HomeMy WebLinkAbout20010809Lord Direct.pdf1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
Q. Please state your name, by whom you are
employed and business address.
A. My name is Thomas J. Lord. I am employed by
Teknecon Energy Risk Advisors, LLC (TERA). My business
address is 1515 South Capital of Texas Highway, Austin,
Texas 78746.
Q. What position do you hold with TERA?
A. I hold the position of Partner.
Q. Please describe your experience relevant to
this testimony?
A.I have been involved, as a both consultant
and employee, in the development and deployment of
energy risk management systems. This experience
includes direct responsibility for assessing,
transacting, and managing speculative energy positions
utilizing both physical and financial transactions. It
also includes guidance for the creation of “best
practice” risk policies, procedures and processes for
investor-owned utilities and major consumers of
electricity. An additional description of my industry
experience and educational qualifications is attached.
Q. What is the purpose of your testimony?
A.The purpose of my testimony is to discuss the
requisite internal skills necessary for Idaho Power
Company (IPC) to assure price risk management
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
capabilities for its customers, potential mitigation of
speculative risks for Idaho Power affiliates due to
contractual relationships with Idaho Power, and
recommended actions to assure Idaho Power receives
appropriate value and rewards from its affiliate
relationships whenever Idaho Power receives
transactional assistance or provides internal demand
and supply information.
Q.Please summarize the scope of your testimony.
A. I will testify as to my understanding of
Idaho Power’s ability to manage forward hedging of
wholesale energy price risks. I will also testify as
to my understanding of certain past practices and
transactional patterns that have created or may have
created value for Idaho Power affiliates without
appropriate compensation to the regulated customers.
Finally, I will recommend changes that Idaho Power
should adopt to both contractual relationships with
affiliates and internal practices that will improve
business processes and risk/reward allocation between
Idaho Power and its affiliates.
Q. IPC testimony (Gale prefiled direct testimony
Case No. IPC-E-01-16, pg 4, line 12) indicates that
long-term (time periods beyond 30 days in the future)
hedging activities may not be performed by IPC in the
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
future. In your opinion, is hedging an appropriate
activity for a regulated utility to pursue on behalf of
its customers to prudently manage the supply of energy
to its customers?
A. Regulated utility customers implicitly depend
upon the utility provider to make decisions to manage
the cost of energy for their consumption. Wholesale
energy market price fluctuations, due to internal supply
excesses or shortfalls, make the risk of price changes
for energy purchases or sales on behalf of the customers
significant to individual customers. While hedging
decisions are dependent upon a variety of
considerations, the failure to make those decisions
implicitly exposes the utility consumer to the
equivalent of unmanaged speculation.
My opinion, therefore, is that a utility must
possess the capabilities to determine whether the risk
exposure of its customers to future price movements is,
in the utility’s best opinion, acceptable. The
complete reliance upon spot pricing for open market
transactions is, implicitly, a speculative decision to
accept complete exposure to wholesale market price
volatility. Only when a regulated utility has
responsibly implemented the internal systems necessary
to make and execute hedging, or price risk management
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
determinations on behalf of its customers, can it
remove this implicit speculative risk.
Q. Why isn’t the power cost adjustment an
effective hedge against price movement?
A. A power cost adjustment (“PCA”) mechanism
only acts to moderate the rate of change of customer
prices by averaging price movements from one year and
applying them to the next year’s customer rates. It
does not, however, remove the risk of adverse price
movements. Over time the PCA guarantees the customer
will pay average cost of the market prices. The PCA
does not remove customer exposure to systemic adverse
price movements that are created by the variable nature
of customer energy consumption patterns. Therefore,
the PCA is not an effective hedging mechanism.
Q. What is an effective method of reducing
customer exposure to price movements?
A.The only method of reducing customer exposure
to wholesale price movements is to secure a source of
energy which possesses, in some manner, an element of
certainty concerning the price of the energy at time of
delivery. In contrast, purchasing at “market price” at
the time of delivery assures that the energy consumer
will be a price taker at the time of purchase. In any
wholesale market, a price taker is fully exposed to the
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
ability of suppliers to extract value from the
production of the good. In electricity, the wholesale
market is perceived as inefficient and subject to the
ability of suppliers to extract significant economic
value for prompt delivery of energy.
It is possible that price risk management
activities may result in higher consumer energy costs
than relying on spot price purchases for all wholesale
energy needs. However, the risk of unmoderated price
movements and subsequent abrupt changes in annual
prices may be unacceptable to many or all customers.
Previously, I discussed the implicit
speculation accepted by the decision not to implement
price risk management decisions. The possibility of
resultant higher energy prices is the risk accepted
from the reward of a smaller range of potential pricing
outcomes that results from hedging activities. It is
this reduction in the range of potential outcomes that
reduces the risk of the utility consumer.
Therefore, I believe that captive customers
should be provided some mechanism by which the
customers can opt to be protected from wholesale market
price volatility. Price risk management, or hedging,
is the logical method of providing that mechanism.
Historically, regulated utility customers
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
have depended upon their service provider and
regulators to insulate them from wholesale energy
markets, either by making long-term market purchases or
by constructing generation assets. In the evolving
deregulated wholesale energy markets, the forward
energy prices will be the factor that determines the
advisability of the “build versus buy” decision. The
ability to analyze forward market prices and make the
correct “build versus buy” decision is a fundamental
component of the capability to provide price risk
management services to regulated utility customers.
Q.What types of organizations possess these
Price Risk Management skill sets?
A.The speculative activities pursued by Idaho
Power affiliates revolve around exactly these skill
sets. Speculative transactions that are not based on
analysis of forward market prices, the underlying
fundamental production costs of the marketplace and a
perception of market supply/demand balances, are
essentially decisions to place bets without
justification for returns. I believe IdaCorp to be a
fundamentally well managed organization that would not
place its corporate well being at risk for unresearched
“gambles.” Therefore, I believe that IdaCorp possesses
these skill sets internally.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
These skill sets are contained in affiliates
of Idaho Power Company. The specific affiliates that I
have identified are:
· IDACORP Energy Solutions, LP (“IES”)
· IdaWest
The second component of the skills necessary
to provide price risk management services for regulated
customers is the ability to calculate exposures to
forward market price movements arising from a customer
consumption pattern. It is my understanding that the
existing computer hardware and software systems and
supporting staff skills were transferred from IPC to
IES under the IPC-IES services agreement. It is also
my understanding that IdaCorp and IES portrayed to
Staff and customers at workshops discussing the IPC-IES
services agreement that these resources would still be
utilized for regulated customer purposes after the
transfer. The responses to staff data requests (see
Exhibit 107) indicate that IES has implemented a number
of “best practice” risk management practices.
Therefore, I believe that IdaCorp’s subsidiaries,
though possibly not within IPC, have created and
possesses the skills necessary for this component of
price risk management services.
The third component of price risk management
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
is the creation of fundamentally sound internal
policies, procedures and processes for the price risk
management decision, market transaction execution and
processing functions. I have been unable, at this
time, to determine the complete nature of the IdaCorp
policies and procedures and processes. However, I
believe that the IPC policies, procedures, and
processes that have been provided for my review prior
to this testimony, are not sufficient to assure that
IPC decisions to accept or reject long-term
transactions for price risk management purposes – or
for any other purpose – are made in a consistent and
controlled manner. The lack of policies, procedures,
and processes undermines any assertion by IPC that
price risk management is or is not advisable for the
regulated customers. An absence of these structures
will inherently make price risk management less
consistent and systematized, which frequently results
in an internal perception that hedging activities are
riskier than they may possibly be.
Q. What are the implications of the absence of
certain “best practice” risk management systems for
IPC?
A. This lack of structure also calls into
question any prior decisions made by IPC because there
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
is no clear basis for their decision-making. The
determination of whether a transaction is advisable
depends on three factors: 1) the current prices and
implied volatility of prices in the forward market; 2)
the net exposure of the risk position to price
movements; and 3) the risk tolerance of the entity for
which the price risk decision is being made. I
acknowledge that there is a wide degree of latitude in
what may comprise an acceptable decision based on these
factors. I recommend that the Commission grant IdaCorp
and IPC a significant amount of future discretion
concerning the creation of mechanisms for supporting
the price risk management decision.
Q.What structure do you recommend Idaho Power
create to establish a clear basis for future decision-
making?
A.I recommend that IPC be obligated to create
adequate policies, procedures and process documents to
show a well-grounded understanding of these price risk
management factors. The ability to evaluate
alternatives based on these policies and the capability
to make well documented and consistent price risk
management decisions are critical to facilitating
appropriate regulatory prudency review of the Idaho
Power’s wholesale energy purchases and sales. Failure
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
to adequately implement policies, procedures, and
documentation for risk management decisions will result
in continued questions regarding the Company’s ability
to represent the best interest of its customers. The
alternative could be the creation of alternative
regulatory or market structures necessary to allow IPC
customers the ability to make their own price risk
management decisions. If such alternative structures
were to be implemented, tariffs would need to be
restructured in such a manner as to allow customers to
make such decisions external to IPC purchasing
practices while retaining the ability to rely upon IPC
for the firm supply of energy at market prices. This
could include implementing a service structure where
customers could receive purely spot market priced
energy on a load shaped time of use basis, thereby
allowing the customer to access alternate suppliers for
risk management products.
The documentation that I would expect IPC to
implement in this regard are:
· A clearly stated risk management policy
stating the IPC broad objectives for
energy risk management (such as reduction
in potential volatility of energy
prices).
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
· The delegations of authority and
responsibility within the IPC corporate
structure to develop and implement risk
management structures.
· A clearly stated method for determining
the risk tolerance of IPC on behalf of
its customers, and the metrics to be used
in communicating that tolerance
throughout the risk management and senior
management organization.
· A clearly stated methodology, including
assumptions and recognized areas of
uncertainty, for determining the existing
exposure to forward wholesale energy
market price movements implicit in IPC’s
consumer sales obligations and generation
resources. This methodology should
include the ability to reflect exposure
to the price risk on an hour-by-hour
basis for a determined number of forward
delivery months.
· A clearly stated series of procedures and
processes for determining and executing
hedge strategies and for maintaining and
reporting wholesale market transaction
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
information under that strategy.
Q.What is your understanding of the
relationship between IES and Idaho Power?
A.My understanding, prior to the filing of
testimony by Idaho Power, was that the Company had
transferred its trading and risk management operations
to IES under an Electric Supply Management Services
Agreement (“Agreement”). In return for that transfer
Idaho Power has an obligation to pay IES approximately
$4.8 million per year, which is closely equivalent to
100% of the cost of those operations in the most recent
rate proceeding for Idaho Power. This transfer between
IPC and IES allows IES to participate in the
speculative market, and allows the IdaCorp family of
companies to retain transactional and risk management
skills. Keeping these skill sets within IdaCorp is a
benefit to both the Company and the regulated
customers.
It is my understanding that the retention of
skill sets was a critical component of the rationale
for approving the Agreement. I believe that the
transfer of transactional and risk management skill
sets to IES without retaining access to those skill
sets significantly diminishes Idaho Power’s ability to
function effectively in deregulated wholesale energy
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
markets. Since Idaho Power will be compelled to
participate in those markets due to the fluctuations in
generating capabilities of hydroelectric generation
resources, effective participation in the wholesale
energy market will be critical to Idaho Power’s
regulated customers.
Q. What is your understanding of the current
services provided for Idaho Power by IES?
A. In keeping with the understanding expressed
above, IES is participating in the near, medium, and
long-term markets at the Idaho Power interconnections
to the regional markets. Furthermore, IES is gaining
insights into the market behavior, expected direction
of price movement, and the implied market volatility
expected by the trading community. Speculative trading
necessitates a significant investment in risk
management infrastructure and skills. I believe it was
assumed that IES would make these investments to
protect its speculative positions, while educating
Idaho Power in the process. Because of the $4.8
million dollar cost paid by Idaho Power to IES, it
seems rational Idaho Power should receive constant
advice and education from IES. My understanding is
that Idaho Power would be able to utilize the IES risk
management staff to act on behalf of the regulated
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
customers in fashion similar to what they did while
Idaho Power had the information and systems necessary
to make prudent decisions on behalf of the regulated
customers.
However, from the testimony of witness Gale
in the Commission Case No. IPC-E-01-16 (pg 4 line 12)
and Case Nos. IPC-E-7/11 Hoyd (pg 14 line 4), it
appears that IES may adopt a more restricted view of
these responsibilities under the Agreement. The
testimony indicates that the support provided by IES
may be restricted to the real time and day-ahead
management of the Idaho Power physical deliveries of
energy, the “assurance that system resources are
managed to the benefit of the customers,” and the
provision of certain limited audit information.
Idaho Power should clearly indicate whether
it intends to rely on IES for longer-term price risk
management. If my interpretation of the Gale and
Andersen testimony is correct, the remaining resources
do not appear sufficient for the exercise of prudent
actions by Idaho Power within the wholesale power
market on behalf of the regulated customers without the
skill sets provided by IES.
Q. Do you believe that the current interactions
between Idaho Power and IES provide instances where the
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
risks and rewards are shifted between IPC and IES are
without appropriate customer compensation?
A. Yes. IES has received certain benefits from
the relationship that have, or could have allowed, IES
to transact with lower risk and to shift certain
transactional costs to Idaho Power and its customers.
The specific areas of concern are:
· Prior knowledge of market liquidity
· Credit risks
· Pricing formulae
· Regulatory authorities necessary for IES
to participate in the wholesale energy
market
· Access to generation optionality
Each of these areas will be discussed
separately in the following testimony.
My fundamental premise is that Idaho Power
cannot reduce the risks of IES trading activities
without transferring a benefit to IES that is
unavailable to other market participants, while at the
same time reducing the ability of Idaho Power Company
customers to achieve the most competitive market
pricing for needed resources. Without transaction
specific data, any estimation of whether IES executed
transactions to implement some of the benefits, and the
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
degree to which IES was successful in profiting from
these benefits, would be highly subjective. However,
the fact that such activities could take place without
adequate customer compensation, is only an element of
the consumer cost. As discussed later, an increased
open market transaction costs can arise from market
perception of inter-affiliate advantage. Other
benefits relating to the reduction of internal
transaction or operating costs, such as reduction in
credit risks, could be determined from the cost of
securing such benefits from the open market.
Q. Would it be beneficial for the Idaho Public
Utility Commission to create formalized rules for the
interaction of IES and Idaho Power?
A. No. Any regulatory action that transfers
risk and reward between two entities, be it utility and
consumer or utility and affiliate, creates a
transaction that can be modeled using financial
analysis tools. Companies acting in speculative
wholesale energy markets should have resources to
examine and disassemble financial components to
determine the most profitable actions and extract
maximum benefit from the regulatory transaction.
Frequently, regulatory Staff do not have the training
or resources to perform such analysis.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
Therefore, it can be more efficient and
effective in certain instances for regulatory agencies
to adopt objective-based criteria that sets forth
policies, objectives, and goals. The responsibility
for the creation of specific procedures and processes
to respond to these objectives is most appropriately
left to the Company or group of employees responsible
for daily management of the targeted activities. The
regulatory agency then reviews the specific procedures
and processes to assure their compliance with the
objectives. It is frequently more tenable for the
regulatory agency to perform the necessary review than
to be involved in the micromanagement of financial
concepts.
I have noted previously certain basic “best
practice” risk management structures that should be
implemented by IPC. My recommendation is that the
Commission develop, preferably in consultation with
IPC, the acceptable objective for the IPC risk
management policy – reduction of price volatility or
the management of prices to a “not to exceed” level,
for example – and a complete listing of the types of
metrics and reports that are expected to be available
to the Commission Staff on an annual basis as the
foundation for prudency reviews.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
I have also recommended that Idaho Power be
given the charge to develop price risk management
procedures and processes based on basic policies and
objectives. That is to allow IPC’s discretion in
developing these metrics, in coordination with
Commission Staff, to best utilize IPC’s existing skill
sets. This structure is most likely to create the
necessary alignment of responsibility and authority to
achieve the Commission’s goals.
Q. What is your understanding of the current
pricing for transactions between Idaho Power and IES?
A. My understanding is that the pricing of
transactions beyond the next delivery day is done at
the purchase price. It appears, from Company testimony
(IPC-E-01-16, Gale, pg 4- line 15, “all wholesale
transaction between Idaho Power and IES will be at
market prices” and Gale pg 18 line 2) that no
transactions are done directly between Idaho Power and
IES for periods beyond next day delivery. IES offers
to act as a broker for all such transactions. I have
been unable to determine whether IES charges a
brokerage fee for arranging such transactions or if
such a fee is charged, it is in keeping with normal
brokerage fees charged in the industry.
For day ahead and real time pricing, IES uses
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
a “representative” market price based on either Mid-C
(the Mid-Columbia wholesale market trading hub in
Washington state) or Palo Verde (the California-Nevada
border wholesale market trading hub) market prices.
The pricing is based on the market prices for those
points, not the actual transaction costs of IES for
securing or selling the power.
Any difference between the purchase price and
the representative market price, or transmission
arbitrage obtained or lost by IES, is retained on the
speculative book. Pricing differential and
transmission arbitrage opportunities are addressed in
subsequent portions of my testimony.
Q. What are the trading risks or opportunities
that could be experienced by IES in the management of
Idaho Power service obligations under the Agreement?
A. The manner in which IES interprets the
relationship between Idaho Power and IES significantly
constrains the risks under the Agreement while
retaining a significant number of the advantages.
In regards to the short term (real-time and
day-ahead), Idaho Power represents the largest market
participant for firm energy transactions for power at
the interconnections of Idaho Power with other regional
market participants. IES, by managing the transaction
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
flow, can assure that Idaho Power and IES are not
simultaneously attempting to complete transactions in
periods of limited liquidity. In addition, if IES
perceives that liquidity at certain pricing locations
is constrained, then IES may anticipate that IPC
purchases will have the impact of moving wholesale
market prices in a specific direction.
While this may not impact the pricing at the
representative pricing points, it may have a noticeable
impact on the Idaho border prices. If IES believes its
actions on behalf of Idaho Power could shift the local
prices noticeably from the representative prices, IES
has the opportunity to create lower risk returns.
For example, if IES determines that IPC will
require an additional 500 MW per hour of on-peak power
three days in the future in a market where the maximum
size of on-peak energy trading over the last week was
150 MW per hour, then IES may anticipate that prices
could move higher. By purchasing block power for
future periods in anticipation of this demand, IES may
be able to position itself to capture returns due to
increased market knowledge. This practice has occurred
frequently enough in commodity markets to develop a
name “front running” and to necessitate Commodity
Futures Trading Commission regulations to prohibit this
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
behavior by commodity brokers.
With regard to the long-term markets, IES
again has knowledge prior to all other market
participants of upcoming Idaho Power market activity.
Information given to me indicates that IES is provided
and has participated in load forecasting and other
activities that define the energy purchasing and sales
exposure of Idaho Power. In addition, the audit
requests submitted and responded to in this proceeding
indicate that IES operates whatever risk position
tracking software is utilized by Idaho Power to manage
its wholesale market position. I am concerned about
the existence, or lack thereof, of software security or
firewalls to segregate Idaho Power information from
IES.
Without these firewalls, IES has access to
Idaho Power’s intended market activities and
consequently has an advantage that no other
participants in the Idaho wholesale power market
possess – the understanding of when IES’s speculative
position would be in conflict with future actions that
Idaho Power would be expected to assume in the market.
For example, a speculator in wholesale power would
understand that Idaho Power may at times buy and other
times sell. This participant must be concerned that
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
any speculative position would be impacted by Idaho
Power activities. If a speculator purchased power for
June, only to have Idaho Power soon thereafter
determine it had excess power for the upcoming June and
therefore need to sell power for that period, the
likely result would be that the speculative position
would lose money without other market actions.
Therefore, knowledge of risk exposure and
transaction decisions of Idaho Power prior to other
market participants reduces IES’s speculative risks in
the Idaho region. However, Idaho Power customers
receive no benefits from the risk reduction experienced
by IES.
Q. Do you believe that hedging activity by IPC
could reduce the benefit to IES of access to IPC risk
positions?
A. Yes. Actions by IPC to reduce its wholesale
market price risk are, by their nature, intended to
reduce IPC’s need to transact in the sport market.
This reduction should, in aggregate, reduce IPC’s
competition for short-term market liquidity. Energy
commodity markets generally experience their highest
volatility, and therefore most rapid price changes, in
the delivery month. Prior hedging of risk, by reducing
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
IPC’s delivery month activities, could reduce IES’s
knowledge advantage in the marketplace.
Q. If Idaho Power Company’s purchasing practices
changed from entering into transactions for time
periods beyond thirty days to a practice of entering
into transactions for periods of less than thirty days,
do you believe it would create opportunities for IES to
benefit from lower risk transactions?
A. Yes, I do believe this could create
speculative opportunities for IES at lower risk than
that of other speculative market participants. As
discussed above, knowledge of the activities of
organizations with significant market positions allows
lower risk trading. Any potential change to increase
IPC’s exposure to delivery month prices increases IES’s
knowledge advantage during the period of time when that
advantage has the potential to create greatest
leverage.
Q.How would this occur?
A.In this case IES would receive, through its
assistance in load forecasting to Idaho Power,
knowledge of Idaho Power’s need to purchase or sell
energy in the wholesale market for forward periods for
high, normal, and low water flow scenarios as well as
high, normal, and low demand scenarios. With this
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
information, IES has a forecast of the likelihood that
Idaho Power will have purchasing or sales transactions
during a delivery month. IES can assess the likely
market liquidity during that period, estimate the Idaho
Power impact on market liquidity during that period,
and make appropriate speculative transactions to take
advantage of the likely market price direction during
that period.
This is not to imply that IES, by the nature
of this information, is guaranteed profitable trading
activities. Abnormal and abrupt conditions can occur,
plant outages may take place, and market pressures from
interconnected markets –such as California – may
overwhelm the market balance of the Idaho region. I am
not implying that IES is gaining perfect market
knowledge. However, IES is gaining better market
knowledge than other participants in the region. This
knowledge reduces the risks of speculative activities.
It does not appear that the Idaho Power regulated
customers have been compensated for that risk reduction
in any manner.
Without access to all transactions by IES and
IPC, information as to whether IES was securing
speculative positions to have risk exposures in
opposition to IPC, cannot be determined. Without
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
specific transaction level information for both the
operational and non-operational books as to what the
price movements were from the IES transaction date
until the delivery date, I can not estimate the
magnitude of IES potential gains from this knowledge.
However, it is simple to note that a $10/MWhr movement
for a 100 MW exposure for any given week is $80,000
($10/MWH *100MW * 80 on-peak hours). The price
movements experienced during the later portion of the
PCA year under review in this proceeding were, at
times, orders of magnitude greater. I believe that
this is ample evidence that opportunities did exist for
IES to make substantial profits from the prior
knowledge of Idaho Power purchasing requirements.
Q. What additional benefits do you believe
IdaCorp and its affiliates received from Idaho Power
during last years PCA?
A. IES received its FERC power marketing license
on April 27, 2001. Prior to that time, IES was not
legally authorized to trade wholesale power. IPC
responses to staff data request (see Exhibit 107)
indicate that all transactions on IES’s behalf were
actually entered into by Idaho Power. This implies
that all counterparty credit risk for IES speculative
transactions was actually assumed by Idaho Power. The
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
open market cost of such credit enhancement is normally
between 1-2% of the notional amount, i.e., the total
value of the transaction as determined by multiplying
all volumes for the life of the agreement by the
current pricing under the agreement. This is a cost of
doing business that IES avoided by receiving free
credit enhancement by the regulated customers.
In addition, IES was allowed to enter the
market months earlier than it could have otherwise,
giving IES access to the market volatility of the west
during 2000/2001. Prior to receiving its power
marketer certificate authority from the Federal Energy
Regulatory Commission, it was unlawful for IES to enter
into wholesale energy market transactions as a
principal. Without Idaho Power standing behind all IES
transactions, IES would not have received any profits
prior to April 2001. In addition, IES was also allowed
to build name recognition in the market place months
earlier and will likely be considered part of Idaho
Power for several months into the future, extending its
credit advantage.
Q. Do you believe there are opportunities for
IES to obtain minimal or risk-free profits under the
IPC-IES pricing methodology?
A. Yes, opportunities could exist under the
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
Agreement. In the area of real-time and day-ahead
power purchases for Idaho Power by IES, a strong
possibility exists for transmission arbitrage under the
contract pricing. Arbitrage is an instance where a
discrepancy between two different pricing points exists
such that a transaction can be entered into to capture
the difference as a profit without risk.
My understanding is that transmission
services are transferred to IES at cost. In addition,
power purchased at the Idaho border for Idaho Power by
IES is transferred based on the representative market
locations - not the border price. Since the
transportation price is known, it is possible for IES
to determine whether Idaho border prices are less than
the representative market price plus transmission. If
there is a differential, IES collects that differential
as a profit. This profit is risk-free and is not shared
with the customers.
For example, if for the next day deliveries
of energy the Mid-C wholesale energy market is
transacting at a value of $100/MWhr and the price of
wholesale energy at the Idaho border with Washington
State is $98/MWhr, an arbitrage opportunity would exist
under the pricing formula. As currently utilized, the
formula would price energy at the border at a price
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
equal to the Mid-C price plus approximately $1.25/MWHr
of transmission costs – or $101.25/MWhr. Purchasing
energy delivered at the border could occur at a cost of
$98/MWhr without requiring any purchase at Mid-C. The
difference between the price under the formula -
$101.25/MWhr – and the market price - $98/MWhr – would
be retained by IES and would have required no risk by
IES on the transaction.
Another area of potential rewards to IES that
is not solely dependant upon the contract pricing
mechanism is the creation of speculative positions in
anticipation of Idaho Power open market transactions.
If IES, through its participation in load forecasting
and management of Idaho Power’s risk position
information, has knowledge that Idaho Power will have
the need for significant day-ahead and real-time
purchases, IES can enter into speculative transactions
that reflect Idaho Power’s future needs. For example,
if IES has knowledge that Idaho Power will require
significant energy purchases for on-peak periods during
the next week, IES can take speculative positions to
purchase power during that delivery period prior to the
execution of the power purchase for Idaho Power. While
it is possible that weather or other conditions will
remove that need, IES actions will be made with
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
knowledge:
· of the projected buying or sales needs of
the largest firm energy market
participant at the interconnections of
Idaho Power with other regional market
participants,
· that IES will know before any other
market participant if those needs shift,
· that IES will view all market transaction
structures of Idaho Power, and
· that if IES sells power to Idaho Power at
values above the IES purchase price, IES
will receive a benefit.
Q. Can there be additional costs to Idaho Power
customers from the IES relationship?
A. Yes. If the other market participants that
might transact with Idaho Power perceive that Idaho
Power, either explicitly or implicitly, favors IES in
its transactions, then there is a significant risk that
these market participants may decide to withdraw from
the business of providing energy to Idaho Power.
Another central premise of deregulated markets is that
an open and freely contested market is necessary for
efficient market pricing. If the Idaho Power-IES
relationship reduces the willingness of third parties
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
to participate actively in the wholesale market for
energy at the border of the IPC system, inefficient
pricing may occur. This inefficiency may occur during
any time period – real-time to multi-year forward
periods – that the market lacks an adequate number of
participants. These inefficiencies reduce market
liquidity and increase prices. Since Idaho Power’s
regulated customers are paying market prices, they will
pay more as a result of decreased liquidity.
Several of my recommendations have dealt with
the access to internal Idaho Power data by IES prior to
other market participants. While the major reason for
my recommendations have been to reduce IES’s ability to
decrease its own risk on speculative transactions in
relation to other market participants, the potential
reduction in market liquidity and the negative impact
on Idaho Power customers if the market loses
participants should not be ignored.
Q. Are there additional possible benefits that
IES may receive from its relationship that current
audit information may be unable to identify?
A. I believe there are additional risk reducing
or risk transferring transactions that would be
impossible to identify without access to all trading
information for IdaCorp and its affiliates. I am not
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
stating such transactions have or have not occurred,
only that information necessary to make a determination
is not available at this time.
The transaction types referred to above
relate to the nature of generation assets as a real
option transaction. Generation facilities, in
financial engineering terms, constitute a series of
options that can be exercised on an hourly, daily,
weekly, or monthly basis. Since the generation owner
has the right but not the obligation to utilize the
generation asset, in financial engineering terms this
would be considered owning the option of being “long”.
The owner of an option has the ability, using
financial formulae such as the Black-Scholes option
model, to determine the efficient hedge ratio for sales
of production against the option to produce output.
Financial theory can illustrate that the constant
readjustment of this efficient hedging ratio has the
effect of allowing risk-free monitization of the
production optionality. The only residual risk is that
market price movement, or volatility, will not occur
and the cost of acquiring the option, the fixed
carrying costs of the asset, will not be recovered.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
However, in the case of Idaho Power and IES,
the fixed carrying costs of the generation assets are
recovered through regulated rates. If, and I stress
that to my knowledge the information necessary to
perform the analysis has not been made available to
either myself or IPUC Staff, IES were to transact
knowing that Idaho Power generation assets would have
excess power to sell in the future, it could be
possible for IES to utilize those assets to form the
basis for this type of transaction. This type of
trading would serve to reduce the risk of IES while
providing potentially profitable trading activities.
Q. What might be the appropriate relationship
between IES and Idaho Power?
A. I believe that the definition of appropriate
or inappropriate relationships depends upon the
alignment of economic interests between Idaho Power and
IES. For example, I believe that IES possesses
significant market knowledge that would be very
beneficial to the regulated customers if they can
access it in a nondiscriminatory manner.
One way to assure that Idaho Power regulated
customers receive that benefit would be for IES and
Idaho Power to adopt a corporate policy that, within
the acceptable risk tolerance for regulated customers,
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
IES and Idaho Power would always share congruent market
views in the region. For example, if IES believes that
it is in its best interest to own speculative positions
in power for the next June, Idaho Power would assure
that it has minimized, to the extent feasible, its
exposure to upward price movements for the same period.
In this manner, Idaho Power would receive the benefit
of IES’s market knowledge and counsel on appropriate
prudent risk management decisions.
In addition, a mechanism for assuring an
allocation of transactions entered into during periods
of inadequate liquidity could be created. For example,
if IPC has requested IES to broker a wholesale
transaction to buy energy for a period in which IES is
also attempting to purchase energy, an allocation of
percentages of requested volumes might be made in
instances where total desired volumes cannot be
contracted for at the requested prices. In this
manner, IPC customers could be assured that IES does
not gain an advantage by preferring its own transaction
needs over those of the customers.
Q.What alternative measure could be required if
their practices are not adopted?
A.I believe that a failure to adopt “best
practice” risk management systems by IPC and a failure
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
to structure the interrelationship between IPC and its
affiliates may necessitate Commission action to assure
customer protection. As noted previously, those
actions could encompass imposition of innovative tariff
structures. Other potential actions to assure customer
protection could include a complete severance of all
transactional and informational ties between IPC and
any affiliates, a requirement for transfer of all risk
management and execution actions to a third party
supplier, or the resumption of forced customer access
to the profits obtained by IPC affiliates in the
wholesale market. I believe that some or all of these
measures may be counterproductive to the long term
interests of both Idacorp and its regulated customers.
However, a failure to appropriate and effectively
manage IPC’s price risk and its affiliate relationships
would be adequate justification for Commission
exploration of alternative measures to protect the
regulated customer’s interests.
Q. Staff has recommended that IES be compensated
at the lower of IES’s actual cost of purchasing power
for consumption or the market price of energy at the
“representative price” under the IPC-IES agreement at
time of consumption for purchases for Idaho Power
regulated customers. Staff has also recommended that
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
Idaho Power be compensated at the higher of IES’s
actual cost of revenues for sale or the market price of
energy at the time of delivery of sales of power by
Idaho Power. Do you agree with these recommendations?
A. Yes, the IPUC Staff has identified one of the
potential flaws in transfer pricing mechanisms – the
ability to create risk arbitrage between two locations.
Under the current pricing system, IES has the
opportunity to determine whether power purchased at the
IPC interconnections with other transmission systems is
priced at a different value than that represented under
the IPC-IES contract price of Mid-C market price plus
the tariff costs of transmission to the IPC system from
that point.
If the cost of wholesale power at the IPC
border is less than the IPC-IES reference price for
real-time or day-ahead power, the difference is
retained by IES. However, IES has taken no risk to
obtain that value. Rather, that value is implicit in
the IPC customer load and physical assets. Prior to
implementation of the pricing structure of this
Agreement, risk-free trades were passed on to the
ratepayers for their benefit. As such, I agree with
Staff that the existing pricing structure under the
IPC-IES contract should be modified to assure that the
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
risk-free arbitrage is captured as a customer benefit.
I believe that transfer-pricing mechanisms,
in general, are a flawed business structure. Because
open market prices are dynamic and a transfer-pricing
mechanism requires a more static viewpoint, potential
arbitrage of the transfer price for one party’s benefit
will always occur. In organizational structures where
inter-departmental cost flows have no overall impact on
shareholder value, these inefficiencies may not be
fatal. However, in this instance, where inefficiencies
may either lead to regulated customer subsidization of
non-regulated profits or to non-regulated activities
supporting regulated customer costs, the use of
transfer pricing becomes problematic.
The Staff position recognizes the fundamental
concern of transfer pricing between two organizations
with differing economic incentives by allocating all
risks to one entity and all potential reward to
another. While the Staff position clarifies the
situation, it is not a sustainable relationship because
there would be no economic benefit to IES.
I recommend one of two solutions to this
problem: either IES must create an internal resource
set that trades the Idaho Power real-time and day-ahead
obligations without communication with the IES
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
speculative trading activities or Idaho Power should
determine whether outsource real-time and day-ahead
transaction and risk management could be obtained for
less than the $4.8 million dollar per year cost charged
by IES. In the first case the result would be very
similar to the relationship in place prior to
implementation of the Agreement, with IES maintaining a
regulated and non-regulated trading group. In the
second case, the information flow would cease to the
speculative group.
Since Idaho Power audit request response (see
Exhibit 107) indicates that no long-term hedging is
undertaken by IES on IPC’s behalf except at the RMC’s
direction, either change would only need to impact the
real-time and day-ahead trading.
In addition, since IES and other affiliates
of Idaho Power are speculative market competitors with
Idaho Power for market liquidity, I recommend that, in
the interest of assuring equitable market rules, the
Commission consider ordering:
1. Any IES Staff in contact with Idaho Power
risk management position reports, load
forecasting and risk decision analytics
be precluded from discussing such
information with any person who is
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
engaged in or who has contact with
persons engaged in IES speculative
activities; and
2. All Idaho Power risk position, load
forecasting and risk decision analytics
information be maintained in a secure
information system to which IES Staff
members can gain access only by specific
written permission from Idaho Power Staff
; and
3. No Idaho Power Staff engaged in
supporting or making risk management
decisions be allowed to hold a position
of financial responsibility in IES;
4. Idaho Power must act to obtain market
pricing information, market liquidity
information and to execute trades for
risk management purposes while treating
IES as a third-party competitor; and
5. All conversations between Idaho Power
risk management Staff and IES Staff must
occur on telephone lines possessing
recording capabilities and all tapes must
be maintained until after the final
determination of a Power Cost Adjustment
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
or similar cost recovery proceeding for
the period of time pertaining to the
conversations has been entered and is no
longer subject to appeal; and
6. No members of the Ida-West or other
IdaCorp purely merchant subsidiaries be
allowed access to any IPC customer,
market forecast, load forecast or risk
management information.
The first five conditions should be met for
as long as the IES-Idaho Power contract is in effect.
The sixth condition should be a prerequisite for any
IdaCorp merchant activities that are not in whole or
part designed to provide services for the IPC regulated
customers under Commission regulation.
Q. You have recommended that Idaho Power be
required to develop price risk management policies,
procedures and processes for submission to the
Commission. Why is it more appropriate for Idaho Power
to develop these procedures than it would be for the
Commission?
A. TERA has been involved in many engagements
devoted to assisting investor owned utilities,
municipal utilities and energy consumers in developing
price risk management policies, procedures and
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
processes. While there is significant literature
describing industry “best practices” in this area, the
reality is that no single “off the shelf” control
framework is correct for any entity. The best practice
for any organization differs depending on internal
Staff skills; the ability to implement and utilize
complex software systems and the cost versus benefits
of said systems for specific applications; the
wholesale power market that is being accessed; the
liquidity, variety and sophistication of trading
products available in that market; and the desire of
the organization to utilize personnel or computer
resources to provide certain data flow management and
security functions. This matrix of varying abilities,
needs and resource allocation decisions can not be
managed externally, as would be the case if the IPUC
imposed price risk management policies, procedures and
processes upon Idaho Power. Therefore, I believe that
the only organization that can appropriately determine
Idaho Power’s best practice price risk management
policies, procedures and processes is Idaho Power.
However, it is possible for an external party
to review an organization’s policies, procedures and
processes to perform a “gap” analysis to assure that
adequate safeguards are in place. I do believe that it
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
is appropriate for the Commission to request that the
price risk management policies, procedures and
processes of Idaho Power be submitted for review and
comment. In this manner, the regulated customers are
assured that the entity responsible for oversight of
Idaho Power actions on their behalf has agreed that
Idaho Power has implemented the appropriate controls,
allocated adequate resources and will provide the
information necessary for legislated regulatory
oversight.
I believe that Idaho Power should be offered
significant latitude and discretion in the drafting and
implementation of price risk management systems. The
Company is best positioned to know its strengths and
weaknesses. Development and review of the price risk
management system should be a collaborative, rather
than confrontational, process. However, certain
fundamental issues need to be addressed to assure that
the Idaho Power implementation decisions reflect the
understandings reached by Idaho Power, IPUC Staff and
Idaho Power customers during the refinement of the
Idaho Power – IES contract. These issues include:
· differentiation of IES and Idaho Power
data,
· protection of Idaho Power customers from
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
IPC-E-01-7/11/16 LORD, T.(Di)
07/20/01 TERA
IES arbitrage opportunities,
· consistency of Idaho Power analysis and
actions, and
· access of Idaho Power to IES skill sets
My opinion is that, in this manner, the fair
and equitable guidelines for prudent price risk
management actions by Idaho Power can be achieved.
Furthermore, that subsequent PCA discussions can be
based upon responses to Idaho Power internal management
systems rather than concern over fundamental questions
concerning the relationship between Idaho Power and its
affiliates.
Q. Does this conclude your testimony?
A. Yes