitance

change would not be sufficient. He was also of the opinion that the DGSH relay

was “neither designed to be, and nor does it function as a condition monitor or

detector for stator winding degradation such as delamination.”18 In cross

17 Transcript p 2380 18 Gardell report p. 49

22

examination however he testified he was not familiar with the CIGRE Paper, nor

its conclusions.

75. Mr. Mihelcic's report states that a capacitance change caused by delamination is

possible and that an issue in the stator windings did cause the Trip. Mr. Mihelcic

also testified he agreed with Mr. Lu’s analysis that the changed capacitance

tripped the DGSH relay.

76. This is a very technical and mathematically complex area. It is also something

that few practicing engineers would ever experience. The Panel prefers the

rigorous analysis of the CIGRE Paper, which is said to be a peer reviewed paper

and which was authored by individuals who were part of the ABB research

department, the company that now manufactures the DGSH relay.

Factual finding

77. The Panel finds that on the balance of probabilities, the Trip was triggered by a

change in the third harmonic voltage ratio, caused by an issue with the generator

stator winding.

(c) The Decision Points at issue i) The decision to dry out the stator 78. Respondents say the initial wet megger results done after the Trip were not

ambiguous with respect to a ground fault. They say that the testing showed there

simply was no ground fault and the Unit should have been returned to service.

79. The evidence discloses that as of March 8, while there was no continuous short to

ground, a ground fault could not be ruled out. At this early stage - had the initial

report from M indicating the protective circuitry was operating properly. The

results of the wet megger conducted by - on the Unit showed a PI of 1.0. (A low

23

PI (below 2.0) indicates that the insulation resistance is low and the insulation

may be contaminated or wet.) Mr. Fenton testified that while drying out the Unit

was a conservative option compared to other options the industry might follow, in

his opinion it “fit into the range of actions power generator companies could

reasonably choose.”19 This was also agreed by Mr. Snyder. 20

80. Mr. Morrison testified that unless there is a solid earth fault, a wet megger test

will tell you very little and in his experience, wet megger tests are rarely done.

Determination

81. The decision to dry out the stator fell within GOP and was reasonable.

ii) The decision to remove the rotor

82. Between March 8 and March 10, the stator was degassed, drained and dried in

order to allow a dry megger and other tests to be conducted.

83. The rotor-in inspection and testing was conducted by H between March 13 and

March 15. As reported by H, the Unit passed each of the “rotor-in” stator tests.

Respondents point out that none of the tests revealed any abnormalities or

concerns. Notwithstanding this, on March 13, 2013 H confirmed its advice to

remove the rotor, stating:

Normally, in the event that a ground fault is detected and cannot be positively traced to a root cause external to the generator, then H recommends that the generator be disassembled and the rotor removed for a detailed visual inspection.21

H also opined that IR and PI readings are not conclusive if the fault occurs in the

end-winding region of the generator. 19 Transcript page 2007 20 Transcript page 2189 21 Doc 000006.432023.0006

24

84. In its report, H also recommended preparing a full rewind kit.

85. Respondents say that original equipment manufacturers (“OEMs”) are notoriously

conservative, and generally present worst-case scenarios, at least in part because

they are not prepared to assume any risk of liability with respect to the advice

they give. From the evidence, however, there are a number of examples in

which - did not accept H’s recommendations. It does not appear to the Panel

that - blindly followed all of H’s recommendations.

86. With respect to the decision to remove the rotor, the Minutes of a March 12

meeting involving - and H indicate that a recommendation to remove the rotor

was made by both H and John Sharp.22 The H Report of March 13 indicated that

when a ground fault is detected (i.e. a trip occurs) but cannot be positively traced

to a root cause external to the generator, H recommends the generator be

disassembled and the rotor removed for a detailed visual inspection. Not only

was this necessary to continue to investigate the Trip, but H indicated that its

standard high voltage testing was usually done with the rotor removed.

Respondents state that once it was clear there was no ground fault, the possibility

of a false trip became a real possibility that warranted careful investigation of the

protective relay system, but - did not pursue it. It appears, however, that in

fact - did request further investigation from M. M provided a second report

March 17, confirming that the protective equipment and related wiring was in

working order.23

87. Mr. Fenton testified that in his opinion, while conservative, the removal of the

rotor fit into the range of options power-generating companies could reasonably

take. Mr. Milano initially testified that there was no need to pull the rotor. Instead,

he testified a DC ramp test should have been done and if the Unit passed return it

22 Doc 000010.1769913.0005 23 Doc 000006.446102.0002

25

to service. On cross-examination, however, he agreed that in his report he

acknowledged it would also fall within GOP to remove the rotor.24

Determination

88. The decision to pull the rotor was reasonable and fell within GOP.

iii Delay resulting from the failure to have full Beckwith monitoring

89. Respondents allege the search for the cause of the Trip was significantly

hampered by -’s failure to enable key functionality of the Beckwith digital

protection system that was installed in 2009, and this was not GOP.

90. According to the evidence of Mr. Patterson, a number of Operators still have no

monitoring of the neutral end at all, and the evidence of Mr. Mozina was that it is

not industry-standard to have 100% redundancy or dual protection at the neutral

end.25

91. While Mr. Patterson stated that complete redundancy would be best practice, in

his opinion, the stator ground fault protection system in place at K 1 complied

with GOP.26While it may have been helpful to have this additional information, a

failure to have duplicate safety systems for the neutral end was not a failure to

follow GOP.

92. It is also unclear what the Beckwith data would have shown. Mr. Gardell testified

that the Beckwith also compared the third harmonic voltages. Presumably it

would have been set to the same sensitivity as the DGSH relay, otherwise conflict

would result between the systems. What it would have shown is speculation. The

Panel has no evidence before it one way or the other that had the Beckwith been

24 Transcript page 2309 25 Cross examination of Mr. Mozina 26 Transcript p 688

26

operational it would have provided information that would have resulted in

changing the decision to focus on the Unit and to remove the rotor.

Factual finding

93. There is insufficient evidence to suggest that had the Beckwith system been

engaged, it would have reduced the length of the investigation or the outage.

Determination

94. The failure to have the Beckwith monitoring system engaged did not fall outside

GOP.

iv) The Decision to include TVA testing 95. K was retained on March 13, 2013. By this time the decision had been made to

remove the rotor.

96. An Investigation Test Plan dated March 18, 2013, was prepared by John Sharp

and M. Vikse of -. The plan states it was to “identify the exact nature and extent

of potential stator winding damage”. If a visual inspection found no clear

indication of the fault, then the electrical testing program set out in the plan was to

be carried out and, when possible, compared to the 2012 test results obtained in

connection with the Uprate.27

97. This plan reflected the initial recommendation from H in its Report of March 13,

which stated that if the visual inspection did not indicate the cause of the Trip

then an off-line dissipation factor and partial discharge test should be performed

and if acceptable the Unit could be put back in service. At -’s discretion and risk,

high voltage testing could also be done.

27 Doc 000006.425668.0002

27

98. On March 19th at a meeting between -, H, and K, this plan was revised. At this

meeting, Mr. Brown of K recommended that the plan add the TVA probe testing,

on the basis that it would add to the data available and “improve the resolution” of

the insulation diagnostic testing.

99. Respondents allege that rather than follow H’s advice, - introduced the TVA test,

which is not used to determine if a unit is fit to return to service after a trip. The

Respondents’ experts have opined that the TVA test was inappropriate and

when - accepted this recommendation by K, it was deviating from the IEEE

standard for stator winding return-to-service testing, and was also deviating from

GOP.

100. While it appears from the evidence that the TVA test is not used very much in

North America, the evidence disclosed that it is an accepted test to determine the

extent to which partial discharge and thus delamination is occurring in individual

bars. Mr. Milano in his Report of January 29, 2016 stated he has been using the

TVA corona probe since the mid-1970’s and has a significant amount of

experience in testing new and aged windings. Also, as a trending tool the TVA

test had been regularly used by -.

101. H had not included the TVA test in its usual suite of tests respecting ground faults

in its March 13 report, but in its report of March 22, 201328 it included the TVA

test results from K with the comment: “To investigate local partial discharge

activity, TVA corona probe test was conducted. H does not have experience in

using this test method to check for stator winding condition, but it is a known test

method by IEEE.”

102. The TVA test is addressed in the IEEE 1434 Standard (Guide for the

Measurement of Partial Discharges in Rotating Machinery) at section 6.3.1.

28 Doc 000006.427283.0002

28

103. Mr. Brown testified:

They had already confirmed to me that they were removing the electrical rotor, the spinning part, to give access to the stator core in order to do a thorough inspection of the winding and do an EL-CID test. So it made sense, at that point, to me that if the rotor was coming out, that they take the time and repeat the diagnostic tests. And we're talking about the insulation resistance, the partial discharge test, that capacitance dissipation factor, and the TVA probe testing. We had historical results that made sense, just to make sure that nothing had changed in that ten-month period.

Q Okay. So that's why you were doing that testing, was to see if anything had changed? A We were looking to see if anything had changed on the insulation system that could explain why they had a ground fault indication and confirm that they were in a good condition to come back into service at that point as well.29

104. The allegation that the TVA probe test is not a standard diagnostic test used to

determine whether a winding is fit for return to service confuses the

appropriateness of the TVA test to determine emergency fitness for service with

the use of the test to obtain data about individual stator bars when trying to

identify the cause of the Trip.

105. All but one of Respondent’s experts who opined on this issue essentially said that

because - was looking for a ground fault, only usual ground fault tests should be

done.

106. As the revised Investigation Test Plan states, - was at that point still at the

investigation stage, with the rotor having just been removed. As of that time, mid

March, 2013, there was no indication of a false trip, thus pointing to some issue in

the generator near the neutral end. The plan stated that if a visual inspection did

not find the cause, then electrical testing should be done. As Mr. Morrison said,

why exclude the TVA test? There was no reason why, at this stage of the

investigation, - should have ignored the advice of K to include a TVA test. The

TVA test had always been a part of the maintenance testing on the Unit, and data 29 Transcript p. 775

29

from such testing was available from 2009 and 2012. Mr. Thompson testified it

would be unusual to do less testing than was normally done. Also, as explained by

Mr. Brown, the TVA test takes you from data about the whole stator down to

information about particular bars. If, with the rotor removed, a visual inspection

did not point to the cause of the Trip, then the suite of electrical tests, including

the TVA test, was reasonable.

107. To say the TVA test is not part of the tests used to determine fitness for service

may be correct, but it was not inappropriate to use the test as part of an

investigation to try to determine the cause of the Trip.

108. Mr. Milano, who is an insulation expert and familiar with TVA testing,

,acknowledged in cross-examination he had previously written that the TVA test

is the most informative test respecting PD activity and the condition of insulation

and it should be done before any hipot testing. Further he acknowledged that if

the TVA test results are poor it may be prudent to postpone or eliminate other

more stressful testing.

Determination

109. There was no good reason to exclude the TVA testing. Saying it is not part of the

usual suite of tests used to determine a return to service is too narrow a view of

what was occurring.

110. The Respondents’ complaint that the TVA test is not a test to determine fitness for

service deflects attention from the main question here: was the inclusion of TVA

testing at this point GOP? Irrespective of the first element of GOP, the tribunal

finds that in this context it was reasonable and met the second element of the

definition of GOP.

v) The decision to replace Bar T5

30

111. In a report dated March 20, 201330, H sets out the data from its partial discharge

test, and in the section headed Conclusion it stated:

… Subsequent tests while the TVA probe test was being performed indicated that copper to ground wall insulation delamination was occurring on phase A. This problem is believed to be caused by top bar number five that showed unacceptable PD levels during the TVA probe test. Both the TVA probe test and the partial discharge test indicated that the problem was getting worse over the course of the test. It is recommended that top bar number five be replaced before returning the generator to service

112. In its March 22 Report,31 H stated:

Although there is no concrete indication that can lead the unit to trip is not found, high PD activity of top bar in slot #5 is indicating abnormal condition. This top bar in slot #5 locates at second bar from the neutral end. This explains why the unit did not trip by 95% coverage of ground fault, but tripped by 100% coverage of ground fault.

DC ramp test and AC hi-pot test can be conducted to proof the stator winding can be put into service again. However, the electrical stress to the insulation by these tests can accelerate the deteriorated condition. Even though it passes the test, it can fail shortly afterwards.

113. The March 22 report’s Conclusion stated:

Based on our investigation result, top bar in slot #5 has strong possibility of being in unreliable condition. Replacing this stator bar immediately at this [time] is recommended…

114. Under the heading “Recommended Repair” the March 22 report stated:

For reliable operation and to minimize further trip event by stator ground fault relay, we recommend following repair.

(1) Replace top bar at slot #5 with spare…

30 Doc 000006.469192.003-10 31 Doc 000006.427283.0002

31

(2) The process of removing bars contains significant risk…If the bars

are damaged in the end winding portion, on site repairs can be performed. ..If the bar is damaged in the slot portion, it either need to be discarded or shipped back…for re-insulating

(3) The stator winding has reached to the end of life-time and

deterioration of insulation can accelerate, which can cause a further trip event in the near future. From this point of view, H recommends preparing a full rewind kit…32

115. H indicated in a revised March 22 report, issued March 27, that it considered

these repairs to be temporary and “a full rewind is required”.33 It left in place its

recommendation to prepare a full rewind kit and “plan for” a stator rewind.

116. Respondents point out that the March 22 report as revised by H on March 27, 2013

had critical word changes. It was also issued after the Notice of Force Majeure

was sent on March 25. The revised report itself describes these changes as “minor

wording revision”.34 The changes in addition to those referred to in paragraph 115

were:

a. Under the heading TVA Corona Probe Test there are two added sentences:

i. “Nevertheless K is familiar and performed this test historically for K generators.”

ii. It should also be noted that the TVA corona probe test performed by K in 2012 outage did not show as high PD activity from this slot

b. Under the heading Concerns for Operation

i. The words “Although there is no concrete indication….” are changed to “although no visible indication of damage…”

ii. The sentence “DC ramp test and AC hi-pot test can be conducted…However the electrical stress to the insulation by these tests can accelerate the deteriorated condition” is changed to “After the stator windings have been properly repaired DC ramp test and AC hi-pot test can be conducted…The electrical stress to the insulation can accelerate the deteriorated condition, hence it should be done after the repair…”

32 Doc 000006.427283.0002 33 Doc 000006.427279.0002. The question of the timing of the stator rewind is dealt with below. 34 Doc 000006.427279.0002

32

117. This revised report is dated after - had made its decision on March 22 to replace

Bar T5. There is no evidence to suggest anything in the revised report would have

or should have caused - to change its decision to replace Bar T5 or issue the

Notice of Force Majeure.

118. Jerome Campbell of -, in an email dated March 22, 2013, reported to Mr. Florence,

Mr. Sharp and others that the H recommendations had been reviewed by Tech

Services and Engineering, and they recommended replacing Bar T5. There is no

indication that any written report from K had as yet been received, although

discussions had taken place. While not referred to in the documentation, Mr.

Brown had also recommended that Bar T5 be replaced prior to returning the

generator to service. He stated: “If we did not replace Bar T5, there was a good

chance the Unit would trip again given the condition of Bar T5 and the efforts to

bring the Unit back online (and all the testing and investigative effort done so far)

would have been wasted.”35

119. In its report of March 26, 2013, K stated:

The PD levels are low and indicate that the winding is in good condition with no change to the overall condition compared to that of 2012. However, an additional investigative test on the A phase with the PD detector coupled at the Neutral end, showed a doubling of the PD levels compared to the Line end. In conjunction with an increase in PD magnitude with the winding energized for a period of time at 11 kV, this observation appears to validate the TVA probe findings on this phase. It is understood that the 100% Ground fault relay trip operation is based on a current balance between the Line end and Neutral end and the detection of third harmonics. It is possible, although unproven and as such only a theory that a 3rd harmonic imbalance may have occurred as a result of this thermal delamination, causing a spurious ground fault trip. If this is the case then this spurious trip could have been advanced notice of an impending problem at the neutral end, providing protection against potential major core damage had this materialized. At this point this is

35 Brown Witness Statement October 15, 2015 para. 98

33

only theoretical and at this stage the presence of some other factor causing the ground fault should not be ruled out. Nor should it be ruled out that this is an isolated incident. 7.0 RECOMMENDATION Based upon the results obtained and reported above, NO true evidence of a stator ground fault has been established. There are several factors that could point to an instrumentation or spurious noise issue. Namely un-explained Dew point indication, thermocouple reaction in tooth between slots 5-6 and also lack of any credible signs of a ground fault. However, the tests have revealed one anomaly that does pose a potential risk to the continued operation of the stator, that of slot 5 top bar (5T) which is a neutral end bar and shows potential signs of unstable delamination. It is recommended that this bar is replaced prior to RTS.36

It can be reasonably inferred that much the same thing was said by Mr. Brown

orally to - personnel prior to the - decision to replace Bar T5.

120. Having received the test results and the recommendations from H and K, - had to

decide if the Unit could be returned to service without repair and operate until the

next Planned Outage.

121. Finding a fault and repairing it with the replacement of one or two bars is not

unusual. Here, however, there was no identified ground fault and the macro level

tests were acceptable although with some upward trends, but there were also very

high PD test readings on Bar T5. The evidence discloses that extremely high PD

readings, up to 600ma, were found at Core Packets 1 through 20, indicating a

problem with the insulation, and upon removal of the wedges, the PD activity

increased on Bar T5 down to core packet 28. Also, only Bar T5 exhibited this

condition. All other bars had acceptable readings. Bar T5 was an outlier.

122. Mr. Fenton testified that once the protective DGSH relay was confirmed to be

functioning as intended and it confirmed that there was no permanent ground, the

standard procedure consistent with GOP would have been to perform an over-

36 Doc 000006.455347.0002

34

voltage test at 150% of rated voltage. He stated that industry data supports the

“rule of thumb” that any winding passing a 150% over-voltage test has a very

high probability of operating successfully without a failure for the next 3 to 5

years. He testified that the TVA test is rarely, if ever, performed on turbo-

generators in North America and is therefore not in the realm of GOP. He

concluded that the decision to take action to do a partial rewind based solely on

the TVA test and without corroborating evidence from other tests was not Fenton

consistent with GOP.

123. Mr. in his report and testimony also stated that following completion of the first

round of diagnostic testing, which included the TVA test results, it was clear that

there was no ground fault and, consistent with GOP, - had one of two choices: (1)

perform a hipot test on the stator to determine suitability for service, or (2) return

to service without a hipot test. In either case, re-assembly of the stator should

have commenced on day 18 following the Trip and the unit should have returned

to service by day 25 or sooner.

124. Mr. Halpern stated that after all the tests and inspections were done and passed

with the rotor removed, - knew the condition of the stator was suitable for safe

return to service and - should have done so. While - may not have determined the

cause of the trip, he saw this as no reason not to return to service. In his opinion,

sometimes a cause cannot be determined and it is labeled a 'false trip’, but this

does not mean the unit is not suitable for service. Mr. Halpern was of the view

that as the Unit passed all “prescribed” tests it could have been returned to service

with redundant protection such as enabling the Beckwith system and monitoring

of all operational parameters such as temperatures, pressures, dew point, flow, etc.

125. Both Mr. Halpern and Mr. Felton essentially ignore the fact that the TVA test data

were corroborated by the test results which showed that the PD test on phase A

was twice as high as at the line end. They did not deal with the fact that - had data

about Bar T5 and had to deal with it. What had started out as a search for a reason

35

for a simple ground fault trip had turned into a situation in which the OEM was

reporting the stator insulation was at the end of its life and one bar in particular, in

the area that had likely caused the Trip, was showing very high PD readings. If

the Unit was simply returned to service, everything pointed to another trip

occurring.

126. Mr. Milano acknowledged having previously written that if extremely high

readings are observed in a TVA test, one solution is to replace the troublesome

bars. 37 He stated, however, that the decision to do so in this case was based on

what he considered to be faulty test results. In particular:

a. The readings of 600 and 400 were too high and Mr. Brown should have

recognized they could not be correct.

127. In cross-examination it was put to Mr. Milano that he had previously written

about questionable coils with readings of 50 to 500 in one case,38 and in another

about a machine with readings between 500 and 700.39 In both cases he had no

clear explanation of this discrepancy in his testimony.

b. The high readings were the result of core surface discharges and Mr. Brown

misread the results.

128. Mr. Milano says the continued presence of end winding contamination, or

contamination just inside the core boundary can add to or amplify the discharge

intensity. These discharges occurring at or near the end of the core can result in

high corona probe readings. Mr. Milano states in his first report that the continued

presence of end winding contamination, or contamination just inside the core

boundary can add to or amplify the discharge intensity.40 These discharges,

37 Transcript pp2313-4 38 Transcript page 2384 39 Transcript page 2315 40 This residual contamination came as a result of the operation of the Unit for some two years without operational hydrogen dryers. This is discussed further below.

36

occurring at or near the end of the core can result in high corona probe readings,

which Mr. Brown misread.

129. Dr. Nelson in his report stated that while there was some contamination in the

interstitial regions of the end winding which possibly remained from the cleaning

operation undertaken in 2012, these regions were not accompanied by any

indications of external discharging. In his reply witness statement.

130. Mr. Brown stated he did consider this issue and conducted tests specifically to

investigate it. He stated it is well known that the TVA test will locate where

partial discharge is on a winding but it will not tell you whether the partial

discharge is on the surface or internal. Following his investigation he says he

conclusively determined that the high TVA readings were not caused by surface

discharges or loose tapes. Mr. Brown was not cross-examined on this issue.

131. The allegation that the test results were misinterpreted falls into the category of

possible areas where a mistake was made, but for which there is little or no

evidence from the record we have before us to support it.

c. The confirmatory PD test results at the neutral end could have been caused by

changes in temperature or humidity.

132. This explanation was not followed up with any evidence and must remain

speculation.

133. Mr. Snyder from TG Advisors stated the mere fact that the insulation was aging

does not imply that failure was imminent. In his opinion, the higher PD activity

was incorrectly used to conclude that the bar was at high risk of failure and was

the likely cause for the Trip. He had no other evidence-based explanation for the

Trip, or for the expanded PD activity on Bar T5 when the wedges were removed.

His view was that as the Unit passed all other electrical tests it was fit for service.

37

When asked by the Panel what should an owner do if the TVA tests clearly show

a bar at the end of life, but passes all other tests, his only answer was to get

another opinion. Asked if the windings were not at the end of their life, how one

could explain the significant increase in PD activity across all three phases after

the replacement of Bar T5, he testified he had no idea how this could happen.

134. The difficulty with the opinions of those who say that - should have considered

the Trip to be a "false trip" and then returned the unit to service is that such

opinions ignore or downplay the evidence that the DGSH relay and protective

system were working properly and that there was a significant anomaly on the

TVA readings for Bar 5. As Mr. Gorney testified, had he been the decision-maker

at - at the relevant time, he would have advised against an immediate return to

service. He stated that the approach - took in considering the Trip to be a

legitimate relay actuation until proven otherwise and not a false trip, was prudent,

and was well within the GOP range. 41

135. In Mr Gorney’s opinion:

…what - did in this case was very straightforward and falls squarely within the GOP range: - engaged in house expertise, engaged third party expertise, and engaged the OEM. - established whether the problem was inside or outside the generator and, in parallel, verified that the operation of the protective devices was proper. With the advice and direction of the OEM and third party expertise, - then systematically went down the course that the data directed. And it did these things in a timely and deliberate fashion.

136. In the view of Mr. Gorney, the Respondents’ experts do not deal with the fact that

the management of - had to consider all the data, which pointed to significant

delamination in Bar T5 and the prospect that the DGSH relay would simply trip

again if the Unit was put back in service. - also had to seriously consider the

41 Gorney reply report p. 5 para 17.

38

recommendations of both H and K. As stated by Mr. Gorney: “These are powerful

and compelling reasons to proceed as advised.”42

137. While each of the Respondents’ experts are expert in their particular technical

field, they did not opine on the bigger picture. Most of their experience is in

providing technical recommendations to management. To simply suggest that

because no actual ground fault was found, this must therefore be a false trip and

false trips are traditionally dealt with by returning a generator to service after a

hipot test, ignores the full picture. All of the experts called by the Respondents,

while very proficient and well qualified within their particular engineering fields,

were focused too narrowly on the issue of there being no discernable ground fault.

138. Mr. Gorney has the experience of a senior manager and whose opinion

encompassed all of the factors that - had to deal with. -'s investigation was to

determine the condition of the stator winding and the reason for the Trip, not to

simply rule out a stator ground. Mr. Gorney testified that in his opinion, it was

not GOP to assume a false trip of the DGSH relay when testing shows it was

functioning properly, external causes were eliminated, and the TVA test identified

the likely cause of the trip being the delamination of Bar T5.

139. In an email dated March 23, 201343, Mr. Florence documented the discussion and

decision made by Messrs. Shaw, Emmott, Campbell, Struhan, Koay, Kim and

Kinzel of -. All concurred that the recommendation from H to replace Bar T5 be

followed. He explained the reasoning as follows:

The rationale for choosing to do this work was based on a consideration of the alternative – returning the unit to service without repairs. Since the TVA corona probe test showed there is deterioration in winding insulation, it is likely that the unit would trip on ground fault again. If that happens, we could go through the lengthy testing process that has gotten us to where we are now, or we could rest (sic) the trip and restart, or we

42 Gorney reply report p. 10 43 Doc 000006.504026.0001/1

39

could consider decreasing the sensitivity of the ground fault trip. The last two options were discussed and quickly discarded as unacceptable because they are outside of any industry-standard of good practice and risk much greater damage to the stator. The first option does not make sense economically as it would only cost more indirect spend and lost production to get to the same place we are now.

140. - had two choices; replace Bar T5 or put the Unit back in operation and face the

likely outcome that the DGSH relay would trip again, resulting in an even longer

outage than would occur if Bar T5 was immediately replaced. The fact that the

Unit passed the electrical tests could not reduce the risk that a further failure

would occur once the bars were put under the mechanical and thermal stresses of

normal operation.

141. - had experience in replacing single bars. Mr. Gorney summarized the situation in

the following words:

The data showed a change in condition in just 11 months. The spare bars needed to replace bar T5 were in storage, the OEM supported the decision, the OEM had the expertise and capability to execute a successful partial rewind, and - had previous experience successfully completing partial rewinds. Given the above, - was right to expect that the partial rewind would be successful in this case…44

142. According to Mr. Morrison only Bar T5 needed to be replaced, versus putting it

back in operation and having it fail a second time, possibly with more damage,

which could not be defended given the information that was available. According

to Mr. Morrison, 10 months to one year was too long to wait for repair at the next

planned outage.

143. Mr. Glover stated that - electrical engineer Bill Lu and M had confirmed that the

DGSH relay operated properly to trip the generator, the protection system was in

good working order, there was no external circumstance that could have caused

the Trip, so the Trip was not a “nuisance” trip. - “rightfully needed to have a full

understanding of the cause of the Trip and have a sufficient level of comfort,

44 Gorney reply report para 28

40

before restarting the unit, that the Trip would not re-occur and the generator

would not suffer damage.”45

144. It was Mr. Glover’s view that on March 5, the generator did not operate as

intended; it tripped offline due to a DGSH relay operation. - and M investigated

the Trip and confirmed that: (1) the DGSH Relay operated properly to trip the

generator; (2) the protection system was in good working order; (3) there was no

external circumstance that could have caused the Trip; and (4) the Trip was not a

nuisance trip. It was then incumbent upon - and required by GOP to continue

performing a thorough investigation of the Trip before return to service, so as to

prevent a reoccurrence of the Trip and/or a ground fault leading to physical

damage.”46

145. Mr. Glover also disagreed with the view that - ought to have simply done a hipot

test and restarted. He stated that during the investigation into the cause of the

Trip, - followed a process that was consistent with the EPRI flowchart

procedure47 for assessing the condition of generator insulation and, as shown in

the flowchart, acceptable hipot test results do not end the assessment and do not

take the place of a thorough assessment of stator winding insulation. After a

ground-fault relay has tripped, simply returning a unit to service following

acceptable hipot test results, without further assessment, in Mr. Glover’s view,

would have been inconsistent with industry guidelines and standards.

146. Mr. Bissell stated that as both H and K recommended replacement of T5, it would

have been reckless for - to ignore these recommendations. In his opinion, the only

reasonably safe path forward for a return to service was to do a partial rewind of

Bar T5. He stated:

In my experience a partial rewind is a standard remedy for a localized problem like the one found here. Partial rewinds, especially with the OEM involved, are typically successful and allow a return to service. It

45 Glover reply report p. 8 46 Glover reply report p. 16 47 EPRI Handbook To Assess The Insulation Condition of Rotating Machines (Vol. 16, 1987)

41

was reasonable for - to expect that if they did the partial rewind that they could return to service48.

147. In the view of Mr. Thompson, while a hipot test is a good tool for troubleshooting

and proof testing, it is too simplistic to just state that if a component passes a

hipot test, an owner can ignore other abnormal testing results and return a unit to

service. In his opinion, when there are other factors to consider, such as

conflicting and abnormal test reports, everything has to be taken into

consideration. In particular, NERC standard PRC-0048 requires that relay trips

be investigated and corrected and a relay cannot be said to have had a false trip

unless legitimate causes for its operation have been investigated. It was Mr.

Thompson’s opinion it would not be acceptable or within GOP to simply report

the relay operation as “unexplained” and return a machine to service to see if it

would trip again. He stated:

A partial rewind of a turbo generator is often a viable option following a stator bar failure. That is why spare stator bars are often purchased at the time a rewind is performed. If a winding is nearing end of life, and a stator bar fails, the spare bars can be used to return the unit to service while a new winding is ordered. I believe this to be a fairly common practice from my experience at TVA and in my conversations with other utilities.49

148. Mr. Mihelcic testified that passing a high-voltage test, including an endurance test

simply means that at that time the winding is electrically okay while

disassembled, but it does not answer the question as to whether it is mechanically

unsound so as to be unable to return to service. He stated in his report:

My opinion is the generator stator ground fault relay tripped due to an issue with the generator stator windings and returning to service without performing any repairs would have extended the outage as the ground fault relay would just trip again if no repairs were performed. The hipot test would not find the reason the generator stator ground fault relay tripped. The high TVA probe test result for generator stator Bar T5 was a significant concern and I agree with the partial rewind to replace Bar T5 as partial rewinds are normally completed successfully. The risk of

48 Bissel reply report para. 39 49 Thompson reply report Section B5

42

restarting the unit was significant per K and H’s recommendations. My past experiences with replacing a generator stator bar (i.e. partial rewinds at twelve other sites) were all successful.50

149. As Mr. Mihelcic testified, Bar T5 was a “stand-out” and he would not have

done a hipot test at this time but would have recommended a replacement. In his

opinion, the mechanical stresses had caused the bar to lose its resin, making it not

mechanically strong enough to resist the stresses experienced in operation.

150. Mr. Bissell testified that in his 50 years of experience in the electric power

industry, he could not recall ever recommending that anyone ignore, and had

never seen anyone ignore, other test results and return to service based on hipot

test results alone. In his opinion, the high TVA readings and the concerns

expressed by K and the OEM made it inappropriate to do a hipot test. He was also

of the view, based on his experience at Westinghouse, that a hipot test was not a

standard test and was used only after uncommon or unusual repairs to determine

the integrity of the repairs.

151. Mr. Holst testified -'s decision to perform a partial rewind of Bar T5 was founded

on “adequate and reliable information” as well as sound

logic. In his opinion the decision to replace Bar T5 was reasonable, would return

the unit to reliable service more quickly than any other alternative, and conformed

to GOP.

152. The EPRI Handbook identifies a need to take corrective action based on

increasing partial discharge or a very high TVA Probe reading. It states, in part:

The need for corrective action to upgrade the stator phase and ground wall insulation to an acceptable condition can be identified by one, or a combination of the following unacceptable results… • Very high partial discharge levels and/or increased levels from a

previous test. • Very high local partial discharge levels probe techniques.51

50 Mihelcic reply report p. 4

43

vi) The TVA test results

153. A number of issues were raised regarding the TVA test results that were relied on

by H and -. The allegations included the following:

a. Mr. Brown was demonstrably not objective when it came to the TVA

probe test and the results that it returned.

b. - did not retain a truly independent and impartial expert in a timely manner

and - did not critically evaluate and assess the evidence and

recommendations it received from H and K.

c. There were issues with the test equipment that cast doubt on its reliability,

particularly the results used to decide to replace Bar T5. These equipment

problems became apparent during the investigation, but the suspect results

were not discarded and - failed to challenge or question the obviously

suspect results or the advice and recommendations being made based on

those data.

a) Brown was not objective

154. While he certainly appeared as an advocate for the TVA test during his testimony

at the hearing, Mr. Brown’s, and K’, reports appear balanced and professional.

From his testimony at the hearing, there is no indication that Mr. Brown’s

enthusiasm for the TVA test distorted his professional opinions and advice given

to - during the Event.

b) The need for objective experts

51 EPRI Handbook Exhibit at page 6-14 - Binder 2, Tab 40.

44

155. It appeared to the Panel that Mr. Brown and K were independent, impartial and

highly experienced. H was clearly expert and independent although

understandably conservative. There was no evidence that with a single bar repair,

a generator owner should seek another further independent opinion beyond those

of the two independent experts. At a later time, when the decisions were made to

replace Bar T31 and to do a full rewind, Mr. Klempner was also retained to

provide a further opinion. There is no dispute that all parties regard Mr. Klempner

as an objective expert in the field of electrical generators.

156. As referenced above, the email of March 23, 2013 from Mr. Florence shows

that - considered the opinions of H and K and did not simply adopt them without

review. In particular, the email states that H recommendations 1 and 2 will be

followed, but recommendation 3 (to prepare a full rewind kit) would be “further

evaluated”.

c) The faulty meter

157. The evidence that the meter used in the March TVA tests was not working properly

came to light in the form of an October 1, 2013 email from Mr. Brown to Mr.

Sharp. It listed other sites where high readings had been previously obtained.

158. Mr. Brown, in his sur-reply witness statement, sought to explain the results from

these other sites. In his surreply he states he was not aware, and to his knowledge

neither K, nor Iris Power was aware, of any potential issue with the Iris PPM97

meter until mid-April 2013 when he questioned some TVA readings he was

getting at K.

159. Mr. Sharp was cross-examined about the tests at the other generating sites. He

stated that none of these involved a forced outage, so presumably they were not of

the same level of concern. He had little recollection of the circumstances under

which high TVA results were found, except for Sundance 1, in which a reduced

DC ramp test was done before the unit was put back into service. The high

45

readings at all other sites did not result in any particular repairs. Mr. Sharp could

not assist with details as to the circumstances for the high readings or how they

were dealt with at the other sites.

160. Mr. Florence was also examined about these other sites and testified that had high

readings at other sites and the fact they had not resulted in any particular repair

been brought to his attention, or if there were concerns about the accuracy of the

Iris probe, he would have had discussions about this before the decision was made

to replace Bar T5.52

161. Mr. Brown explained why the readings at K 1 resulted in a recommendation to

replace Bar T5, while no action was taken at the other units that had high

readings. He stated that one, or a combination, of the following facts applied to

the other units:

(a) The results were not repeatable on the second more investigative TVA

scan (unlike the high readings on K 1 in 2013), which cast some doubt on the

reliability of the initial "high" reading;

(b) The results reduced in magnitude with time;

(c) The results were in a very isolated narrow area and did not grow in

magnitude or length; or

(d) The results were related to surface PD at the end of the slot.

He then went on to explain other reasons why the readings at the other sites did

not result in any action or repair. 53

162. The Panel found this evidence from the witnesses to be very general and appeared

to simply list any number of reasons why a particular unit might have been dealt

with in a particular way as a result of some high TVA test readings.

52 Transcript page 201. 53 Brown Surreply Witness Statement, para 6-7.

46

163. It can be argued that -, to be consistent, should have ignored the TVA results here,

just as they did elsewhere, but this would lead to the need to have a detailed

analysis of the reasons for the high readings for the various other units, evidence

we do not have. Rather we have some evidence from Mr. Brown that in a general

way explains why the K situation is different from the others.

164. In his cross-examination, Mr. Brown was taken to the October email that lists the

other sites, but no questions were asked about the readings at the other sites, nor

was he asked about his explanations set out in his surreply witness statement.

Instead, Respondents say his evidence on this point offends the best evidence rule

and should be discarded. They say that evidence about the other sites should have

come from -. No documentation or reports regarding TVA test results from the

other sites were produced at the hearing by -, nor did the Respondents seek further

production.

165. The Act deals with evidence in section 21:

21(1) The arbitral Panel is not bound by the rules of evidence or any other law applicable to judicial proceedings and has power to determine the admissibility, relevance and weight of any evidence. (2) The arbitral Panel may determine the manner in which evidence is to be admitted.

166. The overriding consideration with respect to evidence is that it be relevant to an

issue and its admission or the refusal to admit it not violate the principles of

equality and fairness. Section 19 of the Act states:

19(1) An arbitral Panel shall treat the parties equally and fairly. (2) Each party shall be given an opportunity to present a case and to respond to the other parties’ case.

167. The Panel does not perceive the admission of Mr. Brown’s surreply witness

47

statement as violating section 19. It is clearly relevant to a live issue at the

hearing. Counsel had the opportunity to question Mr. Brown fully about the other

sites, but did not do so. As stated above, Respondents did question both Mr. Sharp

and Mr. Florence on the point. For what it is worth, Mr. Brown’s surreply witness

statement stands as part of his evidence.

168. Mr. Brown was also not cross-examined on whether the high readings in March

ought to have caused him concern about the reliability of the equipment.

169. From the evidence we have about the other sites and the lack of any

correspondence or documentation at the time the K 1 readings were taken in

March, the Panel must conclude that neither K nor - had any concern about the

reliability of the test equipment used to test the Unit in March, 2013, nor any

concern at the time that high readings at other sites should cause the K Unit to be

dealt with differently than it was.

170. With respect to the meter that was used in March, the Panel has difficulty

accepting Mr. Brown’s testimony that suggests the meter somehow became

unreliable between the testing in March and April of 2013. As Mr. Milano pointed

out, the lack of linearity was caused by a particular diode that was used in the

meter. This would, in theory, give continuous systemic errors.

171. There also remains the question as to whether the meter lacked linearity only

between ranges, or also exhibited non-linearity within a given range. The

evidence on this point is conflicting and not at all clear.

172. Mr. Brown says he calibrated the meter before its use in March and it was

working correctly. Whether or not this is so, the Panel must conclude on the

evidence that the meter in question had some kind of linearity problem, but

neither Mr. Brown nor anyone at H or - had any reason to be concerned in March

about the accuracy of the meter used in the TVA testing. The Panel has no

48

evidence to suggest Mr. Brown or - ought to have known the readings were faulty

at that time.

173. The graphs in the K Report of March 26, 2013 dramatically show the extent to

which Bar T5 is an outlier, with no other bar showing anything like the readings

on T5. Also, the graph containing the 2012 results shows nothing out of the

ordinary for Bar T5. Regardless of any inaccuracy in the meter used, even if 2 or

3 or 10 times overstated, clearly Bar T5 was showing significantly different

readings than the others.54

March 2013 February 2012

Factual Findings

174. The Panel finds that at the time the decision was made to replace Bar T5, -:

a. Knew a Trip had occurred that was in all likelihood caused by an issue in

the generator;

b. Knew that very high TVA readings were found on one bar that increased

when the wedges were removed evidencing delamination or a breakdown

in the insulation, caused by mechanical and thermal forces on the bar

when the generator was operating;

c. Had confirmation of concerns arising from the TVA test by reason of a

partial discharge test done at the neutral end, phase A, showing two times 54 Exhibit 25 from the manufacturer speaks of a factor of 2 or 3. The April tests speak of a difference between meters of a factor of 10.

49

the reading at the line end, or on the neutral of the other two phases on the

Unit;55

d. Had the opinions from both H and K that Bar T5 needed to be replaced, or

it was likely the relay would trip again.

175. - reviewed and considered the recommendations before coming to a conclusion.

176. Based on the facts available in March, the Panel cannot say - had sufficient

information to question the reliability of the test results or the opinions of H and

K to replace Bar 5. The TVA tests were clearly appropriate and could not be

ignored. They militated against doing further hipot testing.

Determination

177. In the circumstances it was reasonable for - to accept the results and the

recommendations of H and K.

178. Applying the definition of GOP discussed above, “in the exercise of reasonable

judgment in light of the facts known or reasonably ascertainable”, the decision to

replace Bar T5 could be expected to return the Unit to operation “at a reasonable

cost consistent with applicable Laws, reliability, safety and expedition.”

179. The Panel finds that based on the information available at the time, the decision to

replace Bar T5 was reasonable and fell within the definition of GOP.

vii) Was the stator condition that required the replacement of T5 preventable?

180. The evidence discloses that prior to the Event, the Unit was run for 2 years

without proper hydrogen drying,56 which clearly resulted in major moisture and

55 Brown first witness statement, pp18-19 56 TRA-90003112

50

contamination problems. "Several kg of copper and iron oxides" are thought to

have been distributed throughout the stator57 necessitating a solvent cleaning

operation during the 2012 planned outage.

181. Messrs. Milano, Snyder and Halpern all opine that this was not consistent with

GOP.

182. There is also evidence that not all the contamination was removed. Both Mr.

Halpern and Mr. Milano cite examples in their reports of contamination

continuing to exist near the end of the core when the rotor was pulled during the

Event in 2013.

183. Mr. Snyder opines that the combined elevated moisture, acid and corrosion

contamination may have accelerated the deterioration and aging of a 29 year old

stator winding. Dr. Nelson, to the contrary, states in his report that it is unlikely

that any moisture present would have had much effect on the ground wall epoxy-

mica insulation.

184. As stated above, Mr. Milano says the continued presence of end winding

contamination, or contamination just inside the core boundary can add to or

amplify the discharge intensity, but Mr. Milano did not opine on whether moisture

can accelerate the deterioration of the insulation itself.

185. It is of note, in this context, that prior to the return of the Unit to service after the

2012 Uprate, the Unit was tested, including a TVA test and hipot test. All results

were acceptable.

Determination

57 Doc 000001.017278.0001

51

186. We are left with a record in which a question is raised about contamination, but

there is little or no evidence that operating the Unit without dehumidifiers prior to

the 2012 Uprate caused any detectible problem with the stator insulation in 2013,

or caused or contributed to the Trip.

viii) Decision to replace Bar T31

187. On April 16, 2013, Mr. Campbell reported to Mr. Florence that following the

replacement of Bar T5, H had recommended to go directly to a high-voltage AC

test, but that before doing so -’s procedure was to make sure the stator was

suitable to be exposed to a high-voltage test, and it would first carry out a TVA

probe test. During that test it was discovered that all slots except three had failed

and it was recommended that a further test be conducted with a different probe.58

188. In a report dated April 17, 201359, H reported that another TVA probe test was

performed using a probe that H had rented. The H TVA probe indicated an order

of magnitude lower than K' probe.60 The recommendation was to perform the

TVA probe test again using another calibrated probe and perform other electrical

tests, including a DC ramp test. The opinion was given by H that during the

partial repair work, the bars were repetitively energized up to 28.5 kVac or

48.45kVdc “which may have accelerated the insulation deterioration, which was

at its end of lifetime.” In its report H again recommended, for the third time, a full

rewind, but on this occasion recommended that this be done “as soon as possible”.

189. On April 18, K performed another TVA probe test using another calibrated TVA

probe. The result showed many unacceptable slots, most notably slots 31, but also

for slots 7, 8, 26, 43, 44 and 46.61 In a report April 19, 201362, it was H's

conclusion that if the generator was restarted without suitable repair, given that

58 Doc 000006. 504021.0001 59 Doc 000006.427261.0002/2 60 Doc 000006 .42726 1.0002 61 Doc 000006 .49699 5.0002 62 Doc 000006.496995.0002/4

52

the partial discharges were significant on all three phases, there was a chance that

an in-service ground fault would occur and it could become a double line to

ground fault, which would lead to significant damage to the core and the new

rotor. H now recommended a full rewind before bringing the unit back into

service. H also strongly recommended that if - chose to put the unit back into

service, an AC Hi-Pot test followed by a PD test be performed first and the unit

removed from service as soon as the rewind kit arrived.

190. On April 19, 2013 there was an internal roundtable discussion within - focusing

on these test results.63 It was decided, inter alia, to:

a. Request a quote from H for an emergency rewind kit;

b. Perform a DC ramp test, and

c. Have John Sharp arrange for a third party expert to review the test results

and provide advice and risk assessment.

191. By email dated April 20, 2013, - contacted Mr. Geoff Klempner, a recognized

generator expert.

192. On April 24, 2013, Mr. Klempner reported that high and changeable TVA

readings tend to indicate delamination and voiding, the most common causes

being temperature and/or mechanical stresses; the stator winding could be in a

further weakened state simply because of its age and being disturbed and re-

tightened. The risk of another failure was in the medium to high range. His advice

was to try a DC Ramp and AC hipot at 110% and if it passed “you can hope it

stays on line until the new rewind kit arrives.” A “win-win situation.”

193. In its report dated April 25,64 H reported on the results of its partial discharge

testing. It concluded:

63 Doc 00000 6.504017.0001 64 Doc 000011.1906976.0003

53

The PD at rated voltage appears to be lower for phase U and phase V. This may be due to the effects of the hipot that immediately preceded the partial discharge testing. Both of these phases experienced very high PD during the hipot, relative to phase W. The PD for phase W has become significantly larger since the previous test and the inception voltage has reached a very low voltage, indicating wide spread deterioration. The significant change in PD results between the two tests help to reconfirm the conclusion that the generator insulation system is at its end of life and deteriorating rapidly.

It is recommended that a full rewind be performed before returning the generator to service. (bolding in original document)

194. On April 26, 2013, Mr. Sharp requested a further opinion from Mr. Klempner

regarding the replacement of Bar T31. Mr. Sharp indicated the plan was to

include a DC Ramp test, and the AC hipot test. Additional TVA testing on Bar

T31 would be done and if verified Bar T31 would then be replaced. Mr. Klempner

replied on April 29, 2013 that:

a. Based on the latest test data, the situation was a “two-edged sword”. If the bar

was replaced it reduces the chance of a further trip and the unit could operate

until the rewind kit arrives, but the work could create more high TVA

readings and potential trips could occur.

b. To put the machine back together without replacing Bar T31 meant the ground

protection would have a high probability of tripping the machine out of

service again, but replacing it might create more damage and cause a ground

trip.

c. His conclusion was that “I don’t disagree with your approach or the program

laid out…”65

195. On April 30, 2013 Mr. Florence concurred with the decision to proceed with the

replacement of Bar T31, based on the estimate that it would have the generator

65 TRA 9 000 3239

54

back on line by June 10 at 14:00.66

196. Just as with the first TVA test results respecting Bar T5, Mr. Milano was of the

opinion that the test results for T31 were misinterpreted and this bar was also

replaced due to “the erroneous analysis of the corona probe test”. While not

expressly stated, but implied, Mr. Milano is of the opinion the poor results for all

of the other bars that were observed after the replacement of Bar T5 must have

similarly been misinterpreted and erroneous.

197. In contrast to this view, according to Mr. Fenton, it should have been anticipated

that disturbing the aged insulation on the stator winding in any fashion could

result in the likelihood of “collateral” damage. He notes that Mr. Klempner stated

this in his documents and this may be what occurred. Mr. Fenton opined that

once Bar T5 was touched, the integrity of the stator winding may have been

compromised due to the work required to remove it and the adjacent Bar T6. This

loss of integrity and incidental work done on other parts of the stator winding

“likely resulted in deterioration.” The subsequent removal of Bar T31 and

adjacent bars likely furthered any deterioration. Thus, according to Mr.

Fenton, - began a “downward spiral from which recovery was unlikely,” this was

a "self-inflicted and unnecessary wound."

198. Mr. Fenton’s view that - ought to have known that the insulation was so

deteriorated that the partial rewind carried with it unacceptable risks of further

damage seems at odds with the opinions that the insulation was not sufficiently

deteriorated to require the replacement of T5 in the first place.

199. Mr. Gorney says in his report:

The damage to the winding following Bar T5 could not have been anticipated by -. It is easy to criticize the Bar T5 replacement in hindsight, but an assessment of whether the decision to replace bar T5 was GOP

66 Doc 000024.11859693.0001

55

cannot be made in hindsight—it must be made in light of the facts known at the time.67

200. While it was recognized that there was a risk of further damage, Mr. Mihelcic was

of the view that he would also have done the partial rewind on Bar T31 since

there was nothing to lose at that point. Mr. Klempner, while also raising the risk

of further damage, ends his assessment by saying he cannot disagree with -’s

approach.

Determination

201. Given the test data that was available, including the data from the calibrated TVA

probe and the opinion provided by the third party expert, the Panel finds that the

decision to replace T31 was reasonable.

202. At the time, - could reasonably expect a major failure, another trip, or worse, if

Bar T31 was not replaced.

ix) Decision Not to Return to Service until Rewind was Complete 203. On May 5, just prior to the removal of T31, Mr. Klempner was provided with

information related to the investigation of removed T5 and 6. He commented on

the “huge IR values and very high PI readings” and concluded that: “Basically, I

think the stator winding is simply old and its life used up. Time for a rewind…”68

204. Following the replacement of Bar T31 Mr. Klempner was provided with an

interim report from K dated May 16, 2013,69 and asked for his opinion about

returning the Unit to service until the rewind kit could be delivered. He reported

in an email of May 18, 2013 that having reviewed the tests:

a. The IR readings indicated dry and brittle insulation that could be prone to 67 Gorney reply report p. 16 68 Doc 000024.11860164.0001/1. 69 Docs 000009.1212782.0002; 000009.1212782.0001

56

delamination

b. The DEV and DIV appeared a bit on the high side again indicating dry and

brittle insulation

c. The PD had increased significantly after the last bar replacement

d. The PD patterns were erratic and not stable, indicating the amount (of)

voids and delamination had increased since the last bar replacement and

were likely changing in nature.70

205. Although having agreed with the strategy of replacing Bar T31, Mr. Klempner

was of the view that more damage had been done by its replacement, which had

caused additional voids and delamination in the ground wall insulation. His

conclusion was that the stator winding was in worse shape than prior to Bar T31

replacement and the insulation was likely too brittle to handle this type of

mechanical activity. He concluded there was a significant chance of an in-service

failure if the generator was put back on line and he also found that there was a

low to medium risk of damaging the core.

206. As stated above, notwithstanding the risks of further damage with the replacement

of Bar T31, Mr. Klempner agreed at the time that it was worth trying the

replacement as the rewind kit had already been ordered.

207. H in its daily report of May 21, 2013 comes to the same conclusion regarding the

stability of the insulation: "the results over the last three tests show that the PD is

rapidly changing indicating that the insulation condition is no longer stable. This

conclusion is also supported by the changing dissipation factor and TVA probe

results.”71

208. In its report of May 23, 2013, K states that:

… the Return to Service on K Unit 1, awaiting rewind carries a significant risk of a repeated trip on ground fault protection. That is, assuming the

70 Doc 000024.11860175.0001 71 000008.855270.0002/1

57

ground fault was triggered by third harmonics from changing insulation capacitance within the winding from Line and to Neutral and within the phases. Should a ground fault occur then the risk of stator core damage is significantly increased.72

209. - says the K' May 23, 2013 report at page 37, Table 21, shows the TVA values

post-replacement of Bar T31 were reasonable and in fact were lower than the

TVA values that - had obtained in 2009. - argues that while these results were

used as justification not to return to service, the 2009 results, which were in places

worse, were used for the opposite purpose and as justification not to rewind the

stator during the 2012 Uprate outage. This submission seems to miss the point

that comparing individual readings was not the issue. By mid-May of 2013 it was

clear that the readings that were being obtained from the stator were rapidly

changing and the insulation condition was no longer stable.

210. Mr. Florence in his first witness statement stated:

The test data, recommendations, and expert comments supported the decision to do the full rewind. The alternative was accepting a real risk of stator core damage and a two year or more outage to repair (with significant extra repair costs, and potentially hundreds of millions of dollars in penalties and lost incentives) with no meaningful way of quantifying the probability of occurrence. On May 22, the decision to complete the full rewind prior to restarting the Unit was official.73

211. Mr. Holst stated that once the results of the post-Bar T31 removal electrical tests

were available, - reasonably determined that there were no alternatives to

performing an emergency full rewind prior to returning the unit to service. The

information available to - was reliable and sufficient to determine that an

emergency full rewind was necessary and would be successful. The procurement

of an emergency full rewind kit was in progress and was not delayed by the Bar

T31 replacement.

Determination

72 000007.807012.0002/2 73 Florence, witness statement October 15, 2015, paras. 174-175

58

212. Given the test data and opinions of H, K and Mr. Klempner, the Tribunal finds that it

was reasonable for - to have decided to wait for the full stator rewind before returning

the Unit to service.74

x) Timing of the Decision to Order a full rewind kit

213. As stated above, in its report of March 22, H had recommended: “preparing a full

rewind kit and plan for stator rewind followed by (sic) this stator rewind.” The

decision to proceed with the replacement of BarT5 was based on this report. This

recommendation to prepare a full rewind kit and plan for a stator rewind after Bar

T5 was replaced was not immediately adopted by - but was to be “further

evaluated.” At the time it was estimated that if Bar T5 could be replaced

successfully, the Unit could be back in service by April 21.

214. Mr. Florence testified that he took this recommendation as something that would

have to be planned for:

I actually talk with the plant manager about looking at H's recommendation on the stator rewind kit. But in -- in -- not in anticipation of doing it immediately, but planning for it, which, to me, would be for the next turnaround. 75

215. The revised report from H, dated March 27 changed the recommendation to add;

“A partial bar replacement is considered a temporary repair, and full rewinding

is required.” There is no evidence that Mr. Florence revisited the issue of when to

order the full rewind kit based on this revised report.

74 We note that Mr. Kim testified in his witness statement that he had a conversation with a Mr. John Fenton from Hatch Energy, described as a Senior Electrical Engineering Specialist, who had been retrained by the - as a consultant. This is not the same Mr. Fenton who testified in these proceedings. In Mr. Kim’s words:

“I was with Mr. Fenton in -’s lobby in Calgary, while waiting for others to show up to take them to the meeting room. Mr. Fenton told me that he agreed with -’s decision to do a full stator rewind before restarting the Unit. Mr. Fenton and I were the only parties to this discussion. He prefaced these comments with something to the effect of “between you and me” or “in confidence.”

Mr Kim was not cross examined on this evidence, nor was Mr. Fenton called as a witness. While we do not base our determination on this evidence, it does provide some confirmation for the actions taken by -. 75 Transcript page 152

59

216. The issue of immediately ordering a full rewind kit was not addressed until after

Bar T5 was replaced. It is at this time that - had received the TVA test results that

had shown all slots but three having failed and the decision had been made to redo

the tests with another meter. In an email of April 17 from Mr. Campbell to Mr.

Florence76, Mr. Campbell says they will be asking H for a quote for a rewind “just

in case.”

217. According to the testimony of Mr. Florence, the decision to do a full rewind was

made April 19, 2013. The documents disclose this was the date - requested a

quote for an emergency rewind kit.

218. The quote from H is dated April 29, 201377 and the purchase order for the

hardware for the rewind was issued on May 6, 2013.78

219. There was some back and forth discussion about a purchase order for the actual

labour and some changes in the hardware. This was not sorted out until the final

PO in June, 2013. Respondents submit that a delay until June to order the rewind

kit was inordinate, however, H says in an email dated June 24, 2013 that

notwithstanding the changes and finalization of the actual work to be done, “we

have not changed our mfg. & delivery target date from the very beginning. It is

our hope and intentions to deliver this order early than noted in the PO.” 79

220. It does not appear that the failure to finalize all of the details of the rewind with H

until June delayed the installation date from that first envisaged in early May,

when the hardware was ordered. In fact, according to -, the full rewind kit arrived

on site approximately two weeks earlier than estimated.

76 Doc 000006.504021.0001 77 Doc 000006.425780.0002 78 Doc 000024.11859846.0001; 000024.11859651.0001; Appendix B to Lou Florence first witness statement 79 Doc 000010.1754305.0001

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221. Mr. Fenton in his report stated:

If, for the moment, we assume that - was correct not to return to service without a full rewind, the decision to order one should have been made much earlier. If - had proceeded expeditiously, as is considered Good Operating Practice, the rewind kit would have been ordered on or about March 27 and this would have reduced the total outage by 39 days. The documents show a complete lack of expediency on -’s part. In my opinion, the unit could have been returned to service and the rewind kit ordered for the next planned outage. However, if we assume that - was correct not return to service without the full rewind, the lengthy outage was unnecessarily extended by delayed action on the part of -.80

222. The difficulty with this analysis is that at March 27, it was expected that the

replacement of Bar T5 would solve the issue of a further trip and the Unit could

be returned to service. There was no evidence at that time of any major general

deterioration in the insulation necessitating an emergency rewind, nor was there

any test data to suggest the Unit could not be returned to service following the

replacement of Bar T5. The TVA test data showed Bar T5 as an outlier, with all

other bars appearing acceptable. All other tests showed the stator to be suitable for

a return to service. At the time, Mr. Florence presumed a full rewind would be

required at the next Planned Outage but it would not need to be done to get the

Unit back up and running.

223. There is also no evidence that had a decision been made to order a rewind kit in

March, it would have been on an emergency basis and we have no evidence as to

when it would have been scheduled for delivery.

224. Mr. Fenton confuses the timing of events. The decision to not return to service

without the full rewind was not made until May 22, based on the data that was

then available. It is hindsight to say a decision to order the rewind kit should have

been made in March.

80 Fenton report p. 30 lines 10-18

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225. The evidence does not disclose that H was recommending an immediate rewind in

March, 2013 and if a rewind kit was ordered in March it presumably would have

been scheduled for delivery in the ordinary course of business. In March there

was no need to order it on an emergency basis.

Determination

226. In March 2013, based on the test data available, the expectation that a full rewind

could be scheduled for the next Planned Outage was reasonable.

227. The Panel cannot say that the decision to order a full rewind kit on an emergency

basis should have been made prior to April 19, 2013.

xi) The length of time for H to deliver the rewind kit

228. The full rewind kit from H arrived on site on August 29, 2013, which was Day

178 of the Outage. In -’s submission, this was unreasonable and there remains no

reasonable explanation as to the excessive duration for the Outage. As Mr.

Snyder explained in his testimony, it is clear that "delivery lead time of the

spare winding components had a significant impact on the outage

duration". This led Mr. Snyder to the opinion that - should have solicited

proposals from third party non-OEM suppliers. While this may have been

possible, there is no evidence that another supplier could have manufactured and

delivered the rewind kit in a timelier manner.

Factual finding

229. The Panel has no substantive evidence that the 15 weeks it took for delivery of the

full rewind kit was unreasonable.

xii) The decision to not have a spare rewind kit on hand

62

230. - submits that, when considered in context, it was unreasonable for - not to have a

full rewind kit on hand at the time of the Trip on March 5, 2013. In particular, it

says that in addition to having asked the IAT in 1999 for a rewind capital

allowance during the term of the PPA, which was refused, -’s decision was not

reasonable because it was aware that: (a) the stator of the Unit was in the “grand

age” or “end-of- life” stage, during which stators are more prone to failure due to

insulation degradation requiring rewind or replacement; (b) industry data

indicated that 50% of similar model generators had required or undergone stator

rewinds prior to reaching the age of the Unit, and (c) it had elected to proceed

with the Uprate without rewinding the stator.

231. Dr. Nelson says in the circumstances of the Uprate, GOP would have dictated the

company put in place a full rewind kit.

232. Similarly Mr. Halpern in his report states “…I don't see any plans in 2013

that - had to rewind the stator within the near or long term, and since the unit was

32 years old, the failure to have a spare rewind kit on hand was a breach of

GOP." 81

233. While Messrs. Halpern, Nelson and also Mr. Eisenhart opine on the need for a

rewind kit, it is of note that no one could point to industry practice to have a full

kit on hand. As stated by Mr. Gorney, rewinds are done as needed and as

determined by condition assessment and OEM recommendations based on life

cycle plans. Mr. Gorney stated: “we operated as many as 37 generators at coal

fired stations, with the oldest being 62 years old and the newest at 32 (as of

2011), and we had no spare rewind kits.”

81 Halpern report p. 49

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234. H’s uprating feasibility study82 in 2008 included a stator rewind, but as an option.

H made the point at page 19 that:

…the electrical stress to the insulating layer does not change by reason of the uprating because the rated voltage does not change. However, heat deterioration stress increases as the temperature of the stator coil increases by uprating. Thermal expansion of the coil occurs during generator load changes. This expansion produces shearing stresses due to the difference in linear expansion of the conductor and the insulation. The expansion also results in bending stress of the coil and. The electromagnetic forces present during operation causes the coil to vibrate. The coil end is fixed in place by a support structure to prevent excessive movement. The coil is held in the core slot by wedges. When the end winding fixing structure or wedges become loose, coil vibration occurs. This vibration quickly abrades the coil insulation resulting in rapid deterioration. Considering these factors, it shall be noted that the lifetime of stator will be consumed faster than before operating.

235. Under section 5.5, headed Comments on Refurbishment and Maintenance the

feasibility study states:

…stator insulation and rotor insulation deteriorates by long-term operation. Besides, up rated operation of generator will cause harder condition, which accelerates the thermal deterioration. It is suggested that either major refurbishment or shorter outage intervals for more maintenance be applied to maintain reliable operation. The most concern will be the stiffness of stator coil support. Stator supports are made of "organic materials", which deteriorates over years. Ultimately, weakened support will cause higher vibration of state or coil, and insulation will be damaged.

236. In section 6 under “Suggested Actions” the study included as item (3): Stator rewinding for life extension or shortened intervals of major outage. As the machine continues to operate and operates at more severe conditions the risk for damage to the stator increases. Stator rewinding would extend the life and reduce improve the operation of the generator as a whole.

237. - did some of the work H included as Suggested Actions but it did not do a stator

rewind as, according to Mr. Sharp, - had not decided on a life extension beyond

82 Doc 0006.441782.0007, at Section 5.4

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the PPA and H had said the existing stator winding was well within the uprated

thermal limits. 83

238. In 2011, before the Uprate (but following the feasibility study), H recommended a

full re-wedge of the stator windings, along with the installation of stator bar top

ripple springs as a bar restraint technology improvement. The purpose of re-

wedging and installing ripple springs was to ensure that the bars are held firmly in

place during operation.

239. Mr. Sharp stated that since the H Uprate feasibility study made it clear that a

stator rewind was not required, the decision was made not to rewind the stator

during the Uprate. Instead he supported the recommendation for a full re-wedge

and installation of top ripple springs, as a means to mitigate the risk of loosening

wedges and preserve the good condition of the stator winding. In his estimate this

would provide 6-8 years of service at the uprated voltage.84 Based on H's

recommendation, - re-wedged the Unit during the Uprate and installed the top

ripple springs. H did all of this work.

240. It does not appear that H ever recommended the option of having a full rewind kit

on hand.

241. Mr. Bissell found the opinion that - ought to have maintained a full spare set of

stator windings to be “ridiculous.” He stated:

I have worked with many companies that maintained various spare components based on the history of the machine or the critical nature of the operations, to shorten maintenance outages. I have never known a power utility that carried a spare generator winding.85

242. As stated above, GOP does not end with what utilities might generally do. It

includes “practices, methods and acts which, in the exercise of reasonable

judgment in light of the facts known or reasonably ascertainable, could have been 83 Sharp witness statement October 15, 2015 84 ibid 85 Bissell reply report para 43.

65

expected to accomplish the desired result at a reasonable cost consistent with

applicable Laws, reliability, safety and expedition” The Respondents argue that in

the circumstances of this case the 2012 Uprate necessitated a full rewind kit be on

hand.

243. On this point Mr. Bissell stated: “Hindsight is 20/20 and this statement is valid

only from that perspective. The unit history, the proposal for the uprating, and the

interactive discussion of the project development with the OEM did not justify a

stator rewind during the uprate project.”86 He stated the test results in 2012

showed a reasonable basis to expect the unit to run for another 6-8 years and it is

not common practice in North America to rewind a stator based on age alone.

244. The Panel notes that there was no evidence of stator winding deterioration in 2012

or that it was at the end of its life. At the time of the Uprate, the generator passed

all appropriate tests, including a hipot test.

245. The Respondents not only acknowledge that the stator had passed all electrical

tests in 2012, but they took the position in this arbitration that even after the Trip,

the stator was viable until the next planned outage. This appears somewhat at

odds with the position that the insulation was in such jeopardy that a full rewind

kit should have been ordered in 2012.

Factual finding

246. There was no evidence that the tests of the Unit in 2012 would have required - to

have a full rewind kit on hand in case it might be needed before the next planned

outage.

Determination

86 Ibid para 44

66

247. The failure to have a full rewind kit on hand was reasonable and not contrary to

GOP.

xiii) The overall length of time to complete each step

248. - objects to the length of time it took to effect the repairs. In its closing

submission it points out:

a. The rotor was not removed for visual inspection and further testing until

14 days after the initial Trip. It is said industry practice is to have made a

determination to remove the rotor for inspection and to have it removed

within 4-6 days of a trip;

b. Mr. Halpern’s evidence is that he has completed rewinds in far less time

than it took - to reach the point of diagnosing that the stator needed a full

rewind.

c. The rewind kit did not arrive on site until August 29, and the rewind was

completed on September 28, 30 days later. As outlined by Mr. Fenton, the

industry standard for the assembly and testing of a new winding is

between 15–18 days.

249. The Panel does have a concern that the overall time to get the Unit back on line

was indeed lengthy, but when broken down into the individual decision points,

there is no evidence of obvious delay. While it could be argued from the overall

time involved that there was a lack of alacrity, there is no hard evidence to back

this up. While the Respondents’ experts could offer general opinions that work

could have been completed in less time, there was no detailed delay analysis or

actual outage schedule analysis provided by the Respondents. The Panel is left

with generalized opinions and anecdotal evidence only.

67

250. It must also be kept in mind that - was first trying to determine the cause of the

Trip and then tried to get the Unit back into operation with a partial rewind. Only

when that failed was it necessary to order the rewind kit.

251. With respect to the rewind itself, no witness for the Respondents presented any

analysis of H’s Gantt charts or had any detailed or specific criticism as to how the

work ought to have gone faster.

252. H did understand the necessity to do the rewind as fast as possible. In its email of

June 20, 2013 it stated:

Considering the circumstances for XSD-1 (unplanned) and the timing of this work it is our strong preference to perform the work on a time and materials basis. We do understand the importance on rewinding this unit as fast as possible without jeopardizing quality.87

Factual Finding

253. There is no evidence that there was any significant delay in returning the Unit to

service.

VII SUMMARY OF FINDINGS OF FACT AND DETERMINATIONS

254. To summarize our findings:

a. Operating the Unit without dehumidifiers prior to the 2012 uprate did not

cause any detectible problem with the stator insulation in 2013, or cause or

contribute to the Trip.

b. The investigation of the DGSH relay was appropriate and confirmed it was

working properly.

c. The decision to dry out the stator fell within GOP and was reasonable.

87 Doc 000008.974092.0001

68

d. The decision to pull the rotor fell within GOP and was reasonable.

e. There was no good reason to exclude the TVA testing. f. At the end of the investigation stage all of the evidence pointed to an aged

insulation system with Bar T5 being the suspected cause of the Trip.

g. At the time the decision was made to replace Bar T5, - knew:

i. A Trip had occurred that was in all likelihood caused by an issue in the

generator;

ii. Very high TVA readings were found on one bar that increased when the

wedges were removed evidencing delamination or a breakdown in

the insulation, caused by heat and mechanical forces on the bar

when the generator was operating;

iii. Confirmation of the TVA test was obtained from a partial discharge test

done at the neutral end, phase A, showing two times the reading at

the line end, and on the neutral of the other two phases on the Unit.

This indicated there was an issue at the neutral end, phase A;88

iv. It had the opinions from both H and K that Bar T5 needed to be

replaced, or it was likely the relay would trip again.

h. - reviewed and considered the recommendations before coming to a

conclusion to replace Bar T5.

i. Based on the facts available in March, - did not have sufficient

information to question the reliability of the test results or the opinions of

H and K.

j. In the circumstances it was reasonable for - to accept the results and the 88 Brown first witness statement

69

recommendations of H and K and replace Bar T5.

k. The replacement of Bar T5 was expected to return the Unit to operation by

April 21, 2103.

l. Based on the information available at the time, the decision to replace Bar

T5 was reasonable and fell within the definition of GOP.

m. The decision to replace T31 was reasonable.

n. The decision to not order a full rewind kit until after it was determined that

the replacement of Bar T5 had not solved the problem, but had made

matters worse, was reasonable.

o. Given the test data and the opinions of H, K and Mr. Klempner, it was

reasonable for - to have decided to wait for the full stator rewind before

returning the Unit to service.

p. The Panel has no evidence that the 15 weeks it took for delivery of the full

rewind kit was unreasonable.

q. The failure to have a full rewind kit on hand was not unreasonable or

contrary to GOP.

r. There is no evidence of any significant delay in returning the Unit to

service.

VIII APPLICATION OF HILP AND FORCE MAJEURE DEFINITIONS

255. While a Force Majeure is defined as any event or cause which is beyond the

reasonable control of the affected Party, this case has been presented on the basis

70

that what occurred was a mechanical failure of the insulation. As stated by Mr

Morrison and acknowledged by Dr. Nelson, delamination is a mechanical failure

of the insulation, and mechanical failures will ultimately lead to electrical failures

of the insulation.89 This then necessitates determining whether or not there was a

HILP Event.

(a) Was there a HILP Event?

256. A HILP Event is defined as follows:

“High Impact, Low Probability Event” or “HILP Event” means a major failure of some or all of the components of the Plant (or a reasonable prediction by the Owner that a major failure of some or all of the components of the Plant will occur before the next scheduled Planned Outage) and which results (or could be reasonably expected to result) in the Plant being unable to operate or being forced to operate at a lower level (or is reasonably predicted by the Owner to be unable to operate or forced to operate at a lower level) and (a) it is reasonably predicted by the Owner that the Plant will be unable to operate or forced to operate at a lower level for a period in excess of six (6) weeks; and (b) the - has confirmed that the above conditions have been met;

257. At a macro level one can say the component that suffered the major failure was

the Unit itself. Once it was determined that the Trip was not caused by any

external factor, - had a Unit that was neither running nor generating electricity,

due to something internal to the Unit. At any level of analysis, this is a major

failure.

258. The Dictionary of IEEE Standard Terms (7th Ed.) defines a failure to be any

trouble with a power system component that causes any of the following to occur:

a. partial or complete shutdown, or below standard plant operation;

b. unacceptable performance of user’s equipment;

89 Transcript at page 1414

71

c. operation of the electrical protective relaying or emergency operation of

the plant electrical system; or

d. de-energization of any electric circuit or equipment.90

259. The shutdown of the Unit can thus be taken as the start of what might turn into a

HILP Event.

260. In analysing whether the steps then taken by - were reasonable and within GOP,

we must remember that the fact that some experts would have done something

different simply means there may be more than one way to address a problem.

The solutions are not binary. There is a range of options that may well be

reasonable in the circumstances.

261. The steps taken to dry out and remove the stator to determine the cause of the Trip

were reasonable and in accordance with GOP. They were part of the investigation

to determine if the Unit could be safely returned to service or whether repairs

were needed. The time this took also clearly forms part of any potential HILP

Event.

262. The test results indicated significant partial discharges for Bar T5, and Bar T5

alone. This, coupled with the increased PD readings at the neutral end of the

stator, referred to above, indicated deterioration of the insulation on Bar T5,

which would lead at least to a further trip, if not an actual ground fault and the

prospect of another outage if not dealt with immediately. The decision to replace

Bar T5 was reasonable and within GOP. The estimate of time it would take to

replace Bar T5 made it reasonable for - to predict the Unit would remain off line

for more than 6 weeks, thus falling with in the definition of a HILP Event.

263. The Notice of Force Majeure is consistent with this analysis. It stated:

90 Cited in Mr. Lu’s Witness Statement, para. 23

72

Pursuant to Section 14 of the PPA, - Generation Partnership-("-") hereby gives notice of an event of Force Majeure ("FM") at K Unit 1 ("Unit") arising from a High Impact Low Probability Event ("HILP").

… As indicated in -'s March 13, 2013 letter, the Unit tripped on a stator ground fault on March 5, 2013. The Unit has been offline since that time. - and various third parties conducted extensive testing following the event. On March 22, 2013, the generator stator OEM, H, recommended the replacement of 'a top bar of the stator based on the results of one of the tests. - has made a decision to accept the OEM's recommendation and has started the process of replacing the top bar. The Unit will be incapable of providing Generation Services until the Unit is returned to service. The current estimated return to service date of the Unit is April 21, 2013, which is subject to change as the repair schedule progresses.

264. The extensive testing carried out after Bar T5 was replaced disclosed a larger

problem than initially envisaged. While an attempt to shorten the outage with the

replacement of Bar T31 was tried, the evidence clearly demonstrates that the

information available to - at the time showed the insulation was at the end of its

life, was unstable and needed to be replaced.

265. At a micro level the mechanical failure of the insulation in one bar that had

caused the Unit to go off line had now lead to the realization that due to the

deterioration of the insulation system generally, a further trip, or actual ground

fault or worse would occur prior to the next Planned Outage.

266. By mid-May, 2013, if the Unit had been put back into service without a rewind,

there was “a reasonable prediction by the Owner… that a major failure will occur

before the next scheduled Planned Outage … and which could be reasonably

expected to result in the Plant being forced to operate at a lower level … and it

was reasonably predicted by the Owner that the Plant would be forced to operate

at a lower level for a period in excess of six (6) weeks.”

267. The HILP Event had gone from a Trip caused by a single bar to a predicted failure

of the insulation system generally.

73

(b) Was there a Force Majeure?

268. As stated above, Force Majeure is defined in part as follows:

“Force Majeure” means any event or cause which is beyond the reasonable control of the affected Party, or its Affiliates, including a HILP Event, a mechanical breakdown but only insofar as such breakdown results from a HILP Event...”

Was the HILP Event beyond the reasonable control of -?

269. The fact that the Unit was tripped off line was beyond the reasonable control

of - as:

a. The test results at the time of the rewind and the reports received from the

consultants gave no indication that the stator windings were in need of any

repair or remediation;

b. The information at the time was that the Uprate did not require any

rewinding, and

c. The Uprate did not require the DGSH relay settings be changed

270. The length of time it took to investigate the problem and carry out repairs was

beyond the reasonable control of - as they were required to act in accordance with

GOP.

271. The Event was a HILP event and was beyond the reasonable control of - and

constituted a Force Majeure.

(c) The Settlement Periods

272. In order to reduce the Settlement Periods, it would be necessary to find - in breach

of its obligations under Article 14.2 to “… exercise all reasonable efforts to

74

mitigate or limit the effect of the event of Force Majeure.” While the outage was

long, based on the evidence presented, we cannot say - breached this obligation.

IX DECISION

273. We answer the questions posited by the parties as follows: a. Was the Event a HILP Event under the PPA?

Answer: Yes.

b. Was the Event a Force Majeure event under the PPA?

Answer: Yes.

c. If the Event was an event of Force Majeure, for what Settlement Periods

is - entitled to Force Majeure relief?

Answer: The Settlement Periods are from 4:00 p.m. on March 5, 2013 until 10

p.m. on October 6, 2013.

274. To answer the specific claim for relief in the Claimant’s Statement of Position (at

paragraph 128(a)), we find that SAIPus = 0 from 4 p.m. on March 5 to 10 p.m. on

October 6, 2013 (the Settlement Period) for the purposes of calculating

Availability Incentives under Schedule D to the K PPA.

275. The Panel will remained seized of the following issues if the parties are unable to

reach agreement:

a. The monetary consequences of the Panel's award,

b. The need for a formal declaration that the - is required to pay - the

Capacity Payments during the Settlement Period, and

c. Costs.

75

Dated at Calgary, November 14, 2016

_____________________ ________________________

James H. Smellie Doak Bishop

______________________

J. Brian Casey