20200731Reid Direct.pdf

DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY AND GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
141I E. MISSION AVENUE
P.O.BOX3727
SPOKANE,WASHINGTON 99220
PHONE: (s09) 495-4316, FAx: (s09) 49s-88s1
RECEIVED
2020 July 31, PM 3:05
IDAIIO PUBLIC
UTIUTIES COMMISSION
BEFORE TIIE IDAIIO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE POWER COST
ADruSTMENT (PCA) ANNUAL RATE
ADJUSTMENT FILING OF AVISTA
CORPORATION
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CASE NO. AVrJ-E-20-Olt
DIRECT TESTIMONY OF
SCOTT C. REID
FOR AVISTA CORPORATION
I LINITryIJSN
2 Q. Please stste your name, business address, and present position with Avista
3 Corporrtion.
4 A. My name is Scott C. Reid. My business address is 1411 E. Mission Avenue,
5 Spokane, Washinglon, and I am employed by the Company as a Wholesale Marketing Manager
6 in the Energy Resources deparunent.
7 Q. What is your educational background?
8 A. I am a 1988 graduate ofthe University of Puget Sound with a Bachelor of Arts
9 in Business Administration. I obtained a Master of Business Administration from the
10 University of Oregon in 1996.
ll a. How long have you been employed by the Company and whst are your
12 duties as a Wholesale Marketing Manager?
13 A. I started working for Avista in 1998 as a Business Analyst. After eight years in
14 the Financial Planning and Analysis deparhnent and three years in the Regulatory Affairs
15 department, I joined the Energy Resources departrnent in 2009. My primary responsibilities
16 focus on analytical and decision support for Energy Resources' operations.
17 a. Have you previously filed testimony in annual Power Cost Adjustment
18 proceedings?
19 A. No, I have not. This is the first filing where I am sponsoring testimony. William
20 G. Johnson, who previously filed testimony in these proceedings, will retire effective August
21 1,2020.
22 a. What is the scope of your testimony in this proceeding?
23 A. My testimony gives an overview of power supply operations and provides a
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I summary of the factors contributing to the power cost deferrals during the July 2019 through
2 June 2020 review period (review period).
3 Q. Are other witnesses sponsoring testimony on behalf of Avista?
4 A. Yes. Company witness Ms. Brandon provides testimony conceming the
5 monthly accounting entries and account balances related to the Power Cost Adjustment for the
6 twelve-months ended June 30,2020.
7 Q. Are you sponsoring any work papers and supporting documentation to be
8 introduced in this proceeding?
9 A. Yes. Detailed work papers supporting the tables and other calculations in my
l0 testimony have been provided in electronic format to the Commission, and other parties
I I coincident to this filing. The Company has also provided supporting documentation, including
12 details of all term natural gas and electricity transactions that flowed during the review period,
13 and daily position reports that show, among other things, forward price curves. Copies of long-
14 term power contracts that the Company entered into during the review period have also been
15 provided.
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17 II. OVERVIEW OF POWER SUPPLY OPERATIONS
18 a. How does Avista, generally, manage its power supply resources?
19 A. Avista Utilities conducts electric planning, procurement, sales and power
20 resource management activities to ensure an adequate supply of electricity to serve customer
2l and other load obligations, as well as to optimize our generation and transmission resources.
22 As one can imagine, numerous variables affect Short-Term power supply. As such we employ
23 the Energy Resources Risk Policy to recognize and actively manage the interaction and
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I d),namics among these variables by establishing processes for future load and obligation
2 estimation, resource estimation, and management ofthe expected net surplus or deficit Short-
3 Term position.
4 It is understood that many factors cause loads to differ from estimates. It is also
5 understood that each of Avista's generating resources has inherent variability because of
6 streamflow and water storage conditions (for hydroelectric plants), mechanical limitations,
7 transmission constraints, fuel availability and conditions, ambient conditions, environmental
8 and permit conditions and other factors.
9 The Energy Resources deparftnent, ofwhich I am a member of, is responsible for fuel
10 management, optimizing the use of electric resources including wholesale power contracts,
11 obtaining and dispatching power r€sources to meet load obligations and provide good
12 stewardship of electric resources.
13 Energy resource planning involves a number of estimates. Actual loads rarely match
14 forward estimates precisely. The net surplus or deficit requires constant attention and its
15 variability dictates that flexibility be maintained at all times. It is necessary to buy and sell
16 energy (or financially equivalent derivative transactions) in hourly, daily, monthly and longer
17 increments, and adjust dispatch plans to meet prevailing conditions. As such, we may use any
18 electricity and fuel transactions that are authorized in our Risk Policy to the extent that they
19 relate directly or indirectly to serving Avista Utilities electric loads or obligations and
20 optimizing the value of Avista Utilities energy resources.
21 0. What types of transactions will Avista enter itr to, as detailed and
22 authorized in the Company's Risk Policy?
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I A. The following are example types of transactions permitted in the context of
2 managing Avista's energy resources and serving the Company's obligations in the Short-Term
3 and Immediate-Term time horizons:
o Scheduling and dispatching energy resource facilities owned or controlled by
Avista.
o Transactions with other parties for physical delivery ofcapacity or energy, including
fixed price and indexed or formuia priced transactions.
r Ancillary services, such as reserves, load-following, generation imbalance and
others.. Transportation, transmission, storage and capacity obligations and rights.
r Bilateral forward transactions with approved counterparties.. Futures contracts traded on an established commodities exchange.. Swap agreements as a tool for fixed price financial hedges.
r Transactions that allow Avista Utilities to buy or sell electricity or natural gas at
Avista's discretion.
o Exchange agreements (forward commodity agreements expected to be settled with
retum of the commodity rather than cash, either with or without associated
settlement prices).
. Fuel (supply, delivery, storage, excess fuel disposition) related to specific electric
generating facilities in which Avista Utilities has an ownership or contractual
interest including natural gas, coal and biomass (wood waste) and related ernission
allowances.r Streamflow and water storage rights and benefits related to Avista Utilities owned
or contracted hydroelectric generation stations including coordination of the related
river systems.
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a. How does Avista optimize its energy resources for the benelit of its
customers?
A. Avista optimizes its energy resources in a number of ways. Electric resource
optimization involves choices among several variables. We assess these variables to select and
execute an appropriate mix for Short-Term and Intermediate-Term objectives. Intra-month
activity during the prompt montl to serve loads, optimize resotuces, and participate in the
electric market is reported after-the-fact in the daily position report. Electric optimization
variables include:
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Scheduling and dispatching of available Avista's generating units as indicated by
relevant plant parameters.
Buying fuel to operate a generating facility or selling fuel already available to
decrease or eliminate generation fiom a unit.
Storing or using water for hydroeleckic generation that maximizes expected
generation value and arranging for water from or for other hydroelectric plants in
the coordinated river system.
Buying or selling or exchanging electricity in the wholesale market from/to other
utilities, power marketers, or independent power producers, including displacing
purchases and sales available to the Avista Utilities balancing area.
Bufng or selling financial contracts that hedge electric purchase or sale prices and
open positions.
Obtaining transmission rights as may be needed to deliver or receive output to or
from any Avista generation source or any market and selling surplus transmission
rights.
Bufng and selling the gas basis spread based on gas Eansport contract rights.
a, Does the Company have an active hedging program?
A. Yes. The Company employs a Power Supply Hedge Requirements Report tool
(PSHRR). The PSHRR is an analyical tool to guide power supply hedging decisions in the
Short-Term forward period. It provides a process to systematically reduce open positions with
forward transactions by buying for expected shortages and selling expected surpluses. An
"open" position for this purpose is the forecasted monthly financial position that is not covered
by frxed price physical or financial transactions, i.e., the surplus or deficit that is subject to price
risk. The plan provides guidance, but may not be followed rigidly when management judgrnent
or market conditions warrant other actions, no action, or simply a delay in taking action.
III. SUMMARY OF DEFERRED POWER SUPPLY COSTS
a. What were the changes in power costs during the PCA review period?
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A. During the review period actual net power costs wero higher thm the authorized
net power costs for tie Idaho jurisdiction by $ I , I 53,94 I . After taking into consideration the
90% allowable deferral perpent, the total is $1,038,548.
a. Please summarize why actuel power eupply expetrse was lower than the
authorlzed level durlng the revlew period?
A. Table No. I below shows the primary factors impacting power supply expense
during the review period:
Table No. l:
1 Chanee in Hydto Generatiolt
2 Charge in Gas Cienetation md Natural Gas Prices
3 Charge in Colship & Kettle Falls Geneiatim and Fuel Expense
4 Cbmge in Net Power hrchase Expcnr
5 Cbange in Net Transmissiom Expense (E:rpcnse - Revenue)
6 Chage in Palouse Wind PPA Net Expens€
7 Chmgp in Retail Loads (Power Cost Chmge less Retail Revenue Adj)
8 Chmge in Misc Expense
Actud minlrs Authot'lred
@ 90% Alhwed
$ 2,511,587
(5,W7200)
323,694
398,21s
(931,77s)
4,960133
7,135
(118.148)
1,r53,%l
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a, Heage describe the contribufon of esch item thowl above in Teble No' I to
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the incrcsre ln net powcr oupply expenses.
I A. Provided below is a summary ofthe factors that, added together, resulted in an
2 increase in power supply expenses for the review period (the "ltem" number references back to
3 Table No. l):
4 ltem No. I Chanse in Hydro Generulion ($2.611.587 surcharse directiod. One factor
5 increasing power supply expense was reduced hydro generation of 48 aMW below the
6 authorized level. Hydro generation at Company-owned plants accounted for the majority of
7 the variance at 46 aMW, with the remaining 2 aMW variance attributed to lower than authorized
8 generation from the Mid-Columbia contracted hydro plants. Hydro generation is weather
9 dependent and diffrcult to predict.
10 Item No. 2 Chanoe in Gas Generation and Natural Gas Prices (56-097-200 rehate
ll directio . Lower nafural gas prices and increased revenue from gas-fired generation resulted
in the largest cost reduction ($6.1 million) of any of the items when compared to authorized.
Gas-fired plants generated 33 aMW more than authorized, resulting in $4.3 million (Idaho
allocation) of increased revenue fiom sales at the Mid-Columbia ("Mid-C") electricity trading
hub. The increased generation necessitated more natural gas purchases, yet overall commodity
expense was lower than authorized by $1.6 million because of lower than authorized natural
gas prices.
The AECO natural gas trading hub continued to experience low prices during the review
period caused by over-supply conditions partly due to reduced demand from the eastem United
States. Prices at the Malin natural gas trading hub remained relatively higher, so Avista was
able to capture the price spreads between AECO and Malin by utilizing its firm natural gas
transportation contracts to purchase natural gas at a low price at AECO, and sell nanrral gas
into the higher-priced Malin market, thereby locking in a favorable benefit for our customers.
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As a result, the effective average transacted natural gas cost was $ 1.72ldekatherm compared to
$ 1.92ldekatherm in authorized expense.
Item No. 3 Chanse in Colstrio and Kettle Falk Generation ($323.694 surcharse
directio . The change in the value of Colstrip and Kettle Falls is a function of the change in
generation multiplied by the market price of power, netted against the change in fuel expense'
The value of Kettle Falls was $25,171 higher than the authorized level (rebate direction), and
the value of Colstrip was $348,864 lower than the authorized level (surcharge direction), for a
net surcharge of$323,694. Kettle Falls goterated 2 aMW above the authorized level Colstrip
generated 8 aMW below the authorized level.
Item No. 4 Chanee in Net Power Purchase Exoense: (8398.215 surcharse dfuectio .
This category is a function ofthe authorized level of short-term purchases and sales times the
difference in actual versus authorized market prices, plus any incidental changes in contract
expenses not related to changes in generation. Effectively, when Avista was a net buyer, power
prices deviated from the authorized prices to a greater degree than prices deviated from the
authorized level when Avista was a net seller.
Item No.5 Chanpe in Net nsmtsslan tfi9i1 / /, rehatc-iitortion\. Net
transmission expense was below the authorized level primarily due to higher third-party
hansmission revenues. Transmission expense was slightly lower than the authorized leve[ and
third-pafiy transmission revenue was much higher than the authorized level. Third-party
transmission revenues result from increased purchases or sales from other regional entities
utilizing our transmission system. Fluctuations in short-term transmission sales are partially a
function ofother utilities' load/resource balance and whether they are sellers or buyers'
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Item No. 6 Chanpe in Palouse Wind Net (54-960-433 s tcharpe dircetiont
2 Because the Palouse Wind power purchase agreement is not included in base rates in Idaho, the
3 increase in net expense in the PCA is a function of the actual hourly generation of the plant
4 times the contract price offset by the hourly market value ofthe power generated. For the year,
5 Palouse Wind generated 38.8 aMW. The market value of the generation was less than the
6 powerpurchase expense, resulting ina surcharge direction impact ofthe Palouse Wind contract.
7 Ium No. 7 Chanse in Retail Loads ($7.135 surcharse direction). The impact ofthe
8 change in retail loads is the net ofthe deviatiofl in actual load versus the authorized level times
9 the market price of power netted against the retail revenue adjustment. For the review period,
l0 ldaho retail sales were 2 aMW below the authorized level. In periods when load and retail sales
1 I were lower (primarily July and December), prices were higher than the Load Change
12 Adjustment Rate, which increased expense. Additional information regarding the tnad Change
l3 Adjustment Rate has been provided later in my testimony.
t4 Item No. I Chanee in Misc Exoense (8118.148 rebate direaio . Miscellaneous
t5 Expense consists of broker fees, California Independent System Operator (CAISO) fees, and
the Montana lnvasive Species expenses. Broker fees and CAISO fees, which are tracked in the
PCA but not included in authorized base rates, totale.d $165,808 in the surcharge direction.
Montana Invasive Species expenses, tracked in the PCA but not included in authorized base
rates until December 2019 (Case No. AW-E-19-04), exceeded authorized by $670,943 in the
surcharge direction. Finally, REC Revenue was higher than authorized, for a rebate of
$ 1,168,098. I
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I This is inclusive of Clearwater Paper RECS sold to a third party in which Clearwater Paper receives 90 percent
ofthe net proceeds and th€ remaining l0 percent is included as REC revenue in the PCA.
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Summam, Power supply expense was higher than the authorized level by $ I ,l 53,941
(Idaho allocation). The increase in power supply expense was primarily due to Palouse Wind
net expense and reduced hydro generation, offset by lower AECO gas acquisition prices,
increased gas-fred generation, and lower than authorizod net transmission expenses. The
Company is providing work papers supporting all impacts listed in Table No. I and described
in more detail above.
TV. NEW LONG.TER]I{ CONTRACTS ENTERE,D INTO DURING REVIEW
PERIOD
O. Please provide a brief description of new long-term contracts that the
Company entered into during tle review period.
A. The Company entered into five long-terrn power purchase PURPA contracts
during the review period. In October 2019, the Company renewed a contract for the purchase
of the Upriver hydroelectric facility ouput owned by the City of Spokane. In December 2019,
the Company renewed a contract for the purchase ofthe Stimson wood-fired facility output in
Plummer Idaho. In March 2020, the Company renewed two hydroelectric purchase contracts,
one with Meyers Falls and the other with Sheep Creek. In May 2020, the Company originated
a contract for the purchase of the SIERR rooftop solar facility output in downtown Spokane.
Copies ofthese contracts have been provided in monthly ERM reports.
V. SUPPORTING I}OCUMENTATI ON
a. Please provide a brief overview of the documentation provided by the
Company in this filing.
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A. The Company maintains a number of documents that record relevant factors
considered at the time ofa transaction. The following is a list ofdocuments that are maintained
and that have been provided in electronic format with ttris filing:
r Natural Gas/Electric Transaction Records These documents record the key details of
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the price, terms and conditions of a transaction. As part of Avista's workpapers
accompanfng this filing the Company has provided a confidential worksheet showing
each natural gas and electric term (balance of the month or longer) transaction during
the review period, including all key transaction details such as trade date, delivery
period, price, volume and counter-party. Additional information can be provided, upon
request, for any ofthese transactions.
Position Reoorts: These daily reports for each kading day in the review period provide
a summary oftransactions and plant generation and the Company's net average system
position in future periods. The Daily Position Reports also contain forward electric and
natural gas prices.
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16 }.I. OVERVIEW OF' I)CALCULATIONS
17 a. Please provide an overview ofthe deferral calculation methodology.
A. Energy cost deferrals under the PCA are calculated each month by subtracting
base net power supply expense from actual net power supply expense to determine the change
in net power supply expense. The base levels for the review period result fiom the power supply
revenues and expenses approved by the Commission in Case No. AVU-E-17-01 for July 2019
through November 2019, and in Case No. AVU-E-19-04 for December 2019 through June
2020. The methodology compares the actual and base amounts each month in FERC accounts
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1 555 (Purchased Power), 501 (Thermal Fuel), 547 (Fuel) and 447 (Sales for Resale) to compute
2 the change in power supply expense. These four FERC accounts comprise the Company's
3 major power supply cost/rwenue accounts. The ERM also includes changes in Accounts 565
4 (transmission expense), and 456 (third-party transmission revenue).
5 In addition, actual expense and revenue for natural gas not bumed is included as natural
6 gas sale revenue under Account 456 (revenue) and purchase expense under Account 557
7 (expense). This would include benefits and costs related to optimizing the value ofnatural gas
8 turbines and power supply's natural gas transportation contracts. All expenses are recorded in
9 accordance with Generally Accepted Accounting Principles and FERC's Uniform System of
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11 The total change in net expense under the ERM is multiplied by Idaho's share of the
12 Production/Transmission Ratio (PT Ratio) approved in association with base net power supply
13 expense. Change in Idaho retail sales is then multiplied by the Load Change Adjustment Rate
14 (LCAR) and added or subtracted from the change in power supply expense to calculate the total
15 power expense change. 90 percent of the change in power expense is defened and 10 percent
l6 is retained by the Company.
17 a. Please explain how the load change adjustment is calculated in the PCA'
l8 A. The PCA includes a load change adjustment to reflect the change in power
l9 production and transmission expense recovered through base retail revenues, related to changes
20 in retail load. The Load Change Adjustment Rate calculation is based on the energy classified
2l production and transmission costs included in the Company's general rate case. The LCAR
22 revenue adjustment for July through November 2019 was $24.84/MWh and $22.00/MWh
23 beginning December 2019.
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1 The monthly load change adjusfrnent in the PCA is computed by multiplying the retail
2 revenue adjustnent rate times the difference between actual and authorized monttrly retail
3 Megawatt-hour sales. If actual Megawatt-hour sales are greater than base, the retail revenue
4 adjustrnent will rezult in a credit to the PCA deferral (reduces power supply costs). If actual
5 Megawatt-hour sales are less than base, the retail revenue adjustment will result in a debit to
6 the PCA deferral (increases power supply costs).
7 Q. Does that conclude your pre-filed direct testimony?
8 A. Yes.
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